Protection of Synchronous Generators

PROTECTION OF SYNCHRONOUS GENERATORS

Sture Lindahl

ABB Network Partner AB

II Protection of Synchronous Generators

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III

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Preface

Generally, the power stations represent about 50% of the capital cost in a power supply system. The power generator itself plays an important role in the energy conversion process in the power station. A generator has more failure modes than any other component in the power system. The generator protection system must detect the faults rapidly. Otherwise, there is a risk that the power generating unit will suffer a protracted forced outage. In some nuclear power stations, there are a spare rotor, a spare stator or both. Usually, there is no spare generator. This means that a generator failure will cause a forced outage of the entire power generating unit. Such outages will cause a substantial increase of the costs for power generation.

The ambition, to protect the generator against all faults, results in ad-vanced protection and monitoring systems. There is, however, considerable divergence in opinion on the extent of generator protection systems. It is important that the protection system detects fault that may hurt humans and damage equipment. Most power systems tolerate the disconnection of one generating unit without running into serious problems. A fault on another power system component may cause the generator protection system to op-erate non-selectively. Such an unwanted operation may cause a blackout of the power system or the disconnection of customers.

In this document, we discuss generator faults and abnormal conditions. We also describe several aspects of the generator protection system.

My intent has been to compile a document that can serve as an intro-duction and a background to further studies. I have presupposed that the reader has some knowledge in power system engineering. I plan to use the document in further education courses. The intended readers are power sys-tem operators and protection engineers. I hope that design engineers in the power industry will find the document useful as a background.

As a former teacher in automatic control, I am aware of the importance of feedback. I encourage all readers to let me know of errors, misunderstandings and suggestions for improvement.

IV Preface

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V

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Contents 1. Introduction

2. Synchronous Machines

3. Generator Faults

4. Fault Statistics

5. Background

6. Differential Protection

7. Underimpedance Protection

8. Overcurrent Protection

9. Interturn Fault Protection

10. Protection Against Open Circuits

11. Stator Earth-Fault Protection

12. Field Earth-Fault Protection

13. Underexcitation Protection

14. Overvoltage Protection

15. Reverse Power Protection

16. Unbalance Protection

17. Out of Step Protection

18. Abnormal Frequency Protection

19. Inadvertent Energising Protection

20. Bearing Current Protection

21. Breaker Failure Protection

22. Operational Experience

VI Contents

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1.1

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1. INTRODUCTION

Generally, the power stations represent about 50% of the capital cost in a power supply system. The power generator itself plays an important role in the energy conversion process in the power station. A generator has more failure modes than any other component in the power system. The generator protection system must detect the faults rapidly. Otherwise, there is a risk that the power generating unit will suffer a protracted forced outage. In some nuclear power stations, there are a spare rotor, a spare stator or both. Usually, there is no spare generator. This means that a generator failure will cause a forced outage of the entire power generating unit. Such outages will cause a substantial increase of the costs for power generation. It is very important that the protection system detects all faults that may hurt humans and damage equipment. This means that the generator protection system must have a high degree of dependability. It is high if the probability of not having a failure to operate is high.

Most power systems tolerate the disconnection of one generating unit, one power transformer, one power line or one busbar section without running into serious problems. A fault on adjacent power system component may cause the generator protection system to operate non-selectively. Such an unwanted operation may cause a blackout of the power system or the disconnection of customers. The generator protection system must have a high degree of security. It is high if the ability of not having an unwanted operation is high.

All protection systems must have a high degree of dependability and a high degree of security. We say that a protection system has a high degree of reliability if the ability of not having an incorrect operation is high. The reliability is the combined ability of not having a failure to operate and of not having an unwanted operation.

The ambition to protect the generator against all faults results in advanced protection and monitoring systems. There is, however, considerable divergence in opinion on the extent of generator protection systems.

To reduce the operating costs for the power generation, utilities reduced their staff and many power stations are unmanned. To avoid increased risks for damage to such unmanned power station it is necessary to equip these power stations with advanced protection systems and remote control systems. Depending on the size (cost) and importance for the power supply we place different demands on the protection system. In hydro power stations with only one generating unit and in nuclear power stations, the protection systems have to meet the most stringent requirements. In

1.2 Introduction

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hydro power stations with several small generating units, we may simplify the protection systems. Such protection systems have to satisfy the legal requirements but no other requirements.

Protection systems in pumped storage hydro plants require many special considerations because of the many modes of operation. They include (1) generation, (2) pumping, (3) synchronous compensation prepared for generation and (4) synchronous compensation prepared for pumping. One special problem is to maintain the correct current direction in reversible pumped storage units.

In the mid 1960's, many utilities introduced electronic control equipment in power stations. After accumulating sufficient experience concerning reliability, maintainability and disturbance immunity, they also introduced static protection equipment. Electronic protection equipment has shorter operate times, better earthquake safety and does not need as much panel space as older electromechanical protection equipment. The introduction of electronic protection equipment made it possible to introduce more sophisticated protection functions. Now, we seldom install new electromechanical protections.

Microcomputer based measurement and control equipment has been used for several years. In the early 1980's, computer based protections became available. In the late 1980's, complete integrated protection system using digital signal processing techniques become commercially available.

1.1 Voltage Classes

It is convenient to use abbreviations for intervals of system voltages. The abbreviations LV, MV, HV, EHV and UHV are common. To avoid misunderstandings, we give our definition in Table 1. Table 1 Classes of system voltages and their designation.

Description Designation System voltage kV Low Voltage LV -1 Medium Voltage MV 1-99 High Voltage HV 100-344 Extra High Voltage EHV 345-999 Ultra High Voltage UHV 1 000-

Introduction 1.3

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1.2 General Demands

The general demands on the protection system are based upon some risk analysis, experience and tradition. The legal requirements give the minimum demands. Further demands must be motivated by reduced disturbance and repair costs. Commonly, it is required that earth faults, short circuits and other severe faults must be detected by two independent protections. The fault must be cleared even if one switching device fails to operate. The generator protection system must also provide adequate back-up protection for (1) the associated buswork, (2) the station auxiliary transformer, (3) the magnetisation transformer, (4) the generator step up transformer, (5) the busbar on the high voltage side of the step up transformer and (6) the power lines that start at the power station. A fundamental requirement is that the operate time must be as short as possible. However, we have to consider the risk for unwanted operation, the cost for the protection system and the costs associated with the damages.

This document describes several protections that may belong to the complete generator protection system. The descriptions are brief and tutorial. To simplify further studies, we have included references to relevant original publications. Many manufacturers can provide more detailed information concerning their products.

Often, the generator and the step up transformer are protected by common equipment. This means that is can be difficult to give a sharp distinction between the generator protections and the transformer protections. This document contains some aspects on transformer protection and back-up protection. There are many mechanical and thermal protection devices that help to avoid damage to the power generating unit. We have not included these devices in this document. Instead, we have concentrated on the protection equipment with electrical energising signals.

1.4 Introduction

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2.1

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2. SYNCHRONOUS MACHINES

A synchronous machine is not a simple device. The armature, or stator, winding is arranged in three symmetrical phase belts in slots in the stator surface. The magnetic field intensity can be controlled via the DC current in the rotor, or field, winding. A synchronous machine can operate as a generator or as a motor. In our case, generator operation is the most common operating mode. When the synchronous machine operates as a generator, a prime mover drives the rotor. The prime mover can be a diesel engine, a gas turbine, a hydro turbine or a steam turbine. A synchronous generator may operate alone with a single load or in parallel with other generators on a large power system.

2.1 The Development of the Synchronous Generator

The frequency of the EMF in a synchronous generator is:

f = np60

( 1 )

where n = the rotational speed in revolutions per minute [rpm], and p = the number of pole pairs.

The three-phase currents in the stator winding generate a rotating magnetic field. During steady-state conditions, this field is stationary to the rotor and its field. This explains the term synchronous machine.

Some synchronous machines have a round or cylindrical rotors. Other machines have salient pole rotors. In the round rotor case, the field winding lies in slots cut axially along the rotor the rotor length. The diameter of a round rotor is small and usually in the order of 100 centimetres. Such a round rotor is suitable for operation at high speeds driven by a gas turbine or a steam turbine. Therefore, it is known as the turbo-generator. When the prime mover operates at a low speed, the rotor may have a larger diameter.

2.2 Synchronous Machines

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The capacity of a synchronous generator is:

S n D LBA2≈ ( 2 )

where n = the rotational speed [rpm], D = the diameter of the rotor [m], L = the length of the rotor [m], B = the magnetic flux density in the air-gap [T], and A = the linear current density on the rotor [A/m].

The rotational speed is given by ( 1 ). In a 60 Hz system the highest rotational speed is 3 600 rpm and in a 50 Hz system the highest speed is 3 000 rpm.

The diameter of the rotor is limited by the centrifugal forces and the stresses in the retaining ring. Despite of the rapid development of materials, it is not possible to increase the diameter beyond 1.3 m for a generator with a rated speed of 3 000 rpm. Corresponding figure is 1.2 metres for a generator with a rated speed of 3 600 rpm. It is possible to increase the diameter to 1.8 metres for generators with four poles.

The length of the rotor is limited by the critical speed and the risk for high vibration amplitudes. Usually, the ratio L/D must not exceed 6-7.

There is no hope that it should be possible to a higher magnetic flux density in the air-gap than 1.2 T.

Our remaining hope is the linear current density. Better cooling of the rotor winding and the stator winding makes it possible to increase the capacity of synchronous generators.

2.2 The Development of the Hydro-Generator

The synchronous machine possesses a wide range of characteristics and special features. They make complete protection difficult. We will review these conditions before we discuss the detailed application of protection equipment.

Figure 1 shows the maximum capacity in MVA of hydro-generators in Sweden.

In 1938, the maximum capacity was 40 MVA and increased to 500 MVA in 1980. During these 42 years, the average rate of increase is more than 6% per year.

Synchronous Machines 2.3

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HYDRO-GENERATORS IN SWEDEN

Rat

ed A

ppar

ent P

ower

[MV

A]

Year

1900 1920 1940 1960 1980 20000

100

200

300

400

500

600

Juktan G1

Harsprånget G5

Ritsem G1

Porjus G11Seitevare G1

Stornorrfors G1Harsprånget G1

Hjälta G1Torpshammar G1

Hojum G1Stadsforsen G1

Figure 1 Maximum capacity of hydro-generators in Sweden.

2.3 The Development of the Turbo-Generator

In 1901, C.E. Brown patented the turbo-generator with a cylindrical rotor. The first generator of this type had a rated voltage of 2 kV, a rated power of 250 kVA and a rated speed of 3 900 rpm that corresponding to a rated fre-quency of 65 Hz. The increasing demand of electricity has led to a very rapid increase of the maximum rated capacity of power generating units. Now, the rated power of the largest turbo-generators for 50 Hz is 1185 MVA for a ma-chine with two-poles and 1640 MVA for a machine with four poles. Figure 2 shows how the maximum capacity depends on the cooling method.


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0

500

1000

1500

2000

Air Hydrogen Water/Hydrogen Water

Turbo-Generator Size (50 Hz)Influence of Cooling Method

MVA

200

850

1200

1640

Figure 2 Maximum rated capacity of turbo-generators.

Figure 3 shows the maximum size of turbo-generating units in Sweden.

1900 1920 1940 1960 1980 20000

250

500

750

1000

1250

Year

Net

act

ive

pow

er [M

W]

Stenungsund 1 & 2

Stenungsund 3 & 4Karlshamn 1, 2 & 3

Oskarshamn 1

Oskarshamn 2

Ringhals 2Ringhals 3 & 4

Forsmark 3 & Oskarshamn 3*)

*) Increase of maximum capacity in existing power plants Figure 3 The development of turbo-generating units in Sweden.

In 1959, Swedish State Power Board commissioned the turbo-generating unit Stenungsund 1 with two radial steam turbines and two axial steam tur-


GENPC020.DOC 2007-05-22 15.24

bines. This means that the unit has two generators with a rated capacity of 25.3 MVA and two generators with a rated capacity of 68.8 MVA. The total rated capacity is 188.2 MVA. In 1985, Oskarshamns Kraftgrupp AB commissioned the nuclear unit Oskarshamn 3 with one turbo-generator. It has a rated capacity of 1 294 MVA. During these 26 years, the average rate of increase is about 12% per year.

2.4 Power Station Configuration

The use of uniform and standardised generator protection is one way of achieving a high degree of reliability. By doing so, we can reduce the design errors. A uniform design of the protection system eases the testing, management and maintenance.

Varying power station configurations obstruct the use of a uniform and standardised generator protection system. The most important factor is the varying power station configuration. Figures 2.2-2.5 show the most common configurations of power stations.

Figure 4 Unit-connected generators without generator breakers.


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Figure 5 Unit-connected generators with generator breakers.

Figure 6 Generators connected to common step-up transformers.


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Figure 7 Generators connected to a common generator busbar.

Besides the varying power station configuration, following factors influence the design of the generator protection system: • generator circuit-breaker or not • earthing of the neutral • location of voltage transformers • location of current transformers

2.5 Asynchronous Operation

Synchronous operation is the desired mode of operation for most synchro-nous machines. There are, however, incidents that may cause sustained loss of synchronism or transient loss of synchronism. Generally, loss of synchronism is an abnormal mode of operation for synchronous machines.

Consider a synchronous generator connected to a strong power sys-tem. Now, let us assume that the field circuit-breaker receives an opening impulse. Then, the breaker will disconnect the exciter from the field wind-ing. The inductance of the field winding will cause a gradual decrease of the field current. It will fall as the discharge resistor absorbs the energy stored in the field winding. Eventually, the loss of excitation will cause a sustained loss of synchronism.

After this, the synchronous machine will operate as an induction ma-chine and it will run above synchronous speed. It will continue to generate power and the setting of the turbine governor will determine the amount of


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power generated. Slip frequency current will flow in several paths in the ro-tor. The field winding may form such a path. Another path is the damper winding of a salient pole machine. The current will also flow in slot wedges and the solid rotor body.

When the machine operates as an induction generator, the external power network will provide the necessary excitation. This means that the machine will absorb much reactive power. The reactive current may ap-proach or even exceed the rated current of the machine.

In [ 1 ], Mason and co-authors describe a series of asynchronous running tests. The test object was a 588 MVA turbo-generator equipped with special temperature-measuring devices on both the stator and rotor. Below, we reproduce some results presented in [ 1 ].

Table 1 Ratings of generators referred to in [ 1 ].

Generator Sn Pn Vn In MVA MW kV kA

A 558 500 22.0 15.437 B 37.5 30 11.8 1.835 C 75 60 11.8 3.67 D 75 60 11.8 3.67 E 150 120 13.8 6.27 F 150 120 13.8 6.27 G 133 120 13.8 5.585 H 75 60 11.8 3.67 I 37.5 30 11 1.97 J 56 45 11.8 2.75


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0.0 0.2 0.4 0.6 0.8 1.00.0

0.1

0.2

0.3

0.4

0.5

0.6

Active Power, P/S [pu]

Slip

, s

[%]

ASYNCHRONOUS OPERATION

Figure 8 Slip during asynchronous operation.

0.0 0.2 0.4 0.6 0.8 1.00.0

0.2

0.4

0.6

0.8

1.0

1.2ASYNCHRONOUS OPERATION

In-Phase Component of Stator Current [pu]

Stat

or C

urre

nt [

pu]

Qua

drat

ure

Cop

onen

t of

Figure 9 Reactive current during asynchronous operation.


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Reference

[ 1 ] Mason, T.H., Fairney.W., Arnold, J.J. & Thelwell, M.J.:"Asynchronous operation of turbo-generators", Report 11-02,CIGRE-Session, Paris, 1972.

3.1

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3. GENERATOR FAULTS

The protection of synchronous generators involves the consideration of more possible faults and abnormal conditions than the protection of any other power system component. When designing the protection system we have to consider (1) stator faults, (2) rotor faults and (3) abnormal operating conditions.

3.1 Stator Faults

Damage to the stator winding itself or its insulation may cause stator short-circuits or stator earth-faults.

3.1.1 Stator Short-circuits

Ageing, overvoltage, overcurrent or loss of cooling may cause stator short-circuits. External short-circuits, improper synchronisation and loss of synchronism may cause large currents. These currents cause high forces that may displace the stator winding and by that an internal short-circuit.

An external short-circuit is accompanied by very large fault-currents. The electromechanical forces increase considerably when the size of the generator increases. The size of the electromechanical forces may amount to more than 100 N/cm at sudden short-circuits. Generally, the utilities require that synchronous generators shall withstand, without damage, all types of short-circuit on the generator terminals.

Short-circuits clear of earth are less common faults. They may occur on the end portion of the stator coils. They may also occur in the slots if there are two coils in the same slot. In the latter case the fault will involve earth in a very short time. The short-circuit currents do not depend on the generator neutral earthing principle.

Generally, thermal power units commissioned during the last 30 years have phase-segregated generator buswork. Such a design reduces considerably the risk for two-phase and three-phase short-circuits close to the generator terminals.

3.1.2 Stator Earth-faults

Pohl has investigated how the earth-fault current damages the sheets of a synchronous machine. In [ 2 ], he describes the result of tests with three different insulating materials between the stator sheets, two different values of the earth-fault current and four values of the fault clearance times.


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Figure 1 shows the number of stator sheets that melt together because of an earth-fault. We can see how the damage caused by the earth fault current may increase with the fault clearance time. Table 1 shows how to interpret the legend in the figure.

0

50

100

150

4 sec 1 min 10 min 60 min

Sheets Melted Together

Legend

Fault Clearance Time

# SM 2 A

SM 5 A

CM 2 A

CM 5 A

M 2 A

M 5 A

Figure 1 Damage caused by the earth fault current.

Table 1 Insulation material and fault clearance time.

Legend Insulation Material Fault Current A SM 2 A Schellackmikafolium 2 SM 5 A Schellackmikafolium 5 CM 2 A Kompoundmikafolium 2 CM 5 A Kompoundmikafolium 5 M 2 A Mikanit in Plattenform 2 M 5 A Mikanit in Plattenform 5

3.2 Rotor Faults

The field circuit of a synchronous generator consists of the rotor winding proper and associated circuits. These may include the slip rings and brushes, the field circuit-breaker, the armature of a rotating exciter or the rectifier and the secondary winding of the magnetisation transformer in a static exciter. This circuit is an isolated DC circuit and it is not necessary to


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earth it. Generally, the field circuit of modern generators is operated unearthed. Earth-faults, interturn faults and open circuits may occur in the field circuit. Overexcitation or unbalanced loading may overheat the rotor itself.

