ieee generator protection tutorial presentation

Special Publication of the IEEE Power System Relaying Committee

Copyright © IEEE 2011

IEEE TUTORIAL ON THE PROTECTION OF SYNCHRONOUS GENERATORS


Developed by a working group of the Power System Relay Committee (PSRC)

First published in 1995 – widely presented within the industry, including a presentation at the 2003 PPIC Conference

Updated, published, and presented for the first time at the 2011 57th IEEE Pulp and Paper Industry Conference

Michael Thompson, ChairChristopher Ruckman, Vice ChairHasnain AshrafiGabirel BenmouyalZeeky BukhalaStephen P. ConradEverett FennellDale FinneyDