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Waterpower '97August 5–8, 1997

Atlanta, GA

UpgradingHydroelectric Generator Protection

Using Digital Technology

Charles J. MozinaBeckwith Electric Company6190-118th Avenue North

Largo, FL 33773-3724 U.S.A.

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Upgrading Hydroelectric Generator ProtectionUsing Digital Technology

Charles J. Mozina1

AbstractThis proposed paper presents the reasons/rationale why hydroelectric generator owners should

consider upgrading the electrical protection of their generators to meet today’s IEEE/ANSI stan-dards. It specifically outlines the risks assumed by the owners in several functional protectionareas where 20+ year old generator protection is inadequate.

IntroductionContrary 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 byproper generator protection. Generators, unlike most other power system components, need to beprotected not only from short circuits, but from abnormal electrical conditions. Examples of suchabnormal conditions are: overexcitation, overvoltage, loss-of-field, unbalanced currents, reversepower, and abnormal frequency. When subjected to these conditions, damage or complete failurecan occur within seconds; thus, automatic detection and tripping are required.

In the early 1990’s, the IEEE Power System Relaying Committee conducted a survey to deter-mine how major synchronous generators in North America were protected from short circuitsand abnormal electrical conditions. Survey findings indicated that despite the clear need to up-grade older generator protection schemes to meet current standards, utilities seemed reluctant tomake needed modifications to existing power plants. This reluctance may be due to severalfactors: a lack of expertise, a misunderstood belief that generators do not fail often enough towarrant proper protection, or a belief that operating procedures will cover protection designdeficiencies.

Areas of Protection Upgrade on Older GeneratorsThe areas of upgrading of 20+ year old generator protection fall into three broad categories:

1) Improved Sensitivity in protection areas where older relaying does not provide the levelof detection required to prevent damages. Examples of protection in this area are:• negative sequence (unbalanced current) protection• 100% stator ground fault protection

2) New or Additional Protection Areas that 20 years ago were not perceived to be a prob-lem, but operating experiences have proved otherwise. These areas are:

1Manager Application Engineering, Protection and Protection Systems, Beckwith ElectricCompany, 6190 - 118th Avenue North, Largo, FL 33773-3724, U.S.A.

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• inadvertent generator energizing• vt fuse loss• oscillographic monitoring

3) Special Protection Application Considerations that are unique to generators. These areasinclude:• generator breaker failure

The IEEE/American National Standards Institute (ANSI) develop protection guides (see refer-ences 1, 2 and 3) reflecting the need to provide the protection, which is outlined in this paper, inthe major upgrade areas cited. These guides express the views of both users (utilities/generatorowners) as well as the generator manufacturers and are reflective of in-service experience viewedat a national level. The guides are updated on a five year basis to keep them current with both in-service experience as well as changes in technology.

Improved Sensitivity Protection Areas

Negative Sequence (unbalanced current) ProtectionThere are a number of system conditions that can cause unbalanced three-phase currents in a

generator. These system conditions produce negative sequence components of current whichinduce a double-frequency current in the surface of the rotor. The skin effect of the double-frequency rotor current causes it to be forced into the surface elements of the rotor. These rotorcurrents can cause excessive temperatures in a very short time.

The current flows across the metal-to-metal contact of the retaining rings to the rotor forgingwedges. Because of the skin effect, only a very small portion of this high frequency currentflows in the field windings. Excessive negative sequence heating beyond rotor thermal limitsresults in failure. These limits are based on the following equation, for a given generator:

K=I22tWhere:K = constant depending on generator design and sizet = time in secondsI2 = RMS value of negative sequence current in p.u.

The continuous unbalanced current capability of a generator is defined in ANSI C50.13 (refer-ences 4 and 5). This standard states that "generator shall be capable of withstanding, withoutinjury, the effects of a continuous current unbalance corresponding to a negative-phase-sequencecurrent I2 of the following values, providing the rated kVA is not exceeded and the maximumcurrent does not exceed 105 percent of rated current in any phase."

Type of Generator Permissible I2(percent of stator rating)

Salient PoleWith connected amortisseur windings 10With non-connected amortisseur windings 5

These values also express the negative-phase-sequence current capability at reduced generatorKVA capabilities.

