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Inaugural IEEE PES 2005 Conference and Exposition in Africa Durban, South Africa, 11-15 July 2005

Upgrading the Protection of Generators to Meet Current IEEE Standards

Charles J. Mozina, IEEE MemberBeckwith Electric Co., Inc., 6190-118th Avenue North, Largo, Florida, U.S.A.

Phone: 727-544-2326; Fax: 727-546-0121; E-mail: [email protected]

Abstract—Significant changes have occurred in the protection of generators in the past ten years as discussed in IEEE guide C-37.102. [1]. This paper discusses these changes as well as the risks of not addressing them. It specifically addresses the risks in two functional areas where 20+-year-old generator protection is inadequate. These areas include: sensitive stator ground fault protection using schemes to provide 100% winding ground detection, field ground fault protection, and inadvertent (accidental) generator off-line energizing protection. Most of these upgrade schemes were made possible through the use of digital protection.

I. INTRODUCTION

Contrary to popular belief, generators do experience short circuits and abnormal electrical conditions. In many cases, equipment damage due to these events can be reduced or prevented by proper generator protection. As generators become older, the likelihood for failure increases as insulation begins to deteriorate. Generators, unlike some other power system components, need to be protected not only from short circuits, but also from abnormal operating conditions. Examples of such abnormal conditions are overexcitation, loss-of-field, unbalanced currents, and abnormal frequency. When subjected to these conditions, damage or complete failure can occur within seconds, thus requiring automatic detection and tripping.

In the late 1980's, the IEEE Power System Relay Committee first issued its ANSI/IEEE C37.102 [Ref. 1] guide for the protection of synchronous generators. This guide outlines current recommended practices for the protection of generators and documents the substantial changes that have occurred in generator protection over the last twenty years. These changes fall into two broad categories: improved sensitivity and security as well as new protection areas. These are the key functional areas that need to be addressed when developing an upgrade program to bring the generator protection up to current industry standards.

II. AREAS OF PROTECTION UPGRADE ON OLDER GENERATORS

The areas of upgrade on generator protection that are twenty years old or more fall into two broad categories:

A. Improved sensitivity and security—in protection areas where older relaying does not provide the level of detection required. Examples of protection in this area are the following:

1. 100% Stator Ground Fault Protection 2. Field Ground Fault Protection 3. Enhancing Generator System Backup Security

B. New or additional protection—areas that twenty years ago were not perceived to be a problem, but operating experiences have since proved otherwise. One key area is inadvertent generator energizing.

III. IMPROVED SENSITIVITY AND SECURITY

A. 100% Stator Ground Fault Protection Three basic methods of 100% stator ground fault protection

are widely used to provide ground fault protection over the entire stator winding. Two methods use the 3rd harmonic detection while a third method uses an injection of a sub-harmonic signal at the stator neutral. This is an important upgrade area because older generators do not have stator ground fault protection for fault over the entire stator winding.

1. 100% Stator Ground Fault Protection Using 3rd Harmonic Neutral Undervoltage Methods

The most widely used conventional stator ground fault protection scheme in high impedance-grounded systems is a time-delayed overvoltage relay (59N) connected across the grounding resistor to sense zero-sequence voltage as shown in Fig 1. The relay used for this function is designed to be sensitive to fundamental frequency voltage and insensitive to third harmonic and other zero sequence harmonic voltages that are present at the generator neutral. Typically, this overvoltage relay has a minimum pickup setting of approximately 5 V. With this setting and typical grounding transformer ratios, this relay is not capable of detecting faults over the entire stator winding as shown in Fig. 1 with typical 90-95% winding coverage.

It is important to protect major generators with an additional ground fault protection system so that fault coverage for 100% of the winding is obtained. Generators that are twenty years old or older typically have only 90-95% of the stator winding protected for ground faults. One of the 3rd

harmonic methods uses a 3rd harmonic undervoltage relay

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connected as illustrated in Fig.2. Third-harmonic voltages are present at the neutral of most generators to varying degrees—it varies due to differences in stator winding pitch, machine load and power factor. If present in a sufficient amount, this voltage can be used to detect stator ground faults near the generator neutral. For faults near the neutral, the level of 3rd

harmonic voltage measured at the neutral decreases.