3.3 Abnormal Operating Conditions

Let us consider a single synchronous generator or a group of synchronous generators connected to a power system by a single-circuit power line. The line may have several sections and intermediate substations. Now, we assume that one line circuit-breaker, either in the power station or in one of the substations, opens inadvertently. We have to consider the risk that the automatic voltage regulator (AVR) does not operate correctly. The excitation may also be under manual control. In such cases there is a risk that we subject our customers to both overfrequency and overvoltage. There may be legal requirements that make it necessary to disconnect the generator in such cases.

A failure in the automatic voltage regulator (AVR) or the excitation system may reduce or even interrupt the excitation current. We say that loss-of-excitation has occurred. When a synchronous generator loses excitation it operates as an induction generator running above synchronous speed. The generator starts to draw reactive power from the network. The wattless current produces the main flux in the machine. The machine will continue to generate active power. The load setting and speed droop of the turbine governor determine the value of the power generation. Turbo-generators are not suited for such operation because they do not have damper windings and will quickly overheat from the induced currents in the rotor iron.

Let us consider a synchronous generator that is operating in synchronism with a power system. Now, we assume that the generator loses its driving force, e.g. due to an inadvertent closing of the stop valves in a steam turbine or the wicket gates in a hydro turbine. The generator remains in synchronism with the power system and continues to run as a synchronous motor. The synchronous machine draws sufficient power from the power system to drive the prime mover. Such motoring does not damage the generator but may damage the prime mover. Especially steam turbines may be damaged by overheating if the steam flow ceases.

Unsymmetrical faults may produce more severe heating of the synchronous generator than symmetrical faults or balanced loading. External unsymmetrical faults may be either series faults or shunt faults. Such faults cause unbalanced loading of the synchronous generator. The


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negative sequence currents that flow during these unbalanced faults induce voltages in the rotor of the generator. The frequency of these voltages is 2fn where fn is the power frequency. The induced voltages cause rotor currents that tend to flow on the surface of the rotor forging and in the non-magnetic rotor wedges and retaining rings. The resulting losses quickly raise the temperature. If the abnormal condition persists, the metal will melt, damaging the rotor structure.

There are [ 1 ] four potential sources of shaft voltages on generator shafts (1) the generation of a shaft voltage by an asymmetrical generator airgap or stator field which links with the rotor shaft, (2) the capacitive cou-pling of the excitation control system with the shaft, (3) the shaft voltages generated by charge separation in the latter stages of the steam turbine and (4) the stresses of the turbine stationary and rotating blades/nozzles or buckets cause the blades to become magnetised by magnetostriction, which on rotation, generates a small AC voltage across the turbine. It is common practice to earth the shaft at one location. The contact between the hydro turbine and the water column prevents charging of the shaft. Usually, turbo-generators have earthing brushes at the turbine end of the generator. It is common practice to earth the shaft at only one point to avoid circulating currents. The remote bearings are insulated from earth. If this insulation deteriorates, induced shaft voltages may be high enough to penetrate the oil film in the bearing and some current starts to flow. The current causes pitting of the bearing surfaces. Essentially, pitting continues until the bearing loses its low coefficient of friction, the friction losses increase, the bearing surface breaks up and the surface is wiped. Generally, a bearing will be damaged within second if the shaft current is higher than 2 A.

References

[ 1 ] Buckley, G.W., Corkins, R.J. & Stephens, R.N.: "TheImportance of Grounding Brushes to the Safe Operation of LargeTurbine Generators", IEEE Trans. on Energy Conversion, vol. 3,no. 3, pp. 607-612, September, 1988.

[ 2 ] Pohl, R.: "Eisenverbrennung durch Lichtbögen niedriger Strom-stärke", AEG Mitteilungen, vol. 20, no. 1, pp. 36-41, January,1930.

4.1

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4. FAULT STATISTICS

It is an advantage to know the failure rate, the type of failures and the causes of failures when we design the protection system for a power system. Sometimes, it is a necessary condition for the design of a cost-effective protection system to have such fault statistics available. There is, however, limited information on generator faults.

This section contains a review of the available sources. It also con-tains a compilation of failure rates for synchronous machines. The rate of external faults and system abnormalities depends on the power system. We do not have the ambition to discuss these rates here. It is believed that the material allows us to carry out simple probabilistic risk analyses. We have to be careful when using the results of the analysis. One should not assume that the calculated results have better accuracy than a factor of two.

4.1 Concepts and Definitions

Vetter [ 7 ] discuses the definitions that RWE in Germany used to collect fault data. Unfortunately the paper does not contain numerical values of the failure rate for synchronous generators.

In 1979, CIGRE Study Committee 11 (Rotating Machines) formed a Working Group, WG 11.08 Reliability (of rotating machines). The goals of the working group included: 1) to examine, review and recommend reliability definitions, 2) to examine data collection systems, 3) to collect statistical operating data on reliability, 4) to recommend ways to improve the collection and analysis of reliability data.

Manufacturers have expressed their concern that the reports give in-sufficient details and that the data often have poor quality. The manufactur-ers have also claimed that the data have a bias towards the users. The data do not recognise the contributions of operator errors. Working Group 11-08 has concluded [ 1 ] that manufacturers cannot expect to obtain enough de-tails concerning the root causes from operating statistics to permit them to improve specific design features. However, there should be sufficient infor-mation for them to identify weak components and frequent failure modes.

It is a fact that the average unavailability and forced outage rate of the generators from year to year, even when a large sample size is involved. Also, a few of the infrequent but serious faults dominate the statistics. For these reasons, lifetime statistics or ten year averages are considered more valuable than annual reports.

CIGRE WG38-03 has compiled an Application Guide [ 2 ] on Power System Reliability Analysis. It contains a wealth of information about reli-

4.2 Fault Statistics

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ability concepts and methods. There are also some examples of reliability data in the Application Guide [ 2 ]. These data do, however, not allow us to estimate the failure rate of synchronous generators and, especially not, how often generator protection systems have to operate.

4.2 The failure rate of turbo-generators

This section contains some data about failure rates for turbo-generators.

4.2.1 CIGRE-Questionnaires 1976-1985

In reference [ 1 ], Jeffreys summarises the results of several CIGRE-ques-tionnaires. Figure 1 reproduces some of his reliability data.

0

10

20

30

40

50

Canada France India Sweden UK USA

MTTF for Turbo-GeneratorsCIGRÉ 1989

Hou

rs*1

000

Figure 1 Mean Time To Failure for turbo-generators.

We can estimate the failure rate at 42 faults/(generators, years) for the turbo-generators in France, UK and USA.

Table 1 reproduces a breakdown [ 1 ] of the number of faults and the repair time for turbo-generators by major components.

About 50% of the faults and the repair time are faults that the genera-tor protection system has to detect. This means that the failure rate is close to 20 faults/(100 generators, year) when we consider only electrical faults.

Fault Statistics 4.3

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Table 1 Breakdown of turbo-generator reliability.

Component Repair Time Number of Events % % Field winding 21 6 Rotor and attachments 17 4 Stator winding 19 5 Stator core and frame 5 1 Auxiliary systems 23 38 Excitation and brushgear 7 32 Miscellaneous 8 14 Total 100 100

4.2.2 BBC

Kramer and Reinhard [ 3 ] describe the system that BBC used to collect fault data for steam turbines and turbo-generators. The paper contains only limited information on failure rates for turbo-generators. Table 2 gives the availability and forced outage rate (FOR) for turbo-generators. The data represents five calendar years, 1968-72.

Table 2 Failure statistics for turbo-generators, 1968-72.

Rated Power Service Time Availability FOR MVA h % % 175 207 569 97.9 0.3 350 109 918 97.3 0.08

Table 3 gives availability for turbo-generators. The data base contains faults from the commissioning year and up to and including 1972. No data are older than 15 years.

Table 3 Failure statistics for turbo-generators, -1972.

Rated Power Service Time Availability MVA h % 175 544 417 96.3 350 116 626 96.5

The total exposure corresponds to a service time of 75 generator-years.


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4.2.3 Sweden

A working group [ 11 ] in Sweden has compiled some failure data for turbo-generators in nuclear power stations. The data base comprises data from four nuclear power stations: Barsebäck, Forsmark, Oskarshamn and Ringhals. Table 4 comprises a summary of the data base. Table 4 Faults on turbo-generators in Sweden.

Unit From To Ng Ny Nf λ year year # gen.y # %/y

Barsebäck 1 1975 1990 1 16 1 6.25 Barsebäck 2 1977 1990 1 14 2 14.29 Forsmark 1 1980 1990 2 22 0 0.00 Forsmark 2 1980 1990 2 22 1 4.55 Forsmark 3 1985 1990 1 6 0 0.00 Oskarshamn 1 1972 1990 2 38 3 7.89 Oskarshamn 2 1974 1990 1 17 0 0.00 Oskarshamn 3 1985 1990 1 6 0 0.00 Ringhals 1 1977 1990 2 28 3 10.71 Ringhals 2 1977 1990 2 28 4 14.29 Ringhals 3 1981 1990 2 20 0 0.00 Ringhals 4 1983 1990 2 16 0 0.00 All Units 1972 1990 19 233 14 6.01

Table 4 shows that the total exposure is 19 turbo-generators, 233 generator-years. The longest individual exposure is from 1972 to 1990. The data base contains 14 generator faults. This means that the average failure rate is 14x100/233 = 6 faults/(100 generators, year).

The working group used the data base to find out the most common type of generator fault. Figure 2 shows the relative frequency (%) of turbo-generator faults in the 12 Swedish nuclear units.

The number of earth-faults in the stator is high, 28.6% of all turbo-generator faults. This motivates a reliable and sensitive earth-fault protection system that trips the generator with only a short time-delay.

It is surprising that the number of faults involving loss-of-field is so high. In Sweden, the risk for voltage collapse sets the transfer limits of the Trunkline network. The reactive absorption will increase to more than 50% of the rated capacity of the synchronous generator after the loss-of-field. Such an increase of the reactive loading may be a severe contingency when


GENPC040.DOC 2007-05-22 15.25

operating close to the voltage collapse limit. These facts and the high rela-tive failure rate underline the importance of protection against loss-of-field.

0

10

20

30

40

50

S. short-c. S. earth-f. R. short-c. R. earth-f. Loss-of-f.

Generator faults 1972-1990Sweden, 233 generator-years

%

14.3

28.6

14.3

7.1

35.7

Figure 2 Types of turbo-generator faults in Sweden.

4.2.4 Allianz Versicherungs-AG

References [ 4 ] and [ 5 ] contain data that are useful when analysing the risks associated with turbo-generator faults. The author presented the mate-rial at two forums in München arranged by the insurance company Allianz Versicherungs-AG.

Unfortunately, references [ 4 ] and [ 5 ] contain any data on absolute failure rates. According to [ 4 ] the number of rotor faults is 80% higher than the number of stator faults. The costs associated with rotor damages are 70% higher than the costs associated with stator damages.

Figure 3 shows a breakdown [ 5 ] of the stator damages according to the cause and the type of faults. The hatched bars show the percentage of the costs associated with the fault type. The full bars show the percentage of the number of stator damages.

Figure 3 shows that the costs associated with electrical faults on the stator winding are considerably larger than the relative number of faults. Reference [ 5 ] does not give the distribution of earth-faults and interturn faults. The data show the importance of fast and reliable protection against stator earth-faults and stator short-circuits.


GENPC040.DOC 2007-05-22 15.25

0

10

20

30

40

50

60

A B C D

Stator DamagesAllianz Versicherungs-AG, 1969-75

Legend%

Cost

Number

A) Earth-faults and Interturn Faults B) Abnormal Current ForcesC) Testing of Windings D) Miscellaneous

Figure 3 Relative cost and number of stator damage.

Reference [ 5 ] does also contain data on rotor damages. Figure 4 shows a breakdown by causes and types of damages. The hatched bars show the percentage of the costs, associated with the faults that the insurance company has to compensate for. The full bars show the percentage of the number of rotor damages that the owner has reported to the insurance company.

0

10

20

30

40

50

60

A B C D

Rotor DamagesAllianz Versicherungs-AG, 1969-1975

Legend

%

Cost

Number

A) Interturn Faults, Winding Breaks and Double Earth-Faults B) RetainingRing and End Regions C) Series Faults D) Miscellaneous

Figure 4 Types of rotor damages.


GENPC040.DOC 2007-05-22 15.25

Figure 4 shows that the costs associated with electrical faults are consider-able higher than the relative number of faults. It is not very surprising that the retaining rings and the end regions of the rotor represent a considerable share of the costs associated with the rotor damages. The data emphasises the importance of fast and reliable rotor earth-fault protections and loss-of-excitation protections.

4.3 The Failure Rate of Hydro-Generators

This section contains some data about failure rates for turbo-generators.

4.3.1 CIGRE-Questionnaires 1976-1985

In reference [ 1 ], Jeffreys summarises the results of several CIGRE-ques-tionnaires. Table 5 and Table 6 reproduce some of his reliability data.

Table 5 Reliability records for hydro-generators.

Country Sn Exposure

Forced Outage Time

Sche-duled

Outage Time

Mean Time Between Failures

Mean Time To Repair

MVA Unit-years

h h h h

Brazil 10-100 118 2,316 21 -"- >100 224 3,592 45 Canada1 All 3,054 52 11,217 67 -"- All 732 52 14 3,970 82 -"- 10-100 54 25 54 -"- >100 12 40 36 Germany >100 144 144 154 113,880 1,880 Japan A 12 7,111 26 -"- B 80 16,926 11 -"- D 1,012 50,211 12 -"- E 60 26,364 4 -"- G 192 3,756 41

1) Canada has only scheduled outage time in second line in summary. 2) Only major outages.


GENPC040.DOC 2007-05-22 15.25

Table 6 Reliability records for hydro-generators (contd.).

Country Sn Exposure

Forced Outage Time

Sche-duled

Outage Time

Mean Time Between Failures

Mean Time To Repair

MVA Unit-years

h h h h

Norway 10-100 1,615 16 92,467 166 -"- >100 210 58 39,991 263 Sweden 10-100 888 11 40,941 53 -"- >100 181 63 16,868 121 Switzerland 10-100 48 12 608 20,148 72 USA All 1,353 51 189 13,253 78

From these data we can estimate the failure rate at 60 faults/(100 genera-tors, year).

Table 7 shows the distribution of number of faults by components.

Table 7 Number of faults for hydro-generators.

Canada Norway Sweden USA All Units 10-100 >100 10-100 >100 All

Units MVA MVA MVA MVA Stator exclud. sta-tor winding

4 8 4 6 5 0

Stator winding 9 4 15 25 16 Rotor 7 11 15 10 14 6 Bearing 21 6 13 10 4 18 Cooling 6 30 35 27 21 18 Excitation 59 11 24 5 1 35 Other Components

3 25 5 0 0 7

Total 100 100 100 73 70 100


GENPC040.DOC 2007-05-22 15.25

Table 8 shows the distribution of forced downtime for hydro-generators by components. Table 8 Forced downtime for hydro-generators.

Can-ada

Norway Sweden USA

All Units

10-100

>100 10-100

>100 All Units

MVA MVA MVA MVA Stator exclud. stator winding

45 19 6 15 0 5

Stator winding 39 15 57 75 66 Rotor 8 14 56 50 18 11 Bearing 23 8 17 10 4 10 Cooling 2 2 2 5 4 4 Excitation 20 12 4 5 1 4 Other Compo-nents

2 6 0 0 0 2

Total 100 100 100 142 102 102

4.3.2 Nordel

Nordel compiles failure statistics from Denmark, Finland, Norway and Sweden on faults that cause disturbances on the power systems with a rated voltage from 40 to 400 kV. The latest available report [ 9 ] comprises statistics for the period 1982-91.

Figure 5 shows the failure rate [faults/(100 generators, year)] for hy-dro-generators with a rated capacity, S greater than 5 MVA. At the end of 1991, the number of hydro-generators in Finland was 87, in Norway 672 and in Sweden 167.


GENPC040.DOC 2007-05-22 15.25

0

10

20

30

40

50

Finland Norway Sweden Nordel

Hydro-Power GeneratorsNordel 1982-91 ( S > 5 MVA )

Faul

ts/(1

00 g

en.,

year

)

5.7

15.1

35.6

18.3

Figure 5 Failure rate for hydro-generators, Nordel 1982-91.

We can see that the failure rate corresponds to a mean time between failures of 5 years. There is considerable variation in the failure rate from one country to another. Figure 6 shows the cause to the failures of the hydro-generators mentioned above.

0

20

40

60

Ligthning Nature Sabotage Staff Equipment Other

Hydro-Power GeneratorsNordel 1982-91 ( S > 5 MVA )

%

1

6

2

26

45

21

Figure 6 Causes to hydro-generator faults, Nordel 1982-91.


GENPC040.DOC 2007-05-22 15.25

We can see that failure of the technical equipment is the most common cause. It is also obvious that the power houses provide ample protection of the hydro-generators against lightning, nature and third party.

4.3.3 Sweden

Reference [ 8 ] contains some data on failure rates for hydro-generators in Sweden. The data base contains faults that occurred during the period 1964-1978 and the average failure rates are:

λp = 7.9 faults/(100 generators, year) for permanent faults,

λt = 6.7 faults/(100 generators, year) for temporary faults

λa = 14.6 faults/(100 generators, years) for all faults.

In reference [ 8 ], it is not possible to find the distinction between permanent and temporary faults. The failure rate, in reference [ 8 ], includes both electrical faults and other faults.

According to Siljeholm [ 6 ], the failure rate is 10.7 faults/(100 gene-rators, year) for all hydro-generators owned by Sydkraft.

4.3.4 Norway

Samkjöringen in Norway compiles [ 10 ] disturbance and fault statistics for the Norwegian main power system. This power system comprises power lines with a rated voltage equal to 40 kV or more. It also comprises genera-tors with a rated capacity of 5 MVA or more. Finally, it comprises shunt capacitors with a rated capacity of 10 Mvar or more. The average failure rate for hydro-generators during the period 1980-84 is 15.8 faults/(100 generators, years). For the same period, the average failure rate for synchronous condensers is 26.3 faults/(100 machines, years).

4.4 Summary

The probability of an electrical failure of a given synchronous generator is low. One can relate the failure rate of a synchronous generator to the failure rate of 400 kV overhead line. Let us assume that the failure rate of 400 kV overhead lines is 0.5 faults/(100 km, year). We assume that the failure rate of a synchronous machine is 15 faults/(100 generators, year). The failure rate of the synchronous machine then corresponds to the failure rate of a 15/0.5 = 30 km long 400 kV overhead line. It is common practice to use


GENPC040.DOC 2007-05-22 15.25

circuit-local back-up protection on such transmission lines. Few protection engineers would argue that the failure rate is so low that we can compromise on the demand to use one main protection and one back-up protection.