It is common practice to provide protection for the generator for external unbalanced currentconditions that might damage the machine. This protection consists of a time overcurrent relaywhich is responsive to negative sequence current. Two types of relays are available for thisprotection: an electromechanical time overcurrent relay with an extremely inverse characteristic,and a static or digital relay with a time overcurrent characteristic which matches the negativesequence current capabilities of the generator. For open conductor or open breaker pole condi-

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tions, the negative sequence relay is usually the only protection. The low magnitude of negativesequence currents created by this type of event (typically 10-20% of stator rating) prevents otherfault relays from providing protection. For electromechanical negative sequence relays, the mini-mum pickup can be set to provide only 60% of stator rated current sensitivity. Thus, these relayswill provide no protection for open phase or open generator breaker pole conditions which arefrequent negative sequence events within the industry. The sensitivity of negative sequence staticor digital relays is required. Almost all 20+ year old generators are protected with electrome-chanical negative sequence relays which make this an important upgrade area.

100% Stator Ground Fault ProtectionHigh-impedance generator neutral grounding utilizes a distribution transformer and a second-

ary resistor. The secondary resistor is usually selected so that for a single line to ground fault atthe terminals of the generator, the power dissipated in the resistor is approximately equal to thereactive volt-amperes in the zero sequence capacitive reactance of the generator windings, itsleads, and the windings of any transformers connected to the generator terminals. Using thisgrounding method, a single line to ground fault is generally limited to 3-25 primary amperes.

R 59N

Figure 1 High Impedance-Grounded Generator

The most widely used stator ground fault protective scheme in high impedance-groundedsystems is a time- delayed overvoltage relay (59N) connected across the grounding resistor tosense zero-sequence voltage as shown in Figure 1. The relay used for this function is designed tobe sensitive to fundamental frequency voltage and insensitive to third harmonic and other zerosequence harmonic voltages that are present at the generator neutral. Typically, the overvoltagerelay has a minimum pickup setting of approximately 5 V.

The 59N protective scheme is straight forward and dependable, however, this relay will pro-vide protection for only about 95% of the stator winding. This is because a fault in the remaining5% of the winding, near the neutral, does not produce a sufficient 60 Hz residual voltage. It isimportant to protect major generators with an additional ground fault protection system so thatfault coverage for 100% of the winding is obtained. Twenty plus year old generators typicallyhave only 95% of the stator winding protected for ground faults. Many utilities have upgradedprotection to provide 100% stator winding ground fault protection. One method is the use of athird-harmonics undervoltage relay. Third-harmonic voltage components are present at the neu-tral of nearly every machine to varying degrees; they arise and vary due to differences in design,manufacture and machine load. If present in a sufficient amount, this voltage can be used todetect ground faults near the neutral.

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One method uses the fact that for a fault near the neutral, the level of third-harmonic voltageat the neutral decreases. Therefore, an undervoltage relay operating from third-harmonic voltagemeasured at the neutral end could be used to detect faults near the neutral. The ground faults inthe remaining portion of the windings can be detected by conventional ground fault protection,e.g., the overvoltage relay (59N) which operates on the 60 Hz neutral voltage. The combinationof both relays provide 100% stator winding protection. A simplified protection scheme using thistechnique is shown in Figure 2.

27Th

59N

59

59N

COMPLETESHUTDOWN

2-2 2-1

95% 100%

86

(+)

(-)

59 2-1 2-2

27Th

59 Instantaneous Overvoltage Supervisory Relay59N Overvoltage Relay Tuned to the

Fundamental (60 Hz) Frequency27Th Undervoltage Relay Tuned to the

Third Harmonic (180 Hz) Frequency2-1, 2-2 Timers

Figure 2 Third Harmonic Undervoltage Ground Fault Protection Scheme

New or Additional Protection Areas

Inadvertent Accidental Generator EnergizingInadvertent or accidental energizing of synchronous generators has been a particular problem

within the industry 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 ofthese occurrences has prompted generator manufacturers to recommend that the problem be ad-dressed through dedicated protective relay schemes. Due to the severe limitation of conventionalgenerator relaying to detect inadvertent energizing, dedicated protection schemes have been de-veloped and installed. Unlike conventional protection schemes, which provide protection whenequipment is in-service, these schemes provide protection when equipment is out of service. Onemethod widely used to detect inadvertent energizing is the voltage-supervised overcurrent schemeshown in Figure 3. An undervoltage element with adjustable pickup and dropout time delayssupervise an instantaneous overcurrent relay. The undervoltage detectors automatically arm theovercurrent tripping when the generator is taken off-line. This undervoltage detector will disableor disarm the overcurrent relay when the machine is returned to service. Great care should betaken when implementing this protection so that the dc tripping power and relay input quantitiesto the scheme are not removed when the generator is off-line.