Fig. 1 Conventional Stator Ground Fault Detection

Thus, an undervoltage relay operating on 3rd harmonic voltage measured at the neutral as illustrated in Fig. 2 can be used to detect faults near the neutral. The ground faults in the remaining portion of the winding are detected by conventional 59N protection, which operates on fundamental frequency. The overlap of these two protection zones provides 100% stator ground fault protection.

2. 100% Stator Ground Fault Protection Using 3rd Harmonic Ratio Method

The 3rd harmonic voltage is present at both the generator terminal as well as at the neutral. For faults near the neutral, the 3rd harmonic decreases when measured at the generator neutral as discussed above. The terminal 3rd harmonic at the terminal, however, increases. The ratio of terminal/neutral 3rd harmonic voltage can be used to detect faults near the neutral. The ratio varies with generator winding pitch, loading and power factor as illustrated in Fig.3 [2].

The ratio method is more secure than using just the neutral undervoltage method, but does require a broken delta voltage measurement at the generator terminal. This measurement requires that terminal VTs be connected line-to-ground as illustrated in Fig.4. The “blind spot” occurs at the mid-winding and is protected by the conventional 59N relay.

59 – Instantaneous Overvoltage Supervisory Relay 59N – Overvotage Relay Tuned to Fundamental Freq. 27Th – Undervotage Relay Tuned to Third Harmonic 2-1,2-2 – Timers

Fig. 2 3rd Harmonic Undervoltage Ground Fault Scheme

Fig. 3 Typical Generator 3rd Harmonic Values

3. 100% Stator Ground Fault Using Low Frequency Injection

The two 3rd harmonic schemes described above for 100% stator ground fault protection have limitations in their applications. The most common limitation being that there may not be enough 3rd harmonic present to allow fault detection. Since the 3rd harmonic varies with power factor and load, a secure setting may not be possible. For these cases, 100% stator ground fault protection is still possible using a

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subharmonic injection scheme that is widely used in Europe but not used much in North America. The scheme shown in Fig. 5 provides full coverage of the entire stator winding. It also provides off-line detection of stator ground faults. The

recent price reductions in the cost of the injection equipment have made this an attractive choice for many users.

59GN – Overvoltage Relay Tuned to the Fundamental (60 Hz) Frequency 59D – Overvoltage Ratio Relay Tuned to the Third Harmonic (180 Hz) Frequency

Fig. 4 3rd Harmonic Ratio Method

*

CouplingFilter

VoltageInjector

M-3425AMeasurements

I

V

Natural Capacitance

other ground voltage elementsNotes:� Subharmonic injection typically at 15-20 Hz� Coupling filter low pass or notch tuned for subharmonic frequency� Measurement inputs tuned to respond to subharmonic frequency

R e layM easu re m ents

59 N C onventional Protec tion

Fig. 5 100% Stator Ground Fault Using Low Frequency Injection

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B. Field Ground Fault Detection (64F) The field circuit of a generator is an ungrounded (typically

600- 800 V) dc system, as shown in Fig. 6.

Fig. 6 A Basic Generator Field Circuit

A single field ground fault generally will not affect the operation of a generator, nor will it produce any immediate damaging effects. However, the probability of a second ground fault occurring is greater after the first ground fault has established a ground reference. When a second ground fault occurs, a portion of the field winding will be short-circuited, thereby producing unbalanced air gap fluxes in the machine. These unbalanced fluxes produce unbalanced magnetic forces, which result in machine vibration. A field ground fault also produces rotor iron heating from the unbalanced short circuit currents. The tripping practices within the industry for field ground relaying are not well established. Some users trip while others prefer to alarm, thereby risking a second ground fault and major damage before the first ground is cleared.

The existing practice within the industry has been to use voltage detection systems. These voltage schemes have been prone to false operation—especially during start-up. Unit operators routinely reset the alarm and continue with start-up procedures. If a persistent alarm occurred, operators attempted to locate the problem. If the ground could not be found within a reasonable time, the unit was supposed to be tripped manually. However, the many nuisance alarms and the very few legitimate ones caused some unit operators to lose confidence in the field ground voltage scheme. Therefore, the alarm lost credibility. Operators continued to keep the units on-line, hoping that a second ground would not occur. Catastrophic rotor failures have occurred due to a second ground in the field developing very quickly after the first ground. In these instances, the operators were not able to isolate the cause of the first alarm, nor were they able to bring the units off-line in an orderly fashion before the second ground occurred.