References

[ 1 ] Jeffreys, R.: "Reliability of rotating machines", ELECTRA, no.126, pp. 34-53, October, 1989.

[ 2 ] Kelley-Régnier, L. (ed.): "Power System Reliability AnalysisApplication Guide", Report, Working Group 38-03, CIGRE,1987.

[ 3 ] Kramer, H. & Reinhard, K.: "Schaden- und Zeitferfügbarkeits-Statistik an Dampfturbinen und Gereratoren", BBC-Nachrichten,vol. 56, no. 3, pp. 83-91, March, 1974.

[ 4 ] Kugler, H.: "Schäden an Turbogeneratoren", DerMaschinenschaden, vol. 45, no. 5, pp. 179-188, May, 1972.

[ 5 ] Kugler, H.: "Schäden an Turbogeneratoren", DerMaschinenschaden, vol. 49, no. 6, pp. 221-235, June, 1976.

[ 6 ] Siljeholm, Ö.: "Driftstörningar på Sydkrafts huvudsystem 1983",Rapport DN-8412-22, Sydkraft, 1984-12-21.

[ 7 ] Vetter, H.: "Verfügbarkeit großer Maschineneinheiten", Elektriz-itätswirtschaft, vol. 66, no. 24, pp. 744-752, 1967.

[ 8 ] "Elkraftteknisk handbok. Vol. 4, Elkraftsystem", EsselteStudium, Uppsala, 1984.

[ 9 ] "Nordel Driftstörningsstatistik - Fault Statistics", Nordel, 1991.

[ 10 ] "Statistikk over feil under driftforstyrrelser i det norskehovednettet 1984", Report, Samkjöringen av kraftverkene iNorge, Oslo, May, 1985.

[ 11 ] "Värmekraftaggregatens Reläskyddssystem", The SwedishTrunklinecommittee, Operations Committee, The WorkingGroup for Protection Systems, 21 October, 1991.

5.1

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5. BACKGROUND

This section contains a short historical background to the protection of syn-chronous generators. This section is entirely based on [ 1 ]. Electrical ma-chines for use in power systems were being produced in the final decades of the last century. Then, the only electrical protective devices available were fuses. They were suitable for use with some small motors. Apparently fuses could not provide adequate protection of generators. They were particularly unsuitable for use with three-phase machines because the operation of a single fuse in case of a phase-to-earth fault on a machine would have caused it to carry unacceptably high negative sequence currents. In addition the operation of fuses in the three-phase circuits could not have initiated the opening of field-winding circuits.

In 1902 H.W. Clothier stated in a paper that he presented to the IEE that for large AC generators it is feasible to do without fuses or other automatic devices. This view was also expressed by W.B. Woodhouse during a paper by H.L. Riesley that he presented to the IEE in 1903.

In spite of these views, there were those who felt that protection re-lays should be used. Reverse-current relays were referred to in a paper by C.H. Merz and McLellan entitled "Power station design" that was presented to the IEE in 1904. These relays were directional relays and their task was to detect current fed from the busbars into faulted machines. The authors stated that these relays would not detect short circuits within machines be-cause the voltages would be too low for the relays to function correctly. The authors nevertheless felt that automatic protective devices were required. In the discussion on this paper L. Andrew stated that he had demonstrated a reverse-current device in 1898 but recognised that it still was not entirely satisfactory. Reverse-current relays, developed by Brown Boveri, were referred to in a paper that was presented to the British Association in 1903. Five years later C.C. Garrard referred to the use of reverse-current relays with 0.5 s time lags to allow for transient effects in a paper presented to the IEE. Clearly most machines were operating without effective protective equipment thus far.

In 1910 K. Faye-Hansen and G Harlow presented a paper "Merz-Price protective gear and other discriminative apparatus for alternating-cur-rent circuits" to the IEE. They advocated the use of circulating-current protective schemes (differential relays) on alternators and showed ar-rangements suitable for delta- and star-connected machines. Even then sev-eral speakers in the following discussion expressed the view that such schemes were unreliable and not suitable for applications to alternators. One speaker, A.E. McKenzie, stated that two 4 MW, three-phase machines

5.2 Background

GENPC050.DOC 2007-05-22 15.25

in Manchester had then been protected by Merz-Price schemes for two years and that similar schemes were being applied to new 6 MW machines. He also expressed the view that devices should be provided to detect loss of excitation. Eventually it became the standard to apply current-differen-tial protective systems to the main winding of all machines.

References

[ 1 ] Wright, A. & Christopoulos, C.: "Electrical Power SystemProtection", Chapman & Hall, London, 1993.

6.1

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6. DIFFERENTIAL PROTECTION

A short-circuit between two (or three) phases in a synchronous machine is a very severe fault. Within a short time, such a fault may cause much damage. There is a risk that a short-circuit that is not cleared properly may cause a fire in the power house. All generators must have a short-circuit protection that detects internal short-circuits quickly, immediately trips the HV unit circuit-breaker (or the MV generator circuit-breaker), the field circuit-breaker, and de-energises the fault location. The short-circuit protection should also shut down the prime mover, turn on CO2 if provided and give an alarm. The short-circuit protection may also initiate the transfer of station auxiliaries from the normal supply from the generator terminals to the reserve supply from the network.

According to Mason [ 3 ], it is the standardised practice of manufac-tures to recommend differential protection for generators rated at 1 MVA or higher. In 1948, Harder and Marter [ 2 ] stated that most of the generators have such differential protection. Above 10 MVA, it is almost universally the practice to use differential relays [ 5 ].

A rotating machine provides a classical application of differential protection. Usually, all equipment, the CTs and the circuit-breakers are near each other. This minimises the possible error due to long cable runs. In ad-dition, there is only one voltage level involved. This means that the CT ratio and types can be the same. The CTs may have matched characteristics. A generator differential protection should have dedicated CT cores and cir-cuits. Such cores should not be used with any other protections, metres, in-struments or auxiliary transformers without a careful check on the effect on CT performance.

The CTs used for the generator differential protections is almost in-variably located in the buses and leads immediately next to the generator winding. This is done to limit the zone of protection so a fault in the generator is immediately identifiable for quick assessment of damage, repair and restoration of service. The generator buswork is usually included in some overall differential protection.

It is very important the differential protection does not operate in case of external short-circuits. This is important in power stations with several large generating units. Most power systems are not designed to withstand a line fault and a simultaneous loss of a generating unit (several generating units). There is a risk that the generator differential protection maloperates if a CT saturates. Close to power stations, the time constant, of the DC component of the short-circuit current, may be very long and in the order of 100 to 150 ms. External short-circuits with fully developed DC

6.2 Differential Protection

GENPC060.DOC 2007-05-22 15.26

component puts severe demands on CT and differential protection. Walker [ 4 ] states that the differential protections for the generators in the Snowy Mountain complex are stable even if the through fault current amounts to 10 times the rated current of the generators.

The generator differential protection can be very rapid and sensitive. During many years, it has been possible to obtain a sensitivity of 5 to 10% of the rated current of the generator and an operating time of 100 to 200 ms. The long operating times were necessary to avoid unwanted operation at external short-circuits when the DC component has a long time constant. According to [ 1 ], modern generator differential protection may have a sensitivity of 2 or 3% of the rated current of the generator. The generator differential protection RADSG has an operate time of 1 to 3 ms.

There may be more than one differential protection in a power station. In such cases, one differential protection is associated with the generator and one with the generator step up transformer. Several transformers may feed power to the auxiliaries. Such transformers may have their own differential protections. Sometimes an overall differential protection covers the generator, the buswork and the step up transformer. The sensitivity of the generator step up transformer differential may be about 20% of the rated current of the transformer. This differential protection must not trip when we energise the generator step up transformer and a high inrush current flows from the network to the transformer. After synchronisation, a small inrush current flows through the generator differential protection but it does not place severe demands on the differential protection. We have to use interposing current transformers in the overall differential protection and in the transformer differential protection. Some digital protections, which are available on the market, may not require external interposing transformers. We never delay the generator differential protection and the transformer differential protection.

The overall differential protection provides back-up protection. The sensitivity of the overall differential protection is equal to the sensitivity of the transformer differential protection. We observe that the overall differen-tial protection may operate non-selectively if we do not delay its tripping signal. This is the case when two generators share the same step up trans-former and a short-circuit hits one of the two generators. Such an non-selective function may prevent tripping to houseload. The failure to trip to houseload may delay the restart of nuclear units. We may delay tripping signal from the overall differential protection. With this, we may avoid non-selective operations. The delay makes it easier for the operating personnel to interpret the relay indications and locate the fault. The fault current on the low voltage side of the step up transformer may be very high.

Differential Protection 6.3

GENPC060.DOC 2007-05-22 15.26

Faults on the generator buswork or the generator circuit-breaker may subject personnel and equipment to very high stresses. The delay of the overall differential protection may increase those stresses. Generally, we recommend that the overall differential protection trips the unit circuit-breaker without any delay. The selectivity and the easier fault location are not as important as the reduced stresses.


GENPC060.DOC 2007-05-22 15.26

References

[ 1 ] Andersson, B., Broman, H., Eriksson, P.- A., Fredriksson, S. &Lohage, L.: "Generatorskydd i Vattenkraftstationer", Rapport,Vattenfall, November, 1982.

[ 2 ] Harder, E.L. & Marter, W.E.: "Principles and Practices of Relay-ing in the United States", AIEE Trans., vol. 67, pp. 1075-1081,1948.

[ 3 ] Mason, C.R.: "The Art and Science of Protective Relaying",John Wiley and Sons, New York, 1956.

[ 4 ] Walker, C.W.: "Relay Protection in Hydro-Electric PowerStations of the Snowy Mountains Authority", The Institution ofEngineers, Australia, Electrical Engineering Transactions, vol.EET-5, no. 2, pp. 311-316, September, 1969.

[ 5 ] "Relay Protection of A-C Generators", AIEE Committee Report,AIEE Trans., vol. 70, pt. I, pp. 275-282, 1951.

7.1

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7. UNDERIMPEDANCE PROTECTION

The line protections shall detect all shunt faults on the transmission network and to trip associated circuit-breakers. The back-up protection system must operate when a line protection fails to operate or when a circuit-breaker fails to interrupt the fault current. Often, the generator underimpedance protection is one part of this back-up protection system. Sometimes, there is no overall differential protection and we need another type of back-up protection when the main protection fails to operate.

Table 1 shows the steady-state short-circuit currents from generators at a three-phase short circuit on the generator terminals. We assume that the excitation voltage is constant.

Table 1 Steady-state short-circuit currents from generators.

Generator Steady-state short-circuit current [pu] No-load excitation Full-load excitation Turbo-generators 0.5 1.5 Hydro-generators 1.0 2.0

Nowadays, most synchronous machines have static excitation systems. It is normal practice to feed the excitation system from a dedicated excitation transformer connected to the generator buswork. The generator voltage falls to about 25% of nominal voltage on a three-phase short-circuit on the high voltage side of the step-up transformer. In such cases, the excitation system cannot maintain the excitation voltage. This means that the fault current may fall far below the values given above. Therefore, it is seldom possible to use a simple overcurrent protection as back-up protection.

We can attain reliable back-up protection by using underimpedance protections. The sensitivity of the underimpedance protection must be high because it has to detect short circuits at the remote end of all transmission lines that stars at the power station. According to [2], one should delay the underimpedance protection at least 0.8 seconds, perhaps 2 to 3 seconds. We may compare the tripping from the underimpedance protection with the tripping from Zone 3 of distance protections.


GENPC070.DOC 2007-05-22 15.26

References


8.1

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8. OVERCURRENT PROTECTION

The Swedish electrical safety regulations demand that all generators have an overcurrent protection in each phase. These regulations also demand that all generators have switching devices that disconnect all phases of the generator from the rest of the power system. A unit connected generator and transformer may use common protection and switching devices.

Many old synchronous generators have rotating exciters. Often, these generators have simple overcurrent protections [ 1 ]. The task of this over-current protection is to provide back-up protection for internal short-circuits and for external shunt faults. Generally, the setting is 1.5 In where In is the rated current of the generator. Often, the time delay is 1.5 seconds.

The introduction of static exciters made it necessary to replace the overcurrent protections by underimpedance protections. Short-circuits close to the power station may reduce the generator terminal voltage. The reduced terminal voltage reduces the excitation current. The fault current may fall below the rated current of the generator and the overcurrent protection may fail to operate. Underimpedance protections may operate even if the fault current is lower than the rated current of the generator.

Large generators are often equipped with differential protection that serves as main short-circuit protection. It is good engineering practice to equip the generator with short-circuit back-up protection. The overall differential protection is the best back-up protection. All generators do not have such back-up protections. Generators without overall differential protection must have underimpedance protection or overcurrent protection as back-up protection.

When the excitation current depends on the generator terminal volt-age, a simple overcurrent protection may not be reliable enough. As de-scribed in Section 7, underimpedance protections may provide reliable back-up protection. The combination of overcurrent and undervoltage relays may provide better short-circuit back-up protection than simple overcurrent protections. We can use voltage-controlled overcurrent protections where the overcurrent relay is disabled until the generator terminal voltage drops below the set level of the undervoltage relay. We can also use voltage-restrained overcurrent protections where the pickup value of the overcurrent relay is proportional to the generator terminal voltage.

Persisting overcurrents in the interval [1.0In,1.4In], where In is the rated current of the generator, are not detected by overcurrent protections or by underimpedance protections. Such overload must be detected by dedi-cated thermal overload protections or by over-temperature sensors. Modern

8.2 Overcurrent Protection

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overload protections may have an adjustable time constant that can be ad-justed to the thermal properties of the generator.

References


9.1

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9. INTERTURN FAULT PROTECTION

An interturn fault is a short circuit between two points on the same phase winding in an electrical machine. Figure 1 shows an interturn fault on phase C in a synchronous generator.

A

B

C

N

INTERTURN FAULT

Phas

e W

indi

ngs

Figure 1 Interturn fault in a synchronous generator.

Interturn faults are quite rare but they have occurred and will continue to occur. Buttrey, Hay and Weatherhall [ 1 ] have provided some information concerning the failure rate of interturn faults. They point out that it is diffi-cult to identify faults that were initiated by interturn faults. Usually, the source of initiation of a stator winding fault is destroyed by the subsequent damage. During the period 1970-74, thirteen major dielectric breakdowns have occurred on stator windings of machines rated at 200 MW or above. The number of exposed generators are not given. We have estimated the number of exposed generators at 50. This means that the failure rate of interturn fault may be in the order of 5.2 interturn faults/(100 generators, year).

Buttrey, Hay and Weatherhall [ 1 ] have also provided some informa-tion concerning the magnitude of the fault current. They state that it may be in the order of 100 kA on a 500 MW generator. Let us assume that the power factor (cos(ϕ)) is 0.8 and that the rated voltage of the generator is 20 kV. Then, the fault current is about 5 per unit. Such high local fault cur-rents can cause severe damage to the iron core. The fault clearance time must be as short as possible.

9.2 Interturn Fault Protection

GENPC090.DOC 2007-05-22 15.26

Modern medium size and large size turbo-generators have stator windings with only one turn per phase per slot. According to Sarma [ 4 ] and Warrington [ 8 ], such generators do not need interturn protection because interturn faults cannot occur without involving earth.

The longitudinal differential relay described in Section 6 will not de-tect interturn faults because there is no difference in the currents at the ends of a winding with shorted turns. An interturn fault would have to burn through the major insulation to earth or to another phase before the longitu-dinal differential relay can detect the fault. Many utilities have disregarded interturn faults on the basis that if they occur they will quickly develop into earth faults [ 9 ]. This is probably true if the fault is in the slot portion of the winding. It will, however, take a little longer in the end portion of the winding.

An approach of this kind is never attractive and may be entirely un-justified. There is a possibility of the machine being seriously damaged be-fore the fault evolves so that can be detected by the longitudinal differential protection or by the earth fault protection. An instantaneous and sensitive interturn fault protection would contribute to the reduction of the resulting damage to the windings and the iron core. An interturn protection will also provide backup protection for some phase-to-phase faults.

We may use various protection schemes to detect interturn faults. Usually, they require additional bushings and terminals. Turbo-generators have physical restrictions that make it difficult to bring out additional terminals. Because of the general use of hydrogen cooling on large turbo-generators, it is not practical to bring out additional terminals from the windings for installing current balance schemes to detect interturn faults.

Some hydro-generators have stator windings with only one turn per phase per slot. Many large hydro-generators have phase windings with two or more parallel circuits. According to Mason [ 3 ], many hydro-generators in Canada have interturn protection as described in [ 5 ].

Wang, Zhang, Wang and Yu have documented [ 7 ] an analysis of in-ternal faults in a synchronous generator. They have analysed a machine with windings with six parallel circuits per phase. There are six current transformers per phase at the neutral end of the phase winding and one current transformer that senses the current to the neutral point resistor. There is one current transformer per phase at the line end of the phase windings. There are therefore 22 current transformers.

Interturn Fault Protection 9.3

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9.1 Transverse Differential Protection

Sometimes each phase winding comprises two identical circuits connected in parallel. A transverse differential protection can detect interturn faults in such machines, if the windings are brought out separately. Figure 2 shows a transverse differential protection that uses current transformers connected at the line end of the phase-windings. A transverse differential protection can also use current transformers connected at the neutral end of the phase-windings.

R

B

R

C

R

A

N

TRANSVERSE DIFFERENTIAL PROTECTION

Figure 2 Transverse differential protection.

Balanced current in the two windings produces a circulation of current in the current transformer secondary circuit. An interturn fault will result in a circulation of current between the windings. This will produce a current in the operate winding of the transverse differential protection. The interturn protection will also detect some phase-to-phase short circuits. It will, however, not always provide as good protection as the longitudinal differential protection. One can use a dependent time overcurrent relay as the measuring relay R. Time delay reduces the main advantage of the interturn protection, namely the instantaneous tripping.

It is also possible to use an instantaneous differential relay. Here a bi-ased system should always be used, as it is not possible to guarantee in ad-vance that exact current sharing between the windings will take place. A


GENPC090.DOC 2007-05-22 15.26

small error in this sharing would cause unwanted operation of the transverse differential protection.