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GEN

R

50CT

27

VT

* On All Three Phases Simultaneously

ANDPickupDelay

DropoutDelay

27Undervoltage*

V<P.U.

50Overcurrent

I>P.U.

OutputContact

a) Relay Inputs b) Relay Logic Diagram

Figure 3 Inadvertent Energizing Scheme

When an off-line generator is energized while on turning gear, or coasting to a stop, it behavesas an induction motor and can be damaged within a few seconds. During three-phase energizationat a standstill, a rotating flux at synchronous frequency is induced in the generator rotor. Theresulting rotor current is forced into sub-transient paths in the rotor body, similar to those rotorcurrent paths for negative-sequence stator currents during generator single-phasing. Rapid rotorheating occurs, which can quickly damage the rotor. The machine impedance during this high-slip interval is equivalent to the generator negative-sequence reactance. Figure 4 shows a simpli-fied equivalent circuit that can be used to calculate the current and voltage associated with three-phase inadvertent energizing.

GENEquivalentSystemVoltage

X2G EG

I

Where:

X1S = System Positive Sequence Reactance

X2G = Generator Negative Sequence Reactance

ES = System Voltage

EG = Generator Terminal Voltage

I = Current

ES

EquivalentSystemReactance

X1S

Figure 4 Inadvertent Energizing Equivalent Circuit

Operating errors, breaker-head flashovers, control circuit malfunctions, or a combination ofthese causes, have resulted in generators becoming accidentally energized while off-line. In in-dustrial applications, the major cause of inadvertent energization of generators has been by clos-ing the generator breaker through the mechanical close/trip control at the breaker itself, therebydefeating the electrical interlocks.

VT Fuse Loss ProtectionLoss of the vt signal can occur due to a number of causes, the most common cause being fuse

failure. Other causes may be an actual vt or wiring failure, an open in the draw-out assemblies, acontact opening due to corrosion, or a blown fuse due to screwdriver shorts during on-line main-

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tenance. Such loss of vt signal can cause protective relays misoperations or generator voltageregulator runaway leading to an overexcitation condition. Some method of detection is requiredso that the effected relay tripping can be blocked and the voltage regulator transferred to manualoperation. Typically, protective functions such as 21, 32, 40 and 51V are impacted and arenormally blocked when a loss of potential is detected.

On larger generators, it is common practice to use two sets of voltage transformers (vts) in thegenerator zone of protection. As shown in Figure 5a, the vts that are usually connected groundedwye-grounded wye, normally have secondary and possibly primary fuses. These vts are used toprovide potential to a number of protective relays and the voltage regulator. If a fuse blows in thevt circuits, the secondary voltages applied to the relays and voltage regulator will be reduced inmagnitude. This change in voltage signal can cause the misoperation of the relays and the regula-tor to overexcite the generator.

60

GEN

TOPROTECTIVERELAY

TOVOLTAGEREGULATOR

VOLTAGEBALANCERELAY

VT

60FL

GEN

TO PROTECTIVERELAY ANDVOLTAGEREGULATOR

a) Application of Voltage Balance Relay Protection b) Modern VT Fuse Loss DetectionFigure 5 VT Fuse Loss Detection

On many older, hydro generators, only one set of vts is provided. It is not possible to use avoltage balance relay unless a second set of vts is added. Thus, many generators do not have vtfuse loss protection. A modern digital method used in vt failure detection makes use of therelationships of negative sequence voltages and currents during a loss of potential. When one vtsignal is lost, the three phase voltages become unbalanced. Due to this unbalance, a negativesequence voltage is produced. To distinguish this condition from a fault, negative sequence cur-rents are checked. The presence of negative sequence voltage in the absence of negative se-quence current indicates a fuse failure rather than a fault.