Clearly, a more secure field ground relay is desirable if automatic tripping is being considered. Such a relay is shown in Fig. 7 and uses an injection principle. This principle has been widely used in Europe with great success, but until

recently, it was not available in a multifunction relay. As illustrated in Fig. 7, a 15-volt square wave signal is injected into the field through a coupling network. The return signal waveform is modified due to field winding capacitance. The injection frequency setting is adjusted (0.1 to 1.0 Hz) to compensate for field winding capacitance. From the input and return voltage signals, the relay calculates the field insulation resistance. The relay setpoints are in ohms, typically with a 20 K ohm and a 5 K ohm critical alarm or trip.

The injection scheme provides a major improvement over traditional voltage schemes in terms of both sensitivity as well as security. In addition, digital relays can provide real-time monitoring of field insulation resistance so deterioration with time can be monitored. The scheme can also detect grounds on an off-line generator, allowing the operator to determine if the field circuitry is free of a ground before start-up. An added benefit of the injection scheme described above is that it operates at a low voltage (15 V) compared to the scheme it typically replaces (120 V), thus improving operator safety when changing brushes with the unit on-line.

Fig. 7 Field Ground Protection Using an Injection Voltage Signal

C. Enhancing Generator System Backup Security (21-2) A mho distance relay characteristic is commonly used to

detect system phase faults and to trip the generator after a set time delay. These relays, however, have frequently operated improperly during major system disturbances—unnecessarily tripping generators and thereby exacerbating the disturbance. This was the case during the 1996 West Coast blackout.

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Investigation revealed that these relays were improperly set for the system conditions they encountered and were expected to “ride through.” They operated due to stable power swings or load encroachment during low system voltage conditions.

The IEEE Power System Relay Committee, through the latest revision of C-37.102 [1], provides guidance on setting this relay. The relay’s impedance reach and delay settings must be coordinated with transmission backup protection and breaker failure to allow selectivity. Typically, the phase distance relay’s reach begins at the generator terminals and ideally extends to the length of the longest line out of the power plant transmission substation. Some factors impacting the settings are as follows:

1. In-feeds: Apparent impedance due to multiple in-feeds will require larger reaches to cover long lines and will overreach adjacent shorter lines. The apparent impedance effect occurs because the generator is only one of several sources of fault current for a line fault. This causes the ohmic value of the faulted line to appear further away and require a larger ohmic setting to cover faults at the remote end of the line.

2. Transmission System Protection: If the transmission lines exiting the power plant have proper primary and backup protection, as well as local breaker failure, the need to set the 21-2 generator relay to respond to faults at the end of the longest lines is mitigated since local backup has been provided on the transmission system.

3. Load Impedance: Settings should be checked to

ensure the maximum load impedance (ZLoad =kV2/ MVAG)

at the generator’s rated power factor angle (RPFA) does not encroach into the 21-2 relay setting. A typical margin of 150-200% is recommended [1] to avoid tripping during power swing conditions. Due to recent blackouts caused by voltage collapse, the 21-2 distance setting should be checked for proper operating margins when the generator is subjected to low system voltage. Note that the impedance is reduced by the square of the voltage. System voltage under emergency conditions can reduce to planned levels of 90 to 94 percent of nominal ratings. Utility transmission planners should be consulted for worst-case emergency voltage levels. In almost all cases, the loadability considerations limit the reach of the generator 21-2 backup relay setting.

Setting generator backup distance protection with adequate margin over load and stable power swings is an art as well as a science. The 21-2 relay element is typically set at the smallest of the following three criteria:

1. 120% of the longest line with in-feeds. 2. 50 to 67% of the generator load impedance (Zload )

at the rated power factor angle (RPFA) of the generator. This provides a 150 to 200% margin over generator full load. This is typically the prevailing criteria.