All generators in the Snowy Mountain complex have windings with two parallel circuits [ 6 ]. Each half of each phase winding is brought out separately at the neutral end. The necessary current transformers, with cross-connected secondaries, are situated ahead of the neutral point. In the earlier stations, Snowy Mountains Hydro-Electric Authority (SMHEA) installed biased-differential relays for this application. The reason was that the restraint feature would take care of any unbalance that might be present between the two halves of the winding. This proved to be a false premise at light load, however, due to the then unappreciated nature of the harmonic currents that circulate in any generator with split-phase winding. An interesting property of the interturn protection was discovered at Tumut 1 when an operator inadvertently tripped the field breaker of a generator. The generator was running at no-load while disconnected from the rest of the power system. This action resulted in unwanted operation of the interturn protection on all three phases. Subsequent tests showed that, immediately following the field breaker trip, the circulating currents did increase to a value above the operate current. At that time the operate value was 5% of the rated phase current. The rapid rate of change of the field voltage during the field suppression process caused circulating currents in the split-phase winding. SMHEA increased the operate value of the interturn protection to 7.5% on all machines at Tumut 1 and later at Tumut 2. The incident showed very clearly that the previously supposed advantage of employing a biased-differential relay for interturn protection was far from real. The small amount of restraint at light load is negated by the summation of the circulating currents in the operating coil of the protection. Therefore, SMHEA installed high-impedance transverse differential protection at Murray 1 and subsequent stations.

Bär, Grau and Kienast [ 2 ] describe the protection system for a pump storage plant with 4 units. Each unit has a rated apparent power of 290 MVA. Each unit has, among other protections, sensitive and percent-age-stabilised transversal differential protections. The operate current is 5% of rated phase current. The operate time is 10 ms.

9.2 Zero Sequence Voltage Protection

For generators with windings without parallel circuits we cannot use the transverse differential protection described above. Reference [ 10 ] docu-ments an interturn protection for windings with only one circuit per phase. The protection uses three single-phase voltage transformers connected to


GENPC090.DOC 2007-05-22 15.26

the line end of each winding. One must connect the other primary terminal of the voltage transformers to the neutral point of the generator. The protection measures the zero sequence voltage across the machine. Normally, no zero sequence voltage should exist but a short circuit of one or more turns on one phase will cause the generated EMF to contain such a component. Figure 3 shows such a zero sequence protection.

A B C

R

ZERO SEQUENCE VOLTAGE PROTECTION

Figure 3 Zero Sequence Voltage Protection.

The voltage transformers have a broken-delta connected secondary winding that energises a relay. Therefore, the relay receives a quantity that is proportional to the zero sequence component of the voltage across the machine.

An earth fault will also produce a zero sequence voltage on the gen-erator terminal. Most of the voltage will be expended on the earthing resis-tor. The zero sequence voltage drop in the machine will be small. The zero sequence component will be limited to 1 or 2% [51]. Therefore, it is prefer-able to measure the zero sequence drop across the generator windings, rather than the zero sequence voltage to earth at the line terminals. This is done by a voltage transformer connected to the line terminals, with the neu-tral point of the primary winding connected to the generator neutral, above the earthing resistor.

The third harmonic component of the EMF will appear as a zero se-quence voltage. It is likely that the amount of the third harmonic will exceed the required operate voltage. We can introduce a filter that removes


GENPC090.DOC 2007-05-22 15.26

most of the harmonic content in the secondary voltage from the broken-delta connected winding. We can also provide a filter to extract the third harmonic component from the broken-delta connected winding and apply it as a relay bias [51].


GENPC090.DOC 2007-05-22 15.26

References

[ 1 ] Buttrey, M, Hay, D. & Weatherall, P.M.: "Generator InterturnProtection", First International Conference on Developments inPower System Protection, 11-13 March, 1975, IEE ConferencePublication Number 125, pp. 42-49, London, 1975.

[ 2 ] Bär, G., Grau, H.-W. & Kienast, L.: "Der Generatorschutz inelektronischer Bauweise im Pumpspeicherwerk Wehr", Elektriz-itätswirtschaft, vol. 78, no. 5, pp. 147-154, 1979.


[ 4 ] Sarma, M.S.: "Synchronous Machines (Their Theory, Stability,and Excitation Systems)", Gordon and Breach, New York, 1979.

[ 5 ] Sills, H.R. & McKeever, J.L.: "Characteristics of Split-PhaseCurrents As a Source of Generator Protection", AIEE Trans.,vol. 72, pt. III (Power Apparatus and Systems), pp. 1005-1016,1953.


[ 7 ] Wang, X.H., Zhang, L.Z., Wang, W.J. & Yu, Z.H.: "Researchand Application of Protection Relay Schemes for Internal Faultsin Stator Windings of a Large Hydro-Generator with Multi-Branch and Distributed Arrangements", Fourth InternationalConference on Developments in Power System Protection,Edinburgh, 11 - 13 April, 1989, IEE Conference PublicationNumber 302, pp. 51-55, IEE, London, 1989.

[ 8 ] Warrington, A.R. Van C.: "Protective Relays. Their Theory andPractice. Volume One", 2nd ed., Chapman and Hall, London andNew York, 1968.

[ 9 ] "Protective Relays Application Guide", 2nd ed., GEC Measure-ment, 1975, 5th printing, October, 1983.

[ 10 ] "Reläskydd - HANDBOK FÖR KRAFTFÖRETAG", VAST,November, 1982.

10.1

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10. PROTECTION AGAINST OPEN CIRCUITS

An open circuit in the windings of a modern generator is not likely because of the size of the conductors [ 6 ]. Some stator windings with large cross-sectional area have several parallel circuits. Such a design eases the construction and reduces the losses caused by the skin effect. It is difficult to detect an open circuit in one of these circuits and to detect high resistance in soldering-joints. Such faults may cause considerable damage before it is detected and cleared. The longitudinal differential protection cannot detect such faults. The negative sequence protection can detect such faults.

Some generators have a double-winding design. Each phase has two separate windings that form two star-connected windings. According to Tideström [ 5 ], it is possible to protect such generators with a sensitive protection against open circuits. The neutral point of both windings must be brought out. Figure 1 shows such a neutral point differential protection.

R

NEUTRAL POINT DIFFERENTIAL PROTECTIONA B C

N

Figure 1 Neutral point differential protection.

One current transformer can replace the two cross-connected current trans-formers if the neutral point is unearthed. This single current transformer measures the current that flows between the two neutral points. Figure 2 shows such a neutral current unbalance protection.

10.2 Protection Against Open Circuits

GENPC100.DOC 2007-05-22 15.27

R

NEUTRAL POINT UNBALANCE PROTECTIONA B C

N

Figure 2 Neutral point unbalance protection.

The neutral point unbalance protection must not operate if harmonic currents flow from one neutral point to the other. Sometimes the protection will only give an alarm. The faults that the protection can detect cause, according to Tideström [ 5 ] no immediate danger to the generator.

Let us now assume that we want to equip a generator with an interturn protection and protection against open circuits. This means that each phase must have four current transformers at the neutral end. Open circuits are, according to Mason [ 4 ], most unlikely in well-constructed machines.

Generally, utilities in the United States do not install protection against open circuits [ 6 ]. According to Evenson [ 1 ] protection against open circuits belongs to the standard protection for generators in Sweden but such protection is uncommon outside Sweden. In [ 7 ] it is stated that modern generators in Sweden do not have protection against open circuits.

In Canada, there are generators with very sophisticated interturn pro-tection and protection against open circuits. Gurney [ 2 ] and Handel [ 3 ] describe the new hydro power plant Revelstoke. Now, there are four gen-erating units with a rated apparent power of 485 MVA each. In the future, there will be six generating units. Each phase winding of the generators has eight parallel circuits. There are twelve transverse differential protections that compare the current in two neighbouring circuits. At the neutral end, two current transformers feed a longitudinal differential protection. At the

Protection Against Open Circuits 10.3

GENPC100.DOC 2007-05-22 15.27

line end there are four current transformers per phase. To detect phase-to-phase short circuits, there are four three-phase differential protections.

References

[ 1 ] Evenson, O.: "Reläteknik för högspänningsanläggningar", Kom-pendium, Lidingö, 1961.

[ 2 ] Gurney, J.H.: "Control and Protection Design of the RevelstokeHydroelectric Project", IEEE Trans. on Power Apparatus andSystems, vol. PAS-104, no. 8, pp. 1987-1997, August, 1985.

[ 3 ] Handel, R.D.: "Electrical Design of the Revelstoke HydroelectricProject", IEEE Trans. on Power Apparatus and Systems, vol.PAS-104, no. 8, pp. 2012-2019, August, 1985.


[ 5 ] Tideström, S. H:son (ed): "Ingenjörshandboken/Allmän Elektro-teknik", 3rd ed., Nordisk Rotogravyr, Stockholm, 1959.


[ 7 ] "Reläskydd - HANDBOK FÖR KRAFTFÖRETAG", VAST,November, 1982.

10.4 Protection Against Open Circuits

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11.1

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11. STATOR EARTH-FAULT PROTECTION

There are many methods for the detection of earth faults on synchronous generators. The choice of method depends on the layout of the power plant. Section 2 contains the single-line diagram of four power plants. To summarise, there are units with the generator and the step-up transformer connected as a unit. The generator may or may not have a generator circuit-breaker. Two or more generators may share a common step-up transformer. One may connect several small generators to a common generator busbar. In such cases, the number of step-up transformers may be one or more. The method for the detection of earth faults depends also on the system earth-ing. Wilheim and Waters have written a book [ 8 ] on system earthing.

11.1 Earthing of Generating Units

Many small generators have, according to Tideström [ 6 ], solidly earthed neutral. In such generators, the short circuit protection system can also de-tect earth faults. A sensitive differential protection can [ 6 ] also detect earth faults if the rated current of the generator is less than 500 A.

Other generators have high-impedance earthed neutral. This means that they have unearthed neutral, high-resistance earthed neutral or resonant earthed neutral. Most generators have high-resistance earthed neutral. One can use a high voltage resistor and connect it directly to the neutral point of the generator. It is also possible to use a low voltage resistor and connect it on the secondary side of a single-phase distribution transformer. The neutral point of the generator is connected to the primary side of the distribution transformer. The main task of the neutral point resistor is to limit the overvoltage on the windings and buswork of the generating units. Overvoltages on the high voltage side of the step-up transformer may cause such an overvoltage. The stray capacitances between the high voltage winding and the low voltage winding of the step-up transformer determine the magnitude of the overvoltage on the generator winding and associated buswork. It is often necessary to install surge capacitors on the low voltage side of the step-up transformer if there is a generator breaker. The highest overvoltage on the buswork occurs while the generator breaker is open.

There is a rule-of-thumb for the selection of the neutral point equip-ment. The effective resistance, RN [Ω] seen from the neutral point of the generator should be equal to the capacitance to earth as in equation ( 1 ). All capacitances are zero sequence capacitances ( = capacitances to earth with all phase conductors connected to each other).


GENPC110.DOC 2007-05-22 15.27

Nw b a t

R = 13 (C + C + C + C )ω

( 1 )

where Cw = the capacitance of the generator winding [F/phase], Cb = the capacitance of the buswork [F/phase], Ca = the capacitance of the auxiliary transformers [F/phase], Ct = the capacitance of the step-up transformer [F/phase].

High earth fault currents may damage the iron core if the fault clearance time is long. The risk for damage is small if the earth fault current is lower than 15 A when there is an earth fault on one generator phase terminal. According to Walker [ 7 ], the safe limit is 5 A.

Below, we will discuss only generators with high-impedance earthed neutral. We describe earth fault protection systems for generators and trans-formers connected to a unit. Figure 4 in Section 2 shows the single-line dia-gram for such a power plant with generating units without a generator breaker. Figure 5 in Section 2 shows the single-line diagram for generators with a generator breaker. One can use similar earth fault protection systems in power plants where two or more generators share a the same step-up transformer. Figure 6 in Section 2 shows the single-line diagram for such a power plant. Finally, we will describe earth fault protection systems for generators connected to a common busbar. Figure 7 in Section 2 shows the single line diagram for such a power plant.

11.2 The Earth Fault Protection System

The task of the earth fault protection system is to detect earth faults on the winding of the generator, on the associated buswork, on the primary winding of the auxiliary transformer and on the primary winding of the step-up transformer. A single phase-to-earth fault will cause an increase of the voltage on the other phases and on the neutral point. The voltage rise depends on the fault location and on the fault resistance. The healthy phases will assume full phase-to-phase voltage if an earth fault without fault resistance hits the line terminal of one winding of the generator. Simultaneously, the neutral point will assume full phase-to-neutral voltage. The voltage rise will decrease when the fault resistance increase. The voltage rise will be negligible if the earth fault occurs on the phase winding close to the neutral point.


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To detect an earth fault on the windings of a generating unit one may use a neutral point overvoltage relay, a neutral point overcurrent relay, a zero sequence overvoltage relay or a residual differential protection. These protection schemes are simple and have served well during many years. However, at best these simple schemes protect only 95% of the stator winding. They leave 5% at the neutral end unprotected. Under unfavourable conditions the blind zone may extend to 20% from the neutral. There are several methods to detect an earth fault close to the neutral point. Figure 1 illustrates some fundamental properties of some types of earth fault protections. The intention is to illustrate general methods and define some classes of earth fault protections.

TYPES OF EARTH FAULT PROTECTIONS

NA

B

C

Line End EarthFault ProtectionNeutral End EarthFault Protection

Total EarthFault Protection

Combined EarthFault Protection

Figure 1 Types of earth fault protections.

The line end earth fault protections can detect earth faults on almost the entire generator winding but have a blind zone close to the neutral point. The size of the blind zone may be 5-20%. The main task of the neutral end earth fault protection is to detect an earth fault close to the neutral point. Such protections may cover 20-40% of the winding. Sometimes these protections can detect earth faults close to the line terminals. To cover the entire winding, one can use a combined earth fault protection that com-prises line end earth fault protection and a neutral end earth fault protection. There are finally total earth fault protections based on a method that makes it possible to detect earth faults anywhere along the entire generator winding.


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11.3 Line End Earth Fault Protection

Neutral point overvoltage protections, neutral point overcurrent protections, zero sequence overvoltage protections and residual differential protections are line end earth fault protections.

11.3.1 Unit Generator-Transformer Configuration

The neutral point overvoltage protection is a common earth fault protec-tion for unit-connected generators. Figure 2 shows a neutral point overvolt-age protection.

NEUTRAL POINT OVERVOLTAGE PROTECTION

U>

N

A B C

Figure 2 Neutral point overvoltage protection.

A single-phase voltage transformer connected to the generator neutral ener-gises the neutral point overvoltage protection. Such protection detects earth faults on the generator windings, on the buswork and on the primary wind-ing of the auxiliary transformer. It can also detect earth faults on the primary winding of the step-up transformer in units without generator breaker and while the generator breaker is closed. The blind spot near the neutral may be as small as 5%.

The neutral point overcurrent protection has similar properties as the neutral point overcurrent protection. The overcurrent protection detects earth faults on the generator windings, on the buswork, on the primary winding of the auxiliary transformer and on the primary winding of the


GENPC110.DOC 2007-05-22 15.27

step-up transformer. Figure 3 shows such a neutral point overcurrent protection.

NEUTRAL POINT OVERCURRENT PROTECTION

I>

N

A B C

Figure 3 Neutral point overcurrent protection.

A single-phase current transformer energises the neutral point overcurrent protection. The primary current is equal to the current that flows from the generator neutral to earth. Evenson states [ 3 ] that the neutral point overcurrent protection is inferior to the neutral point overvoltage protection. The blind zone near the neutral may be 20-30%. A zero sequence overvoltage protection can also detect faults on the generator system. Figure 4 shows such zero sequence overvoltage protection.

Three single-phase voltage transformers energise the zero sequence overvoltage protection. The primary winding of each voltage transformer is connected to a phase conductor. A secondary winding on each voltage transformer form a broken delta that energises the overvoltage relay.

Each voltage transformer has an amplitude error and a phase error. This means that the secondary zero sequence voltage may not represent the primary zero sequence voltage exactly. To avoid unwanted operation, the zero sequence overvoltage setting must be higher that the neutral point overvoltage setting.

Lohage and co-workers have documented [ 1 ] practice for the earth fault protection in hydro power plants owned by Vattenfall (Swedish State Power Board).


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Generally, large hydro power units with generator breakers have one neutral point overvoltage protection and one zero sequence overvoltage protection. The neutral point overvoltage protection must cover at least 95% of the stator winding. In new plants a combined earth fault protection that can detect earth faults anywhere along the generator winding replaces the neutral point overvoltage protection. The delay for this sensitive protection is usually 1.2 second. Often, the zero sequence overvoltage protection covers about 80% of the generator winding. Normally, the delay is 0.4 second.

ZERO SEQUENCE OVERVOLTAGE PROTECTION

N

A

B

C

U>

Figure 4 Zero sequence overvoltage protection.

The earth fault protections described above cannot detect earth faults on the primary winding of the step-up transformer while the generator breaker is open. To detect such faults, one may use a zero sequence overvoltage pro-tection. It is connected to the primary winding of the step-up transformer. The sensitivity is about 80% and the delay is equal to 0.8 second.

11.3.2 Several Generators Connected to a Common Busbar

Let us now consider a power plant with several generators connected to a common busbar. The busbar has one or more transformer bays. Usually, the busbar has no feeder bays. In such plants it is common practice that the generators have unearthed neutral. Often, there is a requirement to limit the overvoltage on the busbar while only one generator is in service. This case


GENPC110.DOC 2007-05-22 15.27

determines the maximum size of the resistor connected to the neutral point of the generator. When all generators with such resistors are in service, the total earth fault current may become too high.

Some busbars may have a bay for an earthing transformer with a neu-tral point resistor. In such cases, the system has a high-impedance earthed neutral. Sydkraft uses a combined earthing transformer and station auxiliary transformer. Some plants may have only a step-up transformer with a Y- or Z-connected winding connected to the busbar. One can use this neutral point to connect a neutral point resistor. It is not necessary to install neutral point resistors at each generator if there is an earthing transformer with a neutral point resistor of if the step-up transformer has a neutral point resistor. It is also possible to avoid using neutral point disconnecters otherwise necessary to limit the earth fault current.

Neutral point overvoltage protections, neutral point overcurrent pro-tections and zero sequence overvoltage protections cannot select the faulty generator if several generators are connected to one common busbar.

Figure 5 shows a residual differential protection that can select the faulty generator when several generators are connected to a common busbar.