Oscillographic Generator MonitoringThe monitoring of a utility's transmission system with oscillographs which record relay cur-

rents and voltages has long been accepted within the industry as providing the basic data toanalyze the performance of the transmission protective system. Because of the greater number oftransmission line faults versus generator faults and abnormal conditions, it was felt by many thatsimilar monitoring of generators could not be economically justified with “stand alone” oscillo-graphs. However, with the advent of digital protective relays for generators, oscillographs arebuilt into the protective relay. Figure 6 is an example of an oscillographic recording from such arelay.

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Figure 6 Digital Relay Oscillograph Record

With the remote communication capabilities of these relays, oscillograph and target informa-tion can be quickly accessed from a remote location, after a generator tripping, to determine ifrelay and circuit breaker operations were proper. Oscillographic information can also identify thetype of testing needed to find the cause of a tripping and speed the return of the generator toservice. It gives the relay engineer the necessary data to keep machines off-line for testing andinspection, when necessary, after an electrical tripping or to return the unit to service with aminimum delay. Those utilities that have implemented a program of oscillographic monitoring ofgenerators have found the information invaluable.

Special Protection Application Considerations

Generator Breaker FailureA breaker failure scheme needs to be initiated when the protective relay system operates to

trip the generator circuit breaker but the breaker fails to operate. Because of the sensitivitiesrequired, there are major differences in how local breaker failure is applied on a generator breakerversus a transmission line breaker. Figure 7 shows the functional diagram of a typical breakerfailure scheme used on a transmission line breaker.

When the protective relays detect a fault, they will attempt to trip the primary transmissionline breaker and at the same time initiate breaker failure. If the line breaker does not clear thefault in a specified time, the timer will trip the necessary backup breakers to remove the failedcircuit breaker from service. The successful tripping of the primary breaker is determined by thedrop out of its current detector (CD) which stops the breaker failure timer (62). When breakerfailure is applied on a generator breaker, however, its tripping may not be initiated by a shortcircuit but by an abnormal operating condition for which there maybe little or no short circuitcurrent. Abnormal operating conditions such as overvoltage, overexcitation, excessive underfrequency,reverse power and stator ground faults will not produce sufficient current to operate the currentdetectors (CD). The breaker 52a switch must be used in parallel with the fault detectors toprovide additional indication in a breaker failure scheme for generator breakers. This logic isshown in Figure 8.

ProtectiveRelays

AND

TripGenerator

CD

Breaker

Aø

TripsBackupBreakers

andUnit

62Timer CD - Current Detector

62 - Breaker Failure Timer WithAdjustable Pickup & Zero Dropout Delays

BFI - Breaker Failure InitiateBFI

Figure 7 Typical Transmission Line Breaker Failure Functional Diagram

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ProtectiveRelays

ANDCD Aø

TripsBackupBreaker

andUnit

62Timer

52a

OR52a - Circuit Breaker Auxiliary Contacts

CD - Current Detector

62 - Breaker Failure Timer WithAdjustable Pickup & Zero Dropout Delays

BFI - Breaker Failure Initiate

BFI

TripGeneratorBreaker

Figure 8 Functional Diagram of a Generator Breaker Failure Scheme

Using Digital Technology to Implement an Upgrade ProgramJust as it has been in the transmission line upgrade area, multifunction digital relaying is an

ideal and cost effective way to upgrade generator protection to current industry standards. Figure9a shows a functional diagram of such a relay.

Utility System

59N

52Unit

High-ImpedanceGrounding

27TN

81 2427 59

5050BF

327

27

AB

C

87

21 3260FL 40 46

27

IA, B, C

Ia, b, c

AC

B

50BF-N

4

5

1

2

TYPICALMULTIFUNCTION

RELAY

Denotes UpgradeFunctions

Utility System

52

81 27 59

50

50

27

27

51V 3260FL 40 46

IA, B, C

Ia, b, c

50N51N

Low-ImpedanceGrounding

24

8787GD

TYPICAL MULTIFUNCTION RELAY

50BF

R

DenotesUpgradeFunctions

4

5

1

3

a) High-Impedance Grounded Generator b) Low-Impedance Grounded Generator

Figure 9 One-Line Diagrams

Common upgrade functions (shaded) are shown in Figures 9a and 9b:

1 Negative Sequence (unbalanced current) Protection2 100% Stator Ground Fault Protection3 Inadvertent (accidental) Generator Energizing4 VT Fuse Loss Protection5 Generator Breaker Failure

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These functions, plus nine (9) additional protection functions, are included in a single com-pact package. Space considerations are an important concern when doing upgrade work and canhave a significant impact on project cost, making multifunction digital relays ideal for upgradeprojects.