3. 80 to 90% of generator load impedance at the maximum torque angle of the 21-2 impedance relay setting (typically 85°).

The capability curve for the generator and settings are plotted on the R-X diagram as shown in Fig. 8. The time delay for the 21-2 relay should be set longer than the transmission lines’ backup and breaker failure protection with an appropriate margin for proper coordination.

To enhance security and safe load margins while still providing the necessary 21-2 relay reach, it is possible to use both load encroachment and out-of-step blocking techniques. Out-of-step blocking uses a 21-3 impedance element that completely surrounds the 21-2 trip element to provide blocking logic.

J X

R

Z2

Z1

RPFA

Max.TorqueAngle

GeneratorCapability

Curve

Z2 Reach at 50 to 67% ofGenerator Capability Curve

Z2 Reach 120% of Longest Line butMust be Less then 80 to 90%

of Capability Curve

Fig. 8 Generator Phase Distance Backup Protection Settings

The zone 3-distance element must be set less than the capability of the generator as illustrated in Fig. 9. For power system swing conditions, the impedance locus will first enter into zone 3 before entering zone 2. For fault conditions, the impedance will instantaneously enter the zone 2-trip characteristic. Out-of-step logic is provided such that if zone 3 operates prior to zone 2, a power swing condition exists and zone 2 is blocked from operating. To enhance steady-state loadability, a notch blinder is used as illustrated in Fig. 9. The part of the zone 2-trip circle is blocked from operating to increase loadability at the generator’s rated power factor angle (RPFA). Both these techniques are available in multifunction digital generator relay packages.

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J X

R

Z2

Z1

Max.TorqueAngle

GeneratorCapability

Curve

Z2 Reach at 50 to 67% ofGenerator Capability Curve

Z2 Reach 120% of Longest Line butMust be Less then 80 to 90%

of Capability Curve

Z3 out of step blocking

Load EncroachmentBlocking

RPFA

Z3

Fig. 9 Security Enhancements forGenerator Phase Backup Distance Protection

IV. NEW OR ADDITIONAL PROTECTION AREAS

Inadvertent Generator Energizing (27/50) Inadvertent or accidental energizing of synchronous

generators (27/50) has been an industry problem in recent years. A number of machines have been damaged, or in some cases, completely destroyed when they were accidentally energized while off-line. The frequency of these occurrences has prompted generator manufacturers to recommend that the problem be addressed through dedicated protective relay schemes. Operating errors, breaker contact flashovers, control circuit malfunctions, or a combination of these causes, have resulted in generators becoming accidentally energized while off-line. In industrial applications, the major cause of inadvertent energization of generators has been closing the generator breaker through the mechanical close/trip control at the breaker itself—thereby defeating the electrical interlocks.

Due to the severe limitation of conventional generator relaying to detect inadvertent energizing, dedicated protection schemes have been developed and installed. Unlike conventional protection schemes, which provide protection when equipment is in service, these schemes provide protection when equipment is out of service. One method

widely used to detect inadvertent energizing is the voltage-supervised overcurrent scheme shown in Fig. 10. An undervoltage element with adjustable pickup and dropout time delays supervises an instantaneous overcurrent relay. The undervoltage detectors automatically arm the overcurrent tripping when the generator is taken off-line. The undervoltage detector will disable or disarm the overcurrent relay when the machine is returned to service. Great care should be taken when implementing this protection, so that the dc tripping power and relay input quantities to the scheme are not removed when the generator is off-line.

Fig. 10 Inadvertent Energizing Schemes

V. CONCLUSIONS

There are several functional protection areas on generators twenty years or older which have significant shortcomings when compared to current IEEE-recommended generator protection practices. This paper identifies a number of these protection areas and the risks of not addressing these shortcomings. It also points out the advantages of using multifunction digital relaying to upgrade generator protection as a technology that offers many advantages over older electromechanical relays.

REFERENCES [1] IEEE Guide for AC Generator Protection, ANSI/IEEE C37.102-2005. [2] Pope, J.W., “A Comparison of 100% Stator Ground Fault Protection

Schemes for Generator Stator Windings”, IEEE Transactions, Power Applications, April 1984.

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