One only needs three-phase current transformer if the neutral point of the generator is unearthed. Unavoidable amplitude errors and phase errors limit the sensitivity of the earth fault protection. On external short-circuits, the fault current from the generator may be very high and may contain a substantial DC component. The fault currents may cause a false secondary zero sequence current. There is a risk that this false current will cause un-wanted operation of the earth fault protection. To avoid such unwanted op-erations, the short circuit protection may block the earth fault protection on external short-circuits. The closing of the generator breaker may cause tran-sient residual currents. These currents may limit the sensitivity of the resid-ual differential protection.

Let us now assume that each generator has a neutral point resistor. To obtain selective clearance of earth faults, it is necessary to use a residual differential protection. Figure 5 shows such a protection that is energised from three-phase current transformers and one neutral point current transformer.

Generally, it is necessary to clear earth faults on the buswork and on the primary winding of the step-up transformers. To detect such faults, one may use a zero sequence overvoltage protection. Three single-phase voltage transformers connected to the primary winding of the step-up transformer may energise the zero sequence overvoltage protection.


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RESIDUAL DIFFERENTIAL PROTECTION

N

A B C

R

Figure 5 Residual differential protection.

11.4 Neutral End Earth Fault Protection

An overvoltage (or overcurrent) generator earth fault protection is straight-forward, secure, and dependable earth-fault protection. However, it suffers from two disadvantages [ 4 ]. First, it will not detect earth-faults near the generator neutral. Second, it is not self-monitoring. That is, an open circuit anywhere in the relay, primary or secondary of the voltage transformer (the current transformer) or an open neutral point resistor may not be detected before a fault occurs.

The induced EMF in a synchronous generator contains harmonics. It is possible to use the third harmonic to detect earth faults close to the neutral point and in the neutral point equipment. The induced third harmonic voltages cause a third harmonic current that flows through the neutral point resistor.

An earth fault close to the neutral point will shunt the neutral point resistor and the third harmonic voltage over the neutral point resistor. Ac-cording to Schlake, Buckley and McPherson [ 5 ] such a third harmonic protection can detect earth faults with a fault resistance less than 1 000 Ω. It can detect such faults on 20% of the generator winding near the neutral point.


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11.5 Combined Earth Fault Protection

When combined to form a protection system, each relay covers the blind zone of the other. Therefore, the combined protection system will detect earth faults anywhere on the stator winding.

Griffin and Pope describe [ 4 ] the earth fault protections used by Georgia Power Company. For over 30 years, Georgia Power Company has grounded all system generators through a distribution transformer with a re-sistance-loaded secondary. A current transformer is then connected in series with the secondary resistor to supply current to one or more overcurrent relays. When properly set, these relays will provide sensitive protection for 90 to 95 percent of the generator stator winding, and will not operate incorrectly for external faults. At the end of 1981, this system is installed on 126 generating units, ranging in size from 15 to 900 MW. In the past 25 years, nearly 20 earth faults have been cleared with minimal equipment damage, and no incorrect operations have occurred.

In 1977, Georgia Power Company concluded that it would be prudent to protect all large generators with an additional earth fault protection system that was completely independent of the existing overcurrent scheme, would give reliable protection to 100% of the generator, and would continuously monitor the generator earthing system. Two types of systems have been installed. One type injects a current at a subharmonic current, and trips on an increase of current caused by the reduction in generator capacitance that results from a single phase-to-earth fault. The other type employs two overlapping voltage relays - an overvoltage relay that protects the high voltage end of the machine, and an undervoltage relay, tuned to respond to the third harmonic, which protects the neutral. Griffin and Pope states [ 4 ] that both schemes have performed extremely well, and that the combine overvoltage/undervoltage scheme has already properly detected an earth fault. It should also be noted that in 1980, a Georgia Power Company generator on which a 100% earth fault protection had not yet been installed, was badly damaged by a ground fault that occurred very near the neutral and was not detected by the 90% protection [ 4 ].

11.6 Total Earth Fault Protection

In 1936, Diesendorf and Groß [ 2 ] pointed out the need for an earth-fault protection that detects earth faults on the entire stator winding. They ana-lysed the method to inject a power frequency voltage at the neutral of the generator.


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There are schemes that inject a subharmonic voltage into the pro-tected plant. An overcurrent relay monitors the subharmonic current that flows to the protected plant. An earth fault anywhere on the stator winding will increase the subharmonic current. This scheme provides total coverage of the entire stator winding. However, the cost of the implementation tends to be high due to the cost of the injection equipment.

References


[ 2 ] Diesendorf, W. & Groß, E.: "Zur Theorie der Pohl'schenNullpunktsverlagerung für vollständigen Gehäuseschlußschutz",E und M, vol. 54, no 22, pp. 253-256, 31 May, 1936.

[ 3 ] Evenson, O.: "Reläteknik för högspänningsanläggningar", Kom-pendium, Lidingö, 1961.

[ 4 ] Griffin, C.H. & Pope, J. W: "Generator Ground Fault ProtectionUsing Overcurrent, Overvoltage, and Undervoltage Relays",IEEE Trans. on Power Apparatus and Systems, vol. PAS-101,no. 12, pp. 4490-4501, December, 1982.

[ 5 ] Schlake, R.L., Buckley, G.W. & McPherson, G.: "Performanceof Third Harmonic Ground Fault Protection Schemes forGenerator Stator Windings", IEEE Trans. on Power Apparatusand Systems, vol. PAS-100, no. 7, pp. 3195-3202, July, 1981.



[ 8 ] Wilheim, R. & Waters, M.: "Neutral Grounding in High VoltageTransmission", Elsevier Publishing Co., New York, 1956.

12.1

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12. FIELD EARTH-FAULT PROTECTION

The field circuit comprises the field winding of the generator and associated circuits of the exciter. We may classify faults in the field circuit as open circuits, earth faults and short circuits.

The oil film in the bearings provides some insulation between the ro-tor and the stator in a generating unit. Charge separation in the later stages of a steam turbine may cause the blades to pick up electrons and acquire a negative charge. Most turbine generators have one or more shaft-earthing brushes to prevent build up of electrical charge on the shaft. This means that the metallic parts of a turbo-generator have contact with earth via the shaft earthing brush. The metallic parts of a hydro-generator have contact with earth via the turbine and the waterways.

12.1 Open Circuits

Open circuits in the field circuit may occur on any type of generator. Experience has shown that they are more likely to occur on slower speed hydro-generators [ 12 ]. An open field circuit may cause burning at the fault location. Besides local damages, an open field circuit causes a complete loss of excitation. Section 13 contains a discussion on loss of excitation.

12.2 Earth Faults

The field winding is always insulated from the metallic parts of the rotor. The insulation resistance is high if the rotor is cooled by air or by hydrogen. The insulation resistance is much lower if the rotor winding is cooled by water. This is true even if the insulation is intact. A fault in the insulation of the field circuit will result in a conducting path from the field winding to earth. This means that the fault has caused a field earth fault.

The field circuit of a synchronous generator is normally unearthed. Therefore, a single earth fault on the field winding will cause only a very small fault current. The leakage resistance of the field winding will deter-mine the size of this fault current. This means that the earth fault current is larger if the generator has a water-cooled rotor. Even then, the earth fault does not produce any damage in the generator. Furthermore, it will not affect the operation of a generating unit in any way. Utilities have, in fact, operated generators in this condition for considerable periods. However, the existence of a single earth fault increases the electric stress at other points in the field circuit. This means that the risk for a second earth fault at another point on the field winding has increased considerably. A second

12.2 Field Earth-fault Protection

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earth fault will cause a field short-circuit with associated consequences described below.

The safest practice is, however, to trip the generator immediately when the first earth fault occurs. This practice should certainly be followed in unattended power plants [ 6 ]. However, some utilities are prepared to take the risk of a second earth fault and its possible consequences in an at-tended plant. Most utilities alarm on the indication of the first earth fault and prepare to remove the unit in an orderly shutdown at the first opportunity [ 5 ]. If one permits a generator to operate with a single earth fault on its field winding, it should at least have automatic equipment for immediate tripping the generating unit at an abnormal amplitude of vibration. Such vibrations will also occur on synchronising and on external shunt faults. As usual, one has to strike a balance between the dependability and the security. The vibration-detection equipment should be in service continuously and not be put in service manually after the first earth fault [ 6 ].

12.3 Short Circuits

Danger arises if a second earth fault occurs at another point on the field winding. The second earth fault will cause a short-circuit in the field wind-ing. An overcurrent relay in the field circuit cannot detect a short circuit if only a few turns are involved or if one pole of a slow-speed hydro-generator is short-circuited. Furthermore, it is highly desirable for the field circuit not to be opened during external power system faults. Such faults may cause high currents to flow in the field circuit. Therefore, field overcurrent protections are uncommon [ 12 ].

The normal field current of a large generator is considerable. The fault current caused by the short circuit may very rapidly cause serious damage at the fault locations.

Still more damage may be caused mechanically. The magnetic flux of one pole will decrease if some turns of the field winding on that pole should become short-circuited. If a large portion of the field winding is short-circuited, the excitation current will be diverted, in part at least, from the intervening turns. This will redistribute the flux on the rotor. Consequently, the attracting force is still normal on some poles. The short circuit will, however, weaken the attracting force on other poles. The result is an unbalanced force and the number of short-circuited turns determines the size of this force. The effects of a short circuit are most evident for turbo-generators with rotors that have few poles. In a large machine, this force may be about 50 to 100 tons [ 11 ]. The force rotates with the rotor

Field Earth-fault Protection 12.3

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and produces violent vibrations. Vibration-monitors may detect the condition shut down the generating unit or at least give an alarm.

Cases are on record where the resulting vibration has broken bearing pedestals, allowing the rotor to grind against the stator. Such failures have caused extensive damage that was costly to repair and that kept the ma-chines out of service for a long time [ 6 ]. The outage of a large generating unit may cost several hundred thousands US dollars per day.

A short circuit on the slip rings causes a high fault current that may overload the exciter. Optical sensors may detect the resulting arc. A short circuit will give a large signal from the sensor. The optical sensor may also detect sparks from worn brushes. Now, the signal level will be lower. Usu-ally, the fault detecting equipment has two levels. The high level should de-tect short circuits on the slip rings and will trip the unit. The low level should detect sparks and will give an alarm. Usually, one delays the signal about 5 seconds to avoid alarm on temporary sparking.

12.4 Demands on Field Earth Fault Protection

It is desirable that an indication of an earth fault should be given so that the operator may take remedial actions at the earliest convenient opportunity. The consequences of a double earth fault in the field winding are so severe that many utilities want to detect the first earth fault and trip the generator. The large capacitances increase the difficulties to detect earth faults on the field winding of large generating units[ 8 ].

According to Tideström [ 7 ], the earth fault detector should only give an alarm. The earth fault detector for the generators in the Snowy Mountain Complex gives an alarm only [ 9 ]. There is a requirement on the operator to take the unit out of service orderly with the least delay. Lohage and co-workers describe [ 1 ] the requirement on the earth fault protection of generating units owned by Vattenfall. The sensitivity of the earth fault detector must be higher than 1 to 2 kΩ. The earth fault protection shall trip the generator. Bär, Grau and Kienast [ 3 ] state that the sensitivity of the earth fault detector must be higher than 2 kΩ.

Earth fault detection for the exciter and the field winding are impor-tant and usually supplied as part of that equipment rather than applied by the user [ 2 ]. However, if not supplied, or if additional protection is desired, several methods are available to detect an earth fault on the field circuit.


GENPC120.DOC 2007-05-22 15.27

12.5 Earth Fault Detectors for Units with Brushes

A simple earth fault detector consists of two lamps connected in series be-tween the supply connections [ 10 ] and [ 12 ]. There is an earth connection at the midpoint. Under healthy conditions, both lamps have the same voltage across them and they should therefore be equally bright. Should a fault occur on the field winding at any point other than the centre, unbalance will occur. It will cause one lamp to be brighter than the other, because of the unequal voltages across them. This earth fault detector gives a positive indication only for faults near the terminals of the field winding.

One can obtain a more sensitive earth fault detector by replacing the lamps with resistors and connecting the midpoint to earth through a sensitive DC-type overvoltage relay [ 12 ]. When an earth fault occurs on the field winding or exciter circuits, a voltage appears across the relay. It will operate if the voltage is high enough. This scheme has also the disadvantage that it will not operate for an earth fault near the midpoint of the field winding [ 10 ].

Alternative schemes have been developed to eliminate this limitation [ 10 ]. One arrangement includes a varistor in series with one of a pair of divider resistors. It changes this blind spot with variations of the field voltage.

Large generators have more complex arrangements involving AC or DC auxiliary supply. The AC scheme comprises an auxiliary supply trans-former. Its secondary winding is connected between earth and one side of the field circuit through an interposed capacitor and a relay coil [ 11 ]. The field circuit is subjected to an alternating potential that has practically the same level throughout. Therefore, an earth fault anywhere in the field circuit will cause an AC current that is detected by the relay. The capacitor limits the current and blocks the normal field voltage. It also prevents the discharge of a large DC current through the auxiliary transformer.

One may avoid the capacitive currents associated with AC injection by injecting a DC voltage through a resistor [ 11 ]. The injected DC voltage is arranged to bias the positive side of the field circuit to a negative voltage to earth. The negative side of the field circuit is at an even greater negative voltage to earth. This means that an earth fault at any point on the field winding will cause current to flow through the power unit and the DC-type relay. The current is limited by including a high resistance in the circuit and a sensitive relay is used to detect the current.

Field Earth-fault Protection 12.5

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12.6 Earth Fault Detectors for Units with Brushless Exciters

The introduction of brushless exciters has increased the difficulties to detect earth faults on the field winding [ 8 ].

Generators with brushless exciters are supplied with means to drop pilot brushes on slip rings to measure the insulation level of the field winding on a periodic basis [ 2 ].

Ungrad, Winkler and Wiszniewski describes [ 8 ] an advanced earth fault protection system. Henninger, Knütter and Schmindel [ 4 ] have also described this protection for generators with brushless exciters. To obtain good monitoring of the field circuit, the earth fault detector uses pilot slip rings continuously

References


[ 2 ] Blackburn, J.L.: "Protective Relaying, Principles and Applica-tions", Marcel Dekker, New York, 1987.


[ 4 ] Henninger, K., Knütter, E.-F. & Schmiedel, K.: "Two-Step RotorEarth-Fault Protection of High Sensitivity for Synchronous Ma-chines", Siemens Power Engineering, vol. 2, no. 1, pp. 13-17,January, 1980.

[ 5 ] Horowitz, S.H. & Phadke, A.G.: "Power System Relaying", Re-search Studies Press and John Wiley & Sons, Taunton and NewYork..., 1992.




GENPC120.DOC 2007-05-22 15.27

[ 8 ] Ungrad, H., Winkler, W. & Wisniewski, A.: "Schutztechnik inElektroenergisystemen. Grundlagen, Stand der Technik,Neuentwicklungen", Springer-Verlag, Berlin..., 1991.


[ 10 ] Wright, A. & Christopoulos, C.: "Electrical Power SystemProtection", Chapman & Hall, London, 1993.



13.1

GENPC130.DOC 2007-05-22 15.28

13. UNDEREXCITATION PROTECTION

One can increase the production of reactive power from a synchronous ma-chine by increasing the excitation current (the rotor current). Now, the ma-chine acts like a shunt capacitor. A synchronous machine can consume re-active power if the excitation current is low enough. In this state, the ma-chine acts like a shunt reactor.

The acceptable limit for overexcitation (reactive production) depends on the prevailing active power generation (consumption). The acceptable limit for underexcitation (reactive consumption) may or may not depend on the active generation (consumption). Figure 1 shows a simplified capability diagram for a synchronous generator. Manufacturers can provide accurate capability diagrams for their generators.

Q

P

CAPABILITY DIAGRAM

Stator Current Limit

Rotor Current Limit

Theoretical Stability Limit

Practical StabilityLimit

Figure 1 Capability diagram for a synchronous machine.

We have plotted the active power, P [MW] along the horizontal axis and the reactive power, Q [Mvar] along the vertical axis. Here, we have assumed that the terminal voltage is equal to the rated voltage. Many capability diagrams have axes scaled in per unit, i.e., P/Sn and Q/Sn where Sn [MVA] is the rated apparent power of the synchronous machine. The rated apparent power, Sn, the rated voltage, Un, the synchronous reactance, Xs, and the power factor (cosϕ) define the acceptable reactive limits in the simplified capability diagram.

The rated apparent power and the rated voltage determine the rated stator current. The stator current may only temporarily exceed the rated

13.2 Underexcitation Protection

GENPC130.DOC 2007-05-22 15.28

current. During steady state, the synchronous machine must not operate outside a circle with a radius equal to 1 per unit.

Let us assume that the active power P is zero. Now, it is not possible to increase the reactive power to the rated apparent power. One cannot reach the limit Q = Sn, because the excitation current becomes too high. It must, however, be possible to operate the machine at P = Sncos(ϕ) and Q = Snsin(ϕ). This determines the requirement on the excitation system and the thermal design of the rotor. The reactive limit given by the highest exci-tation current is also a circle. It passes the point ( P = Sncos(ϕ), Q = Snsin(ϕ)) and has its centre on the negative reactive axes, theoretically at Q/Sn = -1/Xs

13.1 Underexcitation of Synchronous Machines

There are also limits for the underexcitation of a synchronous machine. A reduction of the excitation current weakens the coupling between the rotor and the external power system. The machine may lose the synchronism and starts to operate like an induction machine. Then, the reactive consumption will increase. Even if the machine does not lose synchronism it may not be acceptable to operate in this state for a long time. The underexcitation in-creases the generation of heat in the end region of the synchronous machine. The local heating may damage the insulation of the stator winding and even the iron core.

International standards do not specify limits for underexcitation [ 4 ]. In UK, it is required that a generator should have a full load under reactive consumption that at the power factor, cos(ϕ) = 0.95. In the US all large turbo-generators must operate with reactive consumption at a rated apparent power up to a limit corresponding to a power factor, cos(ϕ) = 0.95. At a power factor equal to zero, the reactive consumption must be about 50% of the rated apparent power, i.e. Q = 0.5Sn. Practically the same requirements are used in Japan. In France, turbo-generators must consume about 35% of the rated apparent power at rated active power, i.e. P = Sncos(ϕ) and Q = -0.35Sn.

13.2 Loss of Excitation

A fault in the Automatic Voltage Regulator (AVR) or in the excitation sys-tem may cause a total loss of excitation. A short circuit on the slip rings will reduce the excitation voltage down to zero. This will cause a gradual reduction of the excitation current and eventually a loss of excitation. An open circuit in the field circuit will also cause a total loss of excitation. The

Underexcitation Protection 13.3

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unwanted opening of the field breaker has caused several losses of excitation in Sweden. When the field breaker is open, high voltage is induced in field winding and there is a risk for damages to the discharge resistor.