Additional features, which make these types of relays extremely flexible for upgrade applica-tions, include:

• Programmable outputs and six programmable inputs• Oscillographic recording• Target storage• Metering of all measured parameters• RS-232 and RS-485 communication ports• Continuous self-checking diagnostics

For low impedance-grounded generators (resistor-or reactive-grounded), overcurrent (51N)stator ground relaying is required. Figure 9b illustrates a one-line diagram of this application.

Many protection upgrade projects are part of larger life extension or automation efforts withina power plant. One of the important features of digital relays is their communication capability.Rear-panel communication ports, RS-232 or RS-485, can be used to remotely set and interrogatethe relay via a modem. Communication with multiple relays can be accomplished using a simplelow cost communication signal splitter and modems (Figure 10).

Communications-LineSplitter

Modem

Address 2

Address 4

Address 5

Address 6

Address 3Address 1

IBM-Compatible PC

TelephoneLine

Modem

a) RS-232 Port

RX TX - + - +

RX TX - + - +

RS-232 to RS-485 4-wire converter

PC Master

RX TX - + - +

T-T+R-R+

Twisted Pair

Address 1 Address 2 Address 5

b) RS-485 Port

Figure 10 Multiple System Addressing Using Communications-Line Splitter

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PLANTDCS System

EMSCenter

Data link toEMS Center Local

OperatorCRT

Display

Relay 1 Relay 2 Relay 3 Relay

Figure 11 System Integration

Metering quantities (MW, MVAR, Volts, Amps, P.F., etc.) within these relays can be ac-cessed by a DCS (Distributed Control System) within the plant through the relay communicationports. This saves in the costs and wiring required for dedicated transducers for each meteringquantity. Figure 11 shows a system which uses the digital relay as an Intelligent ElectronicDevice (IED) to gather data for a DCS system.

ConclusionThere are a number of functional protection areas on 20+ year old generators which have

significant shortcomings. This paper identifies those protection areas and the risks of not ad-dressing them. In addition, a cost-effective strategy to upgrade protection to current industrystandards is outlined using multifunction digital relaying. Generation is the single most expen-sive capital investment of a utility. Protecting this investment to prevent failure should be apriority item with utilties as well as non-utility generator owners.

References[1] ANSI/IEEE C37.102-1986, "IEEE Guide for AC Generator Protection."[2] ANSI/IEEE C37.101-1993, "IEEE Guide for AC Generator Ground Protection."[3] ANSI/IEEE C37.106-1987, "IEEE Guide for Abnormal Frequency Protection for Power

Generating Plants."[4] ANSI C50.13-1987, "American National Standard for Cylindrical Rotor Synchronous

Generators."[5] ANSI/IEEE C50.12-1982, "American National Standard Requirements for Salient Pole

Synchronous Generators and Generator/Motors for Hydraulic Turbine Applications."[6] IEEE Power Engineering Society Tutorial 95TP102, "IEEE Tutorial on the Protection of

Synchronous Generators."

About the AuthorChuck Mozina is currently Manager of Application Engineering for Protection and Protec-

tion Systems for Beckwith Electric Co. He is responsible for the application of Beckwith prod-ucts and systems used in generator protection and intertie protection, synchronizing and bustransfer schemes.

Chuck is an active member of the IEEE Power System Relay Committee and is the pastchairman of the Rotating Machinery Subcommittee. He is the U.S. representative to the CIGREStudy Committee 34 on System Protection and chairs a CIGRE working group on generatorprotection. He also chaired the IEEE task force which produced the tutorial “The Protection ofSynchronous Generators.”

Chuck has a bachelor of science in electrical engineering from Purdue University and hasauthored a number of papers and magazine articles on protective relaying. He has over 25 yearsof experience as a protective engineer at Centerior Energy, a major investor-owned utility inCleveland, Ohio. He is also a former instructor in the Graduate School of Electrical Engineeringat Cleveland State University.