Undercurrent relays connected in the field circuit have often been used [ 6 ] for underexcitation protection. According to Mason [ 5 ], the most selective type of underexcitation relay is a MHO-relay excited from the AC current and voltage at the main terminals of the generator.

Walker has described [ 8 ] the underexcitation protection for the hy-dro-generators in the Snowy Mountain Complex. The smaller generators (4 x 80 MW, 4 x 70 MW, 10 x 95 MW and 4 x 138 MW) have a simple DC undercurrent relay fed from a shunt in the main field circuit. This relay gives an alarm after a short delay and it is left to the operator to act appropriately. The larger generators (6 x 250 MW) have a static excitation system while the smaller have a conventional rotating exciter. Here the impedance relay arranged for tripping will supplement the DC alarm relay.

Born and Fischer have documented [ 2 ] the background for the de-sign of an electronic underexcitation relay developed by Siemens. The introduction of generators with brushless exciter made it necessary to energise the underexcitation relay from the stator only. Siemens had to abandon the older approach to use field voltage as one independent criterion. Figure 2 shows the characteristics of the underexcitation relay.

The characteristics are symmetric around the Q-axes (Q = 0) to suit generators in pumped storage plants. One can set the distances from the origin and the slopes individually. The protection system has two tripping criteria with an adjustable time delay. Bär, Grau and Kienast have described [ 3 ] use of such a relay in the pumped storage plant Wehr.

The most reliable underexcitation protection is, according to Sarma [ 7 ], either a MHO-relay or a directional impedance relay with its characteristic in the negative reactance area. Figure 3 shows the tripping characteristics for such a MHO-relay for underimpedance protection.

Lohage and co-workers have described [ 1 ] requirements on under-excitation protection for hydro generating units owned by Vattenfall. They require that all new hydro-generators must have an underexcitation relay. Many generators use a directional overcurrent relay for underexcitation protection. The underexcitation relay shall trip the generator breaker and start the breaker failure protection. Underexcitation cannot occur while the terminal voltage is low if the excitation system operates correctly.


GENPC130.DOC 2007-05-22 15.28

Therefore, the underexcitation protection should use an undervoltage criterion. Underexcitation will not cause a low terminal voltage if the generator is connected to a strong network or if there are several generating units in the power plant. In such a case, the stator current of the faulty generator will increase. Therefore, the underexcitation protection should use an overcurrent relay. Two criteria must be fulfilled before the underexcitation equipment may trip the generator. The first criterion is the directional overcurrent relay has operated. The second criterion is that either the undervoltage relay has operated or the (non-directional) overcurrent protection has operated.

Q/U

P/U

UNDEREXCITATION PROTECTION

Figure 2 Underexcitation protection.

An AIEE working group has prepared and sent out a questionnaire about practice and experience of underexcitation protection. The group has ana-lysed and documented [ 9 ] answers from 63 utilities in the US, Canada and Mexico. The answers represented 309 generators rated at 60 MW or more, installed since 1949. Already 1958, 72% of these generators had underexci-tation protection. Of all utilities, 86% reported that their new generators had underexcitation protection. Most of the underexcitation protections tripped the generator.

The underexcitation relay tripped many generators during the North-east Power Interruption on the 9 November 1965 and during the PJM Sys-tem Disturbance on the 5 June 1967. Many questions were raised concern-ing the correctness of these relay operations and whether they caused or aided the disturbance. The IEEE Power System Relay Committee formed a

Underexcitation Protection 13.5

GENPC130.DOC 2007-05-22 15.28

working group to investigate and report on the performance of underexcita-tion protection during system disturbances. The report [ 10 ] outlines the re-sults of the working group study and points out areas where further work may be required.

During the first disturbance, underexcitation relays tripped 16 turbo-generators. Out of 193 units, 102 had an underexcitation relays all installed to trip. These represent 81.8% of the system gross capability. The 16 units tripped by the underexcitation relays represent 16.1% of the system gross capability. Only one of the 16 units tripped by the underexcitation had a voltage regulator in service. During the second disturbance, the underexcitation relays tripped a total of 12 units or 28.4% of the total system capacity. Only four of the 12 units tripped by the underexcitation relays had their voltage regulator in service. The working group concluded that 52 relay operations out of 68 were correct. There were 4 unwanted operations and 4 missing operations. The working group could not determine if the other 8 operations were correct or not.

X

R

MHO-Relay Used forUnderexcitation Protection

Practical Stability Limit

Theoretical Stability Limit

Tripping Chatacteristic

Figure 3 MHO-relay for underexcitation protection.


GENPC130.DOC 2007-05-22 15.28

References


[ 2 ] Born, E. & Fischer, A.: "Elektronischer Untererregungsschutz",Siemens-Zeitschrift, vol. 46, no. 12, pp. 912-915, December,1972.


[ 4 ] Glebov, I.A., Danilevich, J.B. & Mamikoniants, L.G.:"Abnormal Operation Conditions of Large SynchronousGenerators and their Influence on Design and Performance in aPower System", Report 11-07, CIGRE-Session, Paris, 1976.

[ 5 ] Mason, C.R.: "A New Loss-of-Excitation Relay for SynchronousGenerators", AIEE Trans., vol. 68, pt. II, pp. 1240-1245, 1949.




[ 9 ] "A Partial Survey of Relay Protection of Steam-Driven A-CGenerators", AIEE Committee Report, AIEE Trans., vol. 81, pt.III (Power Apparatus and Systems), pp. 954-957, February,1962.

[ 10 ] "Loss-of-Field Operation During System Disturbances", IEEECommittee Report, IEEE Trans. on Power Apparatus and Sys-tems, vol. PAS-94, no. 5, pp. 1464-1472, September/October,1975.#

14.1

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14. OVERVOLTAGE PROTECTION

The excitation system must have a capacity that makes it possible to operate the unit at full load. The associated excitation current is much higher than the current needed to reach rated voltage at rated speed with an unloaded generator. At full load, the excitation current may be 200 to 300% of the excitation current at no load. To improve the response of the excitation system many exciters can increase the field voltage to about 600% of the field voltage at no load.

Let us assume that the operator is starting a unit, the rotational speed of the unit is higher than 90% of nominal speed. The operator has not yet synchronised the generator to the network. Now, the automatic voltage regulator (AVR) controls the terminal voltage of the unit. There are several contingencies that may cause a dangerous voltage increase. Such contingencies include a fault in the exciter, a fault in the AVR itself, a short circuit in the secondary circuit that energises the AVR or an open circuit in the secondary circuit that energises the AVR. Such contingencies may increase the excitation far beyond the excitation current at no load. This will cause a terminal voltage that is higher than acceptable.

After synchronisation, the external power system has a dominating influence on the terminal voltage. Commonly, the capacity of a given generator is small in comparison with the capacity of the external power system. This means that a fault in the AVR cannot alter the terminal voltage substantially while the generator is operating in synchronism with an intact network.

The terminal voltage will start to increase rapidly if a fully loaded generator becomes disconnected from the network. Usually, the AVR will reduce the terminal voltage and it will eventually approach 100%. The contingencies mentioned above may cause a terminal voltage that is higher than acceptable. Some units do not have an AVR or the operator may have switched over from automatic voltage regulation to manual excitation control. All these contingencies may cause an unacceptable terminal voltage. The overvoltage will be even higher if the generator feeds unloaded transmission circuits. Long overhead lines and power cables, with large capacitive generation, worsen the situation.

The terminal voltage will increase even more if the load rejection causes an increase of the rotational speed of the unit. The speed of a turbo-generator must not increase over 112 to 115%. In hydro-power plants, the speed increase may be much higher. This may happen if the unit does not have any turbine governor, if the turbine governor is slow or if the operator has switched over to manual speed control. In the worst case, the speed of

14.2 Overvoltage Protection

GENPC140.DOC 2007-05-22 15.28

the hydro-generator may approach the runaway speed of the hydro turbine. The runaway speed of a Francis turbine is about 150 to 200% of nominal speed. For a Kaplan turbine, the runaway speed is about 200 to 300%. One has to remember that the induced EMF is proportional to the product of the rotational speed and airgap flux. The flux is approximately proportional to the excitation current.

In EHV transmission systems, a load rejection at the receiving end of a long transmission line may cause too high voltages even if the AVR and the turbine governor at the sending end operate correctly.

The core material in modern power transformers will saturate if the applied voltage is higher than 110 to 125% at rated frequency. A saturating transformer will reduce the overvoltage because the excitation current to the transformer will increase. The saturated magnetisation impedance may decrease to 0.1% of the unsaturated value. Unfortunately, the flux in a saturated transformer may reach magnetic objects outside the iron core. Eddy current losses may very rapidly increase the temperature of such objects. Such hot objects may also increase the temperature of the oil in the transformer tank and increase the risk for dielectric failures. Such a situation may occur during start-up and shutdown of unit-connected generators. There is a risk that the operator switches over to automatic voltage regulation before the rotational speed has reached 90% of rated speed. He may also forget to switch over to manual excitation control during a shutdown of the unit.

Tideström recommends [ 4 ] a dependent time overvoltage relay for overvoltage protection. Such a relay has a short delay if the overvoltage is very high. The delay increases with decreasing overvoltage.

The overvoltage protection system for the generators in the Snowy Mountain Complex comprises, according to Walker [ 5 ] an overvoltage relay and a timer. The overvoltage relay picks up if the voltage is higher than 130% of rated voltage. The time delay is 2 s.

The overvoltage protection system should, according to Sarma [ 3 ], have two steps if the generator does not have an AVR. In thermal power plants the first step should pick up if the voltage exceeds 125%. For hydro power plants, the corresponding figure is 140%. The first step should trip without delay. The second step should pick up if the voltage is higher than 110% and should have a dependant time characteristic.

The synchronous machines in the pumped storage plant Wehr have, according to Bär, Grau and Kienast [ 2 ], an overvoltage protection system comprising a frequency compensated overvoltage relay and a timer. The overvoltage relay picks up if the voltage is higher than 120% of rated power. The time delay is 3 s.

Overvoltage Protection 14.3

GENPC140.DOC 2007-05-22 15.28

Hydro-power units owned by Vattenfall should, according to Lohage and co-workers [ 1 ] have an overvoltage protection system. It should comprise an overvoltage relay and a timer. The overvoltage relay should pick up if the voltage is higher than 120% of rated power. The time delay should be about 1 second.

Most generators have two sets of voltage transformers. One set comprises three single-phase transformers and it energises the protection equipment and the AVR. The second set may comprise only two single-phase voltage transformers. This set energises the overvoltage protection system. It is necessary to use two sets of voltage transformers because otherwise the overvoltage protection system and the AVR do not have independent input sources. Usually, a phase-to-phase voltage energises the overvoltage protection system to avoid unwanted operation at single phase-to-earth faults.

One may supplement the overvoltage protection system by an overexcitation protection system. The energising quantity of the overexcitation relay is the quantity U/f [V/Hz]. Unit-connected turbo-generators need such a relay to protect the step-up transformer. Incidents have occurred during start-up and shutdown. Occasionally, the AVR was in service while the rotational speed was well below rated speed. This caused overexcitation of the step-up transformer and sometimes damage to it. Once the overall differential protection detected the abnormal situation. The step-up transformer became saturated and the differential relay operated because of the excitation current of the transformer.

14.4 Overvoltage Protection

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References






15.1

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15. REVERSE POWER PROTECTION

The task of a generator in a power plant is to convert mechanical energy available as a torque on a rotating shaft to electric energy. One exception is a reversible unit in a pumped storage plant. During light load conditions, they consume electric power and store it as potential energy. During peak load conditions, those generators operate as normal hydro power units.

Sometimes, the mechanical power from a prime mover may decrease so much that it does not cover bearing losses and ventilation losses. Then, the synchronous generator becomes a synchronous motor and starts to take electric power from the rest of the power system. This operating state, where individual synchronous machines operate as motors, implies no risk for the machine itself. If the generator under consideration is very large and if it consumes lots of electric power, it may be desirable to disconnect it to ease the task for the rest of the power system.

Often, the motoring condition may imply that the turbine is in a very dangerous state. The task of the reverse power protection is to protect the turbine and not to protect the generator itself. Generally, AC current and voltage energise the reverse power protection system and it trips the generator breaker. Therefore, one includes the reverse power protection in the generator protection.

Steam turbines easily become overheated if the steam flow becomes too low or if the steam ceases to flow through the turbine. Therefore, turbo-generators should have reverse power protection. Neugebauer [ 3 ] mentions several contingencies that may cause reverse power. One is a break of a main steam pipe. A second is a damage to one or more blades in the steam turbine. The third is an inadvertent closing of the main stop valves. In the last case, it is highly desirable to have a reliable reverse power protection. It may prevent damage to an otherwise undamaged plant.

During the routine shutdown of many thermal power units, the reverse power protection gives the tripping impulse to the generator breaker (the unit breaker). By doing so, one prevents the disconnection of the unit before the mechanical power has become zero. Earlier disconnection would cause an acceleration of the turbine generator at all routine shutdowns. This should have caused overspeed and high centrifugal stresses.

When the steam ceases to flow through a turbine, the cooling of the turbine blades will disappear. Now, it is not possible to remove all heat generated by the windage losses. Instead, the heat will increase the temperature in the steam turbine and especially of the blades. When a steam turbine rotates without steam supply, the electric power consumption will [ 6 ] be about 2% of rated power. Even if the turbine rotates in vacuum, it

15.2 Reverse Power Protection

GENPC150.DOC 2007-05-22 15.29

will soon become overheated and damaged. The turbine overheats within minutes if the turbine loses the vacuum. Steam turbines may eventually, according to Mason [ 2 ], become overheated if the steam flow is so low that the electrical power generation falls below 10%.

The critical time to overheating of a steam turbine varies, according to Mason [ 2 ], from about 0.5 to 30 minutes depending on the type of turbine. A high pressure turbine with small and thin blades will become overheated more easily than a low pressure turbine with long and heavy blades. The conditions vary from turbine to turbine and it is necessary to ask the turbine manufacturer in each case. It is also prudent to measure the reverse power during commissioning of new units.

Power to the power plant auxiliaries may come from a station service transformer connected to the primary side of the step-up transformer. Power may also come from a start-up service transformer connected to the external network. One has to design the reverse power protection so that it can detect reverse power independent of the flow of power to the power plant auxiliaries.

Hydro turbines tolerate reverse power much better than steam tur-bines do. According to Lohage and co-workers [ 1 ], only Kaplan turbine and bulb turbines may suffer from reverse power. There is a risk that the turbine runner moves axially and touches stationary parts. They are not al-ways strong enough to withstand the associated stresses.

Ice and snow may block the intake when the outdoor temperature falls far below zero. Branches and leaves may also block the trash gates. A complete blockage of the intake may, according to Mason [ 2 ] cause cavitation. The risk for damages to hydro turbines can justify reverse power protection in unattended plants. According to GEC [ 7 ], geared units may require reverse power protection. This is because the design of the gears is for driving in one direction only.

A hydro turbine that rotates in water with closed wicket gates will draw electric power from the rest of the power system. This power will be about 10% of the rated power. If there is only air in the hydro turbine, the power demand will fall to about 3%. It is prudent to measure these values during the commissioning.

Diesel engines should, according to Mason [ 2 ] have reverse power protection. The generator will take about 15% of its rated power or more from the system. According to GEC [ 7 ], a stiff engine may require perhaps 25% of the rated power to motor it. An engine that is well run in might need no more than 5%. According to Sarma [ 4 ], diesel engine units usually require reverse power protection with a setting of 15 to 25%. It is

Reverse Power Protection 15.3

GENPC150.DOC 2007-05-22 15.29

necessary to obtain information from the engine manufacturer and to measure the reverse power during commissioning.

Gas turbines usually do not require reverse power protection. The power required to motor a gas turbine varies, according to Mason [ 2 ], from 10 to 50% of rated power. It depends on the turbine design and whether it has a separate load turbine.

A reverse power relay and a timer can provide adequate reverse power protection. The reverse power relay can be a directional undercurrent relay that measures the current that flows from the generator to the network (an underpower relay). It may also be a directional overcurrent relay that measures current that flows from the network to the generator (an over-power relay). There are few sensitive current relays that also can withstand the normal load current continuously. The relay must also temporarily withstand the fault current that may flow through the relay. The setting range of the timer should be from a few seconds to some minutes.

Figure 1 illustrates the properties of reverse power protection with underpower relay and with an overpower relay. The underpower relay gives a higher margin and should provide better dependability. On the other hand, the risk for unwanted operation immediately after synchronisation may be higher. One should set the underpower relay to trip if the active power from the generator is less than about 2%. One should set the overpower relay to trip if the power flow from the network to the generator is higher than 1%.

OperateLine

OperateLine

Margin Margin

Underpower Relay Overpower Relay

Operating pointwithoutturbine torque

Operating pointwithoutturbine torque

Q Q

P P

Figure 1 Characteristics of the reverse power protection.


GENPC150.DOC 2007-05-22 15.29

There is a risk that the generator breaker does not open on command from the reverse power relay. Now, we are in danger. It is futile to start the breaker failure protection from the reverse power relay. The operate value of the breaker failure protection is usually higher than the operate value of the reverse power relay. There is only a remote possibility that the breaker failure relay will detect that the generator breaker has failed to open.

Let us consider a unit with a generator breaker on the primary side of the step-up transformer. It has a unit breaker on the secondary side of the step-up transformer. We can increase the dependability of the reverse power protection by installing two reverse power relays. Two different sets of instrument transformers should energise the reverse power relays. The two reverse power relays should have approximately the same pick up value. One reverse power relay should have a shorter delay than the other. The first reverse power relay should trip the generator breaker and the second relay should trip the unit breaker. With this, we can avoid necessary interruption of the supply of auxiliary power through the step-up transformer.

The demands on the reverse power protection are increasing. An AIEE report [ 8 ] says that the reverse power relays may only give an alarm immediately when power flows from the network to the generator. The re-verse power relay should trip if the power reversal persists long enough to cause damage to the turbine from overheating. A delay of at least one minute will be permissible between the time when the power reversal starts and tripping should occur.

An IEEE report [ 8 ] does not recommend any dedicated reverse power protection. The interlocking system can provide certain reverse power protection.

GEC points out [ 7 ] that the reverse power relay must detect active power. The reactive power will not change very much when the active power reverses. The reactive power seldom exceeds 60% of rated power. This means that the phase angle between current and voltage may be as high as 85o and may be either inductive or capacitive. This illustrates the difficulties when designing a suitable reverse power relay. GEC also mentions that there are sensitive three-phase power relays with a sensitivity of about 0.5%.

According to Lohage and co-workers [ 1 ] the reverse power relay must pick up if the active power from the network to the generator exceeds 2% of the rated power. They say that, the delay of should be from five to 10 seconds, depending on the type of turbine.

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References



[ 3 ] Neugebauer, H.: "Selektivschutz", Springer-Verlag, Berlin,1955.


[ 5 ] "Minimum Recommended Protection, Interlocking and Controlfor Fossil Fuel Unit-Connected Steam Station. I - OverallProtection", IEEE Committee Report, IEEE Trans. on PowerApparatus and Systems, vol. PAS-92, no. 1, pp. 374-380,January/February, 1973.

[ 6 ] "Power System Protection", vol. 1, 2 and 3, Application, Editedby the Electricity Council, Peter Peregrinus, Stevenage, 1981.




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16.1

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16. UNBALANCE PROTECTION

Single-phase loads, series faults and unsymmetrical faults may cause con-tinuous and temporary unbalance loading of a synchronous machine. If the unbalanced loading is too high and persist too long, the rotor of the machine will overheat and become damaged. A three-phase generator carries a balanced load if the stator phase currents are:

a

b

c

I = I (2 f - 03

)

I = I (2 f - 23

)

I = I (2 f - 43

)

sin

sin

sin

π π

π π

π π

( 1 )

and the phase-to-earth stator voltages are:

a

b

c

V = V (2 f - 03

+ )

V = V (2 f - 23

+ )

V = V (2 f - 43

+ )

sin

sin

sin

π π ϕ

π π ϕ

π π ϕ

( 2 )

16.1 Unbalanced loading

The generator carries an unbalanced load if equation ( 1 ) and ( 2 ) do not hold true. Unbalanced loading is not a very well defined concept. It is also difficult to describe how unbalanced loading will increase the stresses that the generator has to endure. A better description is the relative amount of negative sequence current, I2/In that the generator carries. The negative sequence current, I2 is:

2a

2b cI = I + a I + a I

3 ( 3 )

and In is the rated stator current of the machine. The relative negative se-quence current is therefore well defined and one can measure it.

16.2 Unbalance Protection

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16.1.1 Causes of Unbalanced Loading

Unbalanced loading may produce more severe heating than balanced three-phase operation. Series faults close to the generator will cause negative se-quence currents. Unsymmetrical faults may produce more severe heating in three-phase synchronous machines than symmetrical faults. Typical condi-tions and incidents that can cause unbalanced loading are: • Single-phase loads close to the power plant. • Untransposed transmission circuits. • Unbalanced step-up transformers. • Series faults in the transmission network. • Series faults on the secondary side of the step-up transformer. • Series faults on the primary side of the step-up transformer. • Pole discrepancy in the generator breaker. • Unbalanced shunt faults close to the power plant. • Unbalanced shunt faults on the generator buswork.

16.1.2 Consequences for the Generators

A synchronous machine overheats quite rapidly if it carries even low nega-tive sequence currents. The negative sequence current generates a stator-MMF that rotates with the same speed as the rotor but in the opposite direc-tion. Seen from the rotor, this MMF has a frequency 2fn, where fn is the power frequency (50 or 60 Hz). This MMF induces voltages with a fre-quency 2fn in the rotor and its windings.

These voltages cause currents to flow in the rotor and associated windings. Due to the skin effect, these currents flow close to the surface of metallic objects in the rotor. The penetration depth in magnetic steel is less than one millimetre at 50 Hz. These currents heat will quickly the rotor body, the slot wedges, the retaining ring and the damper winding if there is one. These components are normally already under great stress in large turbo-generators. If the negative sequence current persists, the metal will melt and damage the rotor structure.

The amount of negative sequence current that the machine can tolerate depends on the design of the generator.

16.1.3 Turbo-Generators

Generators without damper winding do not have well-defined paths for the induced double frequency currents. The electromagnetic and thermal

Unbalance Protection 16.3

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utilisation increases steadily. This is especially true for the rotors in turbo-generators. This means that the turbo-generators are very sensitive for unbalanced loading. Much development work has been done and will be done to improve the unbalance loading capability. One has to pay special attention to the material of the slot wedges. When the conductivity of the slot wedges is higher than the conductivity of the rotor body, most of the induced double frequency currents will flow in the slot wedges. In several modern generators, the slot wedges do not have electrical contact with each other. This means that the current will flow from slot wedges to the rotor and back again. This will cause severe local heating. The general opinion is that it is important to secure good electrical contact between the slot wedges and the rotor body.

16.1.4 Hydro-Generators

Salient pole generators with Damper windings (hydro-generators) have well-defined paths for the induced double frequency currents. The currents flow mainly in the damper windings. Generally, hydro-generators have strong damper windings and they can withstand higher negative sequence currents than turbo-generators can. There are very few hydro-generators without damper windings.

16.2 Continuous I2-capability

Because unbalanced loading may continue for long periods, each machine is assigned a continuous negative sequence current capability (continuous I2-capability). Usually it is expressed in percent of the rated stator current.

Table 1 shows typical continuous negative sequence current capability for generators with different forms of cooling [ 7 ].

Most countries support [ 3 ] the American suggestion concerning continuous I2-capability. Table 2 contains the suggested capability.

The machine manufacturers can provide more accurate values.


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Table 1 Negative sequence current capability.

Type of machine Type of cooling (I2)max K and cooling medium % s Turbo generator Direct hydrogen 30 lb/in2 10 7 Turbo generator Conventional hydrogen 30 lb/in2 15 12 Turbo generator Conventional hydrogen 15 lb/in2 15 15 Turbo generator Conventional hydrogen 0.5

lb/in2 15 20

Typical salient pole machine Conventional air 40 60

Table 2 Suggested continuous I2-capability.

Cooling Method Sn I2,max MVA %

Indirect cooled 10 Direct cooled

-"- <960 8 -"- 961-1200 6 -"- >1200 5

16.3 Temporary I2-capability

The synchronous machine may carry large negative sequence currents during fault conditions. Because normal fault clearance times are short, only little heat is lost by the machine while the fault currents are present. In addition, it is the heating caused by these currents that may cause damage and therefore it is the input energy that must be limited. This means that we have to define a temporary negative sequence current capability (temporary I2-capability). The length of time, T [s] that a machine can operate with negative sequence current without danger of being damaged can be expressed in the form:

0T

22 i (t) dt = K∫ ( 4 )

where: i2

2(t) = the instantaneous negative sequence current as a function of time; the current is expressed in per unit based and


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K = a constant.

The generator can withstand a constant negative sequence current, I2 [A], during a period, T [s], given by the equation:

T = K II

2n

2

⎛⎝⎜

⎞⎠⎟

( 5 )

where In = the rated current of the generator [A] and K = a constant [s] that is typical for the type of generator.

The constant K tells us how many seconds the machine can withstand a negative sequence current equal to the rated current of the generator. The constant K depends on the size of the generator and the method of cooling. For most generators the value is from 5 to 30 s, but for some hydro-genera-tor it may be as high as 60 s.

There are industry standards that determine the permissible unbalance to which a generator is designed [ 4 ]. For turbo-generators with Sn ≤ 800 MVA the requirement is:

K 10≥ ( 6 )

and for Sn>800 MVA, the requirement is:

K 10 - 0.00625(800 - S )n≥ ( 7 )

Figure 1 shows these requirements in graphical form. For example, a 500 MVA generator would have K = 10 s and a

1 600 MVA generator would have K = 5 s. Figure 2 shows data on the negative sequence current capability.


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0 500 1000 1500 2000

15

10

5

0

Rated Apparent Power, S [MVA]

NEGATIVE SEQUENCE CURRENT CAPABILITY

K [s]

K = 10 - 0.00625*( S - 800 )

Figure 1 Negative sequence current withstand capability.

0.01 0.10 1.00 10.01

10

100

1000

10000

Negative Sequence Current [ pu ]

NEGATIVE SEQUENCE CURRENT CAPABILITY

High K

Low K

High I2max

Low

I2m

ax

Max

imum

Tim

e [

s ]

Figure 2 Maximum time for a given negative sequence current.


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The ability of large generators to stand negative sequence current is becom-ing progressively less because their specific rating is still increasing although their size has almost reached the limit of present material.


Generally, the unbalanced protection consists of a dependent time overcur-rent relay. A negative sequence filter energises the overcurrent relay. On a log-log scale, the time characteristic is a straight line and can be set to match the machine characteristic.

In 1953, Barkle and Glassburn suggested [ 2 ] that synchronous gen-erators should have a negative sequence protection with dependent time characteristic. They documented the fact that the heating caused by a phase-to-phase short circuit on the generator terminals was nine times higher than the heating caused by a three-phase short circuit on the generator terminals. The report contains a description of a new negative sequence current relay . It is suitable for generators with K in the interval 30 to 90 s.

Synchronous generators should, according to Mason [ 5 ], have a negative sequence current relay with dependent time characteristic. The negative sequence current relay should trip the generator. Mason points out that the relay will seldom operate on external unbalanced faults. The unbal-ance protection can be justified as a protection against series faults. It can also be justified as aback up protection against external unbalanced shunt faults.

An AIEE working group has prepared and sent out a questionnaire about practice and experience of underexcitation protection. The group has analysed and documented [ 6 ] answers from 63 utilities in the US, Canada and Mexico. The answers represented 309 generators rated at 60 MW or more, installed since 1949. In 1958, 40% of these generators have negative sequence protection. Then, 70% of the utilities installed negative sequence protection on new generators.

The new hydro power stations owned by Vattenfall will, according to Lohage and co-workers [ 1 ], have a negative sequence current relay with dependent time characteristic. They point out that the relay can detect pole discrepancy in the generator breaker.

It is not uncommon, according to Horowitz and Phadke [ 4 ], to apply negative sequence relays on the generator to alarm first, alerting the operator to the abnormal situation and allowing corrective action to be taken before removing the machine from service.


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References


[ 2 ] Barkle, J.E. & Glassburn, W.E.: "Protection of GeneratorsAgainst Unbalanced Currents", AIEE Trans., vol. 72, pt. III(Power Apparatus and Systems), pp. 282-286, April, 1953.

[ 3 ] Glebov, I.A., Danilevich, J.B. & Mamikoniants, L.G.:"Abnormal Operation Conditions of Large SynchronousGenerators and their Influence on Design and Performance in aPower System", Report 11-07, CIGRÉ-Session, Paris, 1976.

[ 4 ] Horowitz, S.H. & Phadke, A.G.: "Power System Relaying", Re-search Studies Press and John Wiley & Sons, Taunton and NewYork..., 1992.




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17. OUT OF STEP PROTECTION

Many utilities have adopted reliability principles for the planning and operation of their bulk power system. They use the principles when making decisions on investments in power plants and transmission systems. The system operators use the system when deciding on transfer limits and when planning outages. The design principles often prescribe the tolerable consequence of a set of contingencies but they may vary from utility to utility. The set of contingencies may include: • A loss of a large generating unit. • An inadvertent tripping of a circuit breaker. • A shunt fault on a transmission line. • A shunt fault on a busbar

Often, the utilities do not tolerate loss of synchronism because of such con-tingencies. Sometimes a utility may decide to delay investments and tempo-rarily deviate from the reliability principles.

Severe stresses may result when a generator loses the synchronism without having lost the excitation. Pole slipping is associated with high cur-rent pulses and violent oscillations of the air gap torque in the generator.

Mason says [ 3 ] that it is not likely to lose synchronism with other generators in the same station unless it loses excitation. Many units have underexcitation protection. He concluded that it is not the usual practice to provide out of step protection.

Synchronism can, according to GEC [ 4 ], be regained if the load is sufficiently reduced, but if this does not occur within a few seconds it is necessary to isolate the generator and then re-synchronise.

During the planning of the power plant Abwinden-Asten on the River Danube, it was necessary to consider the long fault clearance time in the connecting network. Each generating unit has a bulb turbine and the turbine generator units have a low inertia constant. The low inertia constants and the long fault clearance times made it necessary to install an out of step protection. ELIN has, according to Dorfmeister [ 2 ], developed an out of step protection. He does, however, not describe the method for detection of pole slipping clearly. Static and dynamic estimation of the rotor angel is a key task of the protection.

Hydro-generators owned by Vattenfall must not have out of step pro-tection [ 1 ]. Some nuclear units in Sweden have a simple out of step pro-tection. It comprises an overcurrent relay and some associated logic. After three consecutive overcurrent pulses, it trips the unit.

17.2 Out of Step Protection

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References


[ 2 ] Dorfmeister, K.: "Betrieb und Erfahrung mit einem neuartigenStabilitätsschutz in der Mikroprozessortechnik", ELIN-Zeitschrift, vol. 34, no. 3/4, pp. 58-61, 1982.



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18. ABNORMAL FREQUENCY PROTECTION

Abnormal frequency is related to abnormal speed of the generating units. A single failure in the power plants will usually not cause abnormal speed de-viations if the power system is a large and stable one. However, if the sys-tem is a small isolated one with large generating units, the loss of one unit may cause a big power deficit. Then, the system frequency begins to fall and may reach so low values that it becomes necessary to disconnect other units. Faults in the network may occasionally split a large power system into small electrical islands. Such islands may have a big power surplus or a big power deficit. Here, there is a risk for abnormal frequencies. There are cases on record where a subsystem established a balance at 50% of normal system frequency and 50% of normal network voltage. Now, the on-line tap changers started to move and eventually they reached their extreme positions. Then, the system operator closed a circuit-breaker and reconnected the subsystem. The voltage level on the power network became normal. The consequence of the disturbances was that customer equipment became damaged by overvoltage during the service restoration process.

18.1 Aims of the Abnormal Frequency Protection

The frequency control system shall provide the first line of defence against abnormal frequency. A load shedding system provides the second line of defence. Then, the abnormal frequency protection provides a last defence line. One task is to prevent operation of customer loads at abnormal frequencies. The Swedish Electrical Safety Regulations require that the utility shall prevent changes in network voltage and system frequency that may present danger to the customers. Another task of the abnormal frequency protection is to prevent damage to power plant equipment.

Some utilities use an underfrequency relay to trip generating units to houseload when a widespread blackout has occurred. The idea is to have the generating units in a hot standby state and ready for synchronisation. When the network operator has voltage restored the transmission system, new generation will become available with a minimum of time delay. Such actions aim at reducing the customer interruption times instead of preventing loss of voltage.

Automatic switching of circuit breakers on abnormal frequency may ease the service restoration. Some utilities believe that the service restora-tion process will run faster and smoother if they can energise several dead subsystems instead of synchronising an electrical island.

18.2 Abnormal Frequency Protection

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There are two major considerations associated with operating power plants at abnormal system frequency: • Protection of equipment from damage. • Prevention of cascading trips that lead to a complete blackout

18.2 Effects of Abnormal Frequency

There are no standards for abnormal frequency operation of synchronous generators. Reduced frequency results in reduced ventilation. Therefore, operation at reduced frequency should be at reduced apparent power. The underfrequency limitations on the generator, however, are usually less restrictive than the limitations on steam turbines. Overfrequency is usually the result of a sudden load reduction. Therefore overfrequency is associated with light-load or no-load operation of the generator. Operation within the allowable overfrequency limits of the turbine will not produce generator overheating as long as operation is within rated apparent power and 105% of rated voltage.

Abnormal frequency present hazards to other parts of the plant such as: • Steam turbine vibrations and increased stresses on blades. • Reduced capacity of auxiliary equipment • High temperatures caused by increased excitation current • Overexcitation of transformers

18.3 Co-ordination with Load Shedding

The aim of the frequency controlled load shedding is to re-establish a bal-ance between available generation and load by disconnecting load when the system frequency drops below certain levels. The amount of load shedding varies from country to country and from region to region. Typical values range from 20 to 60% of system load. Experience has shown that the load shedding system may not always prevent underfrequency. Then, one needs the abnormal frequency protection to prevent damage to power plant equip-ment and especially steam turbines.

18.4 Realisation of Abnormal Frequency Protection

All prime movers should have overspeed protection. The overspeed device may be a mechanical centrifugal device or an overfrequency relay. Varia-tions in generator voltage must not adversely affect the overfrequency

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relay. Mechanical centrifugal devices may be difficult to adjust and it is common practice to test them every year after maintenance outage periods. It is easier to test overfrequency relays and they may reduce the start-up time after maintenance outage.

The setting of the overspeed device may be 108 to 115% for turbo-generators and 140 to 160% for hydro turbines.

The overspeed protection may be a part of the prime mover, or of its speed governing system, or of the generator protection. The overspeed ele-ment should operate the main stop valve to shut down the prime mover. It should also trip the generator circuit breaker and the auxiliary breaker where auxiliary power comes from the generator buswork. By doing so, it is possible to prevent overfrequency operation of customer loads and power plant auxiliaries.

The overspeed element should usually operate at 3 to 5% above full-load rejection speed.

The underfrequency protections often have two steps. One frequency relay trips the unit breaker without delay if the system frequency falls below 95%. Another frequency relay trips the unit if the frequency does not recover.

The aim of the frequency controlled load shedding is to cause the system frequency to return to normal before it becomes necessary to trip the generating units.

18.4 Abnormal Frequency Protection

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19.1

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19. INADVERTENT ENERGISING PROTEC-TION

Operating errors, breaker head flashovers, control circuit malfunctions, or a combination of these have resulted in inadvertent or accidental energising of off-line generators [ 2 ]. Many large generators have been severely dam-aged, sometimes, beyond repair [ 1 ]. This section is entirely based on reference [ 1 ] and [ 2 ].

19.1 Inadvertent Energising

Operating Errors: The use of more complex breaker patterns has resulted in more frequent operating errors. Even with extensive interlocks between unit breakers and disconnecters, there has been an increase in the number of documented cases in which off-line units have been inadvertently energised through the high voltage switch.

Breaker Head Flashover: The extreme dielectric stress in breakers and the small contact gap spacing associated with their high-speed interrupting re-quirement can lead to contact flashover. The risk of a flashover is higher just before synchronisation or just after the unit is removed from service.

19.2 Generator Response to Inadvertent Energising

Three-Phase Energising: When a generator is accidentally energized with three-phase system voltage while at low speed, it behaves like an induction motor. If the generator is connected to a strong network, the stator current will be about 3 to 4 times rated current.

Single-Phase Energising: Single-phase energising of a generator from the high voltage system while at low speed subjects the generator to a signifi-cant unbalance current. There will be no significant accelerating torque if the voltage applied to the generator is single-phase. Breaker head flashover is the most frequent cause of single-phase inadvertent energising.

19.3 Damage Caused by Inadvertent Energising

Turbo-Generator Damage: The initial effect of inadvertent energising of a generator from standstill is rapid heating in iron parts near the rotor surface. Slot wedges have little clamping load at standstill, resulting in

19.2 Inadvertent Energising Protection

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arcing between them and the rotor iron. The arc heating begins to melt the metals.

Steam Turbine Damage: During an inadvertent energising incident, the generator acts as a motor to drive the turbine. The generator starts to accel-erate the turbine and the exciter. As it comes up to speed, the unit passes through its natural torsional frequencies. Vibration, blade distortion and rubbing may cause turbine damage if the energising source is not removed soon enough. The blades in the steam turbine may become overheated if the turbine continues to rotate at high speed without any steam flow. Bearing failure due to insufficient lubrication can occur.

Hydro Unit Damage: Heating of the damper windings and the rotor mate-rial, combined with the lack of proper ventilation, will create damage quickly.

19.4 Systems to Detect Inadvertent Energising

Although the normal generator protection may detect some cases of inadvertent generator energising, dedicated protection systems are recommended to detect inadvertent energising. Unlike conventional protection systems that provide protection when equipment is in service, these new schemes provide protection when equipment is out of service. The most widely used dedicated protection systems are:

Frequency Supervised Overcurrent Relays: This system uses a frequency relay to supervise the trip output of sensitively set instantaneous overcurrent relays. The overcurrent relays are automatically armed by the frequency relay as the unit is taken off-line and they remain armed while the unit is shut down.

Voltage Supervised Overcurrent Relays: This system utilises undervolt-age relays to supervise the trip output of high-speed instantaneous overcur-rent relays. The overcurrent relays are automatically armed by separate un-dervoltage relays when the unit's field is de-energised and they remain armed while the unit is shut down.

Auxiliary Contact Enabled Overcurrent Relays: This system uses a combination of auxiliary contacts on breakers and switches to enable and disable high-speed instantaneous phase overcurrent relays.

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Distance Relays: This scheme uses a distance relay located in the high-voltage switchyard that is set to look into the machine. The relay should be set to detect the sum of the generator step-up transformer and machine transient reactance with an appropriate margin.

Directional Overcurrent Relays: This scheme uses three directional phase overcurrent relays with very inverse time characteristics. Voltage sensing is from the generator such that the overcurrent relays will pick up on current into the generator.

19.5 Schemes to Detect Breaker Head Flashover

Some dedicated schemes, described above for inadvertent energising ,can detect breaker head flashover. However, the following schemes are widely used to detect breaker head flashover in the generator breaker or in the unit breaker.

Modified Breaker Failure Scheme: An instantaneous overcurrent relay is connected in the neutral of the step-up transformer. The relay is set to re-spond to a breaker pole flashover. The breaker gets a starting impulse when the relay while an auxiliary contact indicates that the circuit breaker is open.

Breaker Pole Disagreement: A current relay augments the conventional breaker pole disagreement scheme. This relay senses whether any phase is below a certain low threshold level (indicating an open breaker pole) while that another phase current is above a substantially higher threshold level (indicating a closed or flashed-over pole). Operation of the disagreement circuitry initiates breaker failure tripping.

19.6 Conclusion

American utilities have observed that inadvertent energising of large generators has significantly increased in recent years as generating stations have become more complex. Operating errors, breaker head flashover, control circuit malfunctions or a combination of these causes have resulted in generators becoming accidentally energized. Major US turbine-generator manufacturers have recommended, and many utilities are installing, dedicated inadvertent energising protection systems.

19.4 Inadvertent Energising Protection

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References

[ 1 ] "Inadvertent Energizing Protection of Synchronous Generators",IEEE Committee Report, IEEE Trans. on Power Delivery, vol. 4,no. 2, pp. 965-977, April, 1989.

[ 2 ] "Impact of HV and EHV Transmission on Generator Protection",IEEE Committee Report, IEEE Trans. on Power Delivery, vol. 8,no. 3, pp. 962-974, July, 1993.

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20. BEARING CURRENT PROTECTION

The oil film of the bearings in a generating unit provides some insulation between the rotor and the stator. There is a risk that shaft voltages cause an electrical breakdown of these oil-films. Then, bearing currents start to flow and their sizes depend on the shaft voltage and the loop impedance. An electric current that flows through the oil film of a bearing in rotating ma-chines can cause serious damage.

20.1 Shaft Voltages

There are several sources that may cause voltages in the shafts of turbine generator units. Both the waveform and the size of the voltage depend on the type and the size of the machine and they also vary with the loading. The most important shaft voltage sources are [ 1 ] and [ 3 ]:

Magnetic Unsymmetries: The generator itself creates the most important shaft voltage that may cause damage. One cause of this phenomenon is due to asymmetries in the magnetic circuit of the stator. The net dissymmetry links the rotor shaft and it induces a shaft voltage. It is rich in harmonics. Further causes are eccentrically mounted rotors and rotor sag. These sources are strong because they have low source impedance and can drive high currents that are limited only by the circuit impedance.

Axial Shaft Flux: This source is due to the possibility that the turbine cylinder/shell combination acts like a permanent magnetic generator. Both the stationary and rotating turbine blades/buckets can be magnetised by magnetostriction and can form an additional source of voltage. This is an AC source rich of harmonics, but it is also a weak source. It is not very important in turbine generators, although it is very important in high-speed axial-flow compressors used in the petrochemical industry.

Charge Separation: Charge separation in the later stages of a steam turbine may cause the blades to pick up electrons and get a negative charge. The rate of charge separation and therefore potential is directly proportional to steam flow-rate and hence loading.

External Field Voltages: Potentials can also be induced by capacitive coupling between the rotor field winding and the shaft. Thyristor-controlled excitation systems contain high frequency components in their output volt-

20.2 Bearing Current Protection

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age waveform. This source is also weak and incapable of driving large cur-rents, but again it can cause a breakthrough in the oil film.

20.2 Hazard Caused by Shaft Voltages

Practical tests on an unearthed rotor of a turbo-generator provide informa-tion about the size of the shaft voltages. There was a DC voltage of about 45 V due to electrostatic charge in the turbine and to dissymmetrical insula-tion resistances. There was an induced AC component of about 2.5 V at the fundamental frequency, due to eccentricity of the rotor shaft. There was a 15 V rectangular wave AC component due to the static excitation system.

The oil film of the bearings provides some insulation between the ro-tor and the stator in a generating unit. If the bearing pedestals at each side of a turbo-generator are earthed, the shaft voltage will be impressed across the oil film of the bearings.

Most turbo-generators have one or several shaft-earthing brushes to prevent build up of electrical charge on the shaft. This means that the metallic parts of a turbo-generator have contact with earth via the shaft earthing brush. The metallic parts of a hydro-generator have contact with earth via the turbine and the waterways. At least the DC voltage will disappear when the shaft is earthed at one point.

The main outboard bearing of large horizontal turbo-generators is, according to [ 4 ], insulted from the bedplate. Usually, no shaft current is flowing because one end of the generator shaft is insulated from earth. When failure of this insulation has occurred or has been short-circuited, the shaft voltage will be impressed on the oil film of the bearing. A bearing current will start to flow if an electrical breakthrough occurs in the oil film of the bearing. The size of the bearing current is about 100 to 200 A. The bearing or other vital components such as the combination equipment on Kaplan turbines will be damaged. If the bearing current is higher than about 2 A and lasts longer than a few seconds, it will, according to Lohage and co-workers [ 2 ], cause damage.

Bearing Current Protection 20.3

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20.3 Realisation of Bearing Current Protection

It is difficult to detect an electrical breakdown of the oil film in a turbine generator bearing. Utilities have tried to use the shaft voltage for bearing protection. Experience has shown that the bearing current gives more reli-able protection. Now, it is assumed that the current in the generator shaft is equal to the bearing current. One uses a shaft current transformer to measure the shaft current. The shaft current transformer is similar to a normal window-type current transformer. The shaft itself is the primary winding. The core of the shaft-current transformer encompasses the shaft. The secondary winding of the shaft current transformer energises an overcurrent relay. This relay should operate if the secondary current is higher than 1 to 2 mA. Furthermore, it should have very low power consumption. The shaft current relay energises a timer that delays the alarm and trip. The minimum primary operate current increases with the diameter of the shaft. It is about 0.25 A for a shaft with a diameter of 0.2 metres and about 0.75 A for a shaft with a diameter of 2.8 meters.

In 1951 only two utilities out of 25 used, according to an AIEE report [ 4 ], shaft current relays to detect failure of bearing pedestal insulation in turbo-generators. Only machines rated above 50 MVA had such features. An overcurrent relay can detect a bearing pedestal insulating failure. The relay has one terminal connected to the bearing pedestal and the other to an insulated brush making contact with the generator shaft. The oil film in the bearing prevents the relay coil from being short-circuited. This is the only known technical information on shaft current protection in the international relay literature.

Hydro-generators owned by Vattenfall have, according to Lohage and co-workers [ 2 ], shaft current protection. The shaft current relay trips the unit.

20.4 Bearing Current Protection

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References

[ 1 ] Ammann, C., Reicher, K., Joho, R. & Posedel, Z.: "ShaftVoltages in Generators with Static Excitation Systems -Problems and Solutions", IEEE Trans. on Energy Conversion,vol. 3, no. 2, pp. 409-419, June, 1988.


[ 3 ] Buckley, G.W., Corkins, R.J. & Stephens, R.N.: "TheImportance of Grounding Brushes to the Safe Operation of LargeTurbine Generators", IEEE Trans. on Energy Conversion, vol. 3,no. 3, pp. 607-612, September, 1988.


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21. BREAKER FAILURE PROTECTION

It is prudent to require that frequent faults with serious consequences shall be cleared even if one relay or one switching device fails to operate when required. Many utilities design their system so that it can withstand, without damage, the clearance from a back-up relay or when one switching device fails to operate.

The previous sections have documented main protection and backup protection for the generator and related power system components. This section will discuss the consequences of a failure to operate of a switching device. It is sufficient to note that the probability of a failure to open is low. According to a CIGRE questionnaire, it may be as low as 0.0001. According to operational experience from CEGB it may be in the order of 0.001. Operational experience from Sydkraft shows that the circuit breakers maloperate in about 3 percent of the disturbances. Here, it is sufficient to note that the probability is greater than zero. Few protection engineers are prepared to recommend their companies to neglect the risk of breaker failure.

Sometimes it is possible to rely on remote backup protection. By in-troducing breaker failure protection for the generator breaker and the unit breaker it is possible to reduce the time for back-up fault clearance. Often it is less expensive to install local back up protection and breaker failure pro-tection than to reinforce the power system for longer fault clearance times.

It is common practice to use breaker failure protection with three or four overcurrent relays and a timer. The breaker failure protection checks if all phase currents, and sometimes also the residual current, fall to zero. If this occurs within a certain time after the protection system has given a trip-ping impulse to the circuit breaker. Usually one sets the timer to operate af-ter 150 to 200 ms. If all current relays then have dropped out, the switching device has interrupted the fault current and no further action is necessary. If this is not true, the breaker failure protection trips adjacent circuit breakers.

Lohage and co-workers [ 1 ] discuss the setting of the current relays in the breaker failure protection. Their conclusion is that the current relays must have the same sensitivity as the relays that start the breaker failure protection. For hydro-generators, they recommend that a setting of about 30 to 50 percent of the rated current of the generator. For turbo-generators, it may be necessary to use even lower settings depending on the number of the reverse power relays. It is hardly impossible to find overcurrent relays that can always detect reverse power and simultaneously withstand normal load current and fault current.

21.2 Breaker Failure Protection

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A local back-up protection system has the advantage that it is the cir-cuit breaker in the same station that carries out the back-up protection. This is an advantage for the system operators.

An AIEE report [ 3 ] documents contemporary practice for back-up protection in thermal power plants. Then, it was obvious that the big invest-ments in the power plants motivate the existence of a back-up protection system. Then, the equipment was more sturdy and the fault currents were lower. It is not a surprise that the utilities then accepted remote back-up protection systems.

An AIEE working group has prepared and sent out a questionnaire about practice and experience of underexcitation protection. The group has analysed and documented [ 2 ] answers from 63 utilities in the US, Canada and Mexico. The answers represented 309 generators rated at 60 MW or more, installed since 1949. In 1958, 19 utilities said that they had no back-up protection for short circuits in the generator. On the other hand, 18 utili-ties required back-up protection for short circuits in the generator, 15 utili-ties required breaker back-up for short circuits in the generator, 20 utilities required back up protection for the high voltage busbar, 14 utilities required a breaker back up for short-circuits on the busbar, 29 utilities required the tripping of the generator when the line protection failed to operate. The working group recommended installation of back-up protection to obtain the same level of reliability for generator faults as for line faults.

The unit breaker and the generator breaker (if it exists) for hydro-generators owned by Vattenfall shall, according to Lohage and co-workers [ 1 ], have breaker failure protection using three or four current relays.

References




22.1

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22. OPERATIONAL EXPERIENCE

This section documents some operational experience of protection systems.

22.1 Experience from Belgium

Reference [ 1 ] documents a blackout that occurred in Belgium on 4 August 1982. The disturbance started in a nuclear power station with tree units. The initiating event was the tripping of Doel 3 with a rated active power of 900 MW. At the time of the disturbance, the output of that unit was 700 MW and 449 Mvar. Unit 1 in Doel operated at 388 MW and 222 Mvar while unit 2 operated at 382 MW and 236 Mvar. These two units operated close to their reactive limits. There was no reactive reserve available in the power station to cover the loss of the reactive output from unit 3.

The loss of Doel 3 caused a voltage depression on the 380 kV trans-mission network. The automatic voltage regulators (AVRs) on the remaining units increased the excitation current and tried to increase the voltage level. In some remaining units, the overexcitation limiter in the AVR allowed the field current to increase above the pick up level of the overcurrent protection for the rotor. Then, the overcurrent relays tripped these units. In summary, the tripping of one unit caused cascading trips of several other units. This resulted in a widespread blackout. The restoration of the network and connection of the customers took six hours.

22.2 Experience from France

Reference [ 3 ] documents a disturbance that occurred in France on 12 January 1987. The tripping of three big thermal units initiated the disturbance. Independent faults caused these disconnections that occurred within 42 minutes. The losses caused a voltage depression on the 400 kV transmission network. The automatic voltage regulators (AVRs) in remaining units increased the excitation current and tried to increase the voltage level. This caused the tripping of 11 units with a total rated active power of 8 500 MW. The rotor overcurrent relay tripped these. The tripping of the generating units caused a widespread blackout in south-western France. The network restoration and connection of customers took about 12 hours.

22.2 Operational Experience

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22.3 Experience compiled by IEEE

Reference [ 2 ] documents a survey of practices and experiences of genera-tor back-up protection. The report contains an analysis of time-delayed back-up protection. They are associated with unit-connected generators, predominantly rated at 100 MVA and higher. In addition, it discusses appli-cation and setting considerations. The questionnaire covered the following types of back-up protection systems:

51V-C voltage-controlled phase time-overcurrent (disabled until

voltage drops below set level) 51V-R voltage-restrained phase time-overcurrent (current pickup pro-

portional to voltage) 51 phase time-overcurrent 21 phase distance (facing into the external power system) 46 negative-sequence time overcurrent 51N neutral time-overcurrent (in the high side of step-up

transformer)

The responses represented an average of 6 698 unit-years of experience with major unit-connected generators. The largest reported unit of a particular user ranged from 120 to 1 355 MVA, with an average of 850 MVA. The range of the smallest units was 75 to 678 MVA, with an average of 140 MVA. The survey showed the flowing:

1. The majority apply all three classes of back-up protection, phase,

negative-sequence and high-side neutral overcurrent. 2. Distance relaying predominates versus overcurrent for phase backup

protection. 3. The use of backup, for sensing transmission faults, is less of a moti-

vation than sensing low-side and local switch-yard faults. 4. Almost all retrofit activity is confined to the negative-sequence

class, where it is presumed that static types are being applied. 5. The major objectives for use of negative-sequence overcurrent

relaying are to detect: (a) series unbalance and (b) local faults versus transmission faults.

6. The major objective for use of neutral overcurrent relays is to protect for unit-transformer or switchyard fault.

7. The respondents reported 26 correct and 19 incorrect operations. The neutral overcurrent class had the most favourable ratio of correct to incorrect operations.

Operational Experience 22.3

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a) Series unbalance accounted for all of the 8 correct negative-

sequence operations. b) Explanations were included for 6 of the 10 neutral overcurrent

correct operations. Of the six, two for open breaker poles and two where the relay operated after the differential relaying had tripped the unit.

c) Causes for the 19 incorrect operations were: 9 faulty or maladjusted relays 3 wiring errors 3 incorrect settings 3 open potential contacts 1 personnel error 8. Three users reported cases of extensive damage where back-up

protection was not applied for the conditions encountered.

A discussion of application and setting considerations is included. Three subjects not covered by the survey are also presented: • Unit auxiliaries transformer circuit backup • 100% turn-turn fault detection • Stator-ground fault back-up

22.4 Conclusions

The two blackouts described above show the importance of co-ordinating control system functions and protection system functions. It is not good enough to co-ordinate the protection for the generator and the step-up trans-former. In the setting of rotor current limiters and overcurrent protection it is important not to restrict the capability of the unit by selecting typical set-tings.

The IEEE survey shows that utilities in the US prefer to use distance protection as phase back-up protection in favour of overcurrent protection. It also shows that the neutral point overcurrent relay performs well as backup protection. Another result is that it is difficult to achieve the desired level of security. When a back-up protection maloperates during a power system disturbance, there is a risk that it disconnects several units and causes a very severe contingency. Few transmission systems can withstand such contingencies.

22.4 Operational Experience

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References

[ 1 ] Van den Damme, R.: "The incident of August 4th 1982 of theBelgian electricity system", Intercom, 12 September, 1983.

[ 2 ] "A survey of generator back-up protection practices", IEEECommittee Report, IEEE Trans. on Power Delivery, vol. 5, no.2, pp. 575-584, April, 1990.

[ 3 ] "Die Störung vom 12. Januar 1987, 11.42 Uhr", Unpublishedtranslation of an internal report from EdF, Mouvementsd'Energie, 2 February, 1987.

Protection of Synchronous Generators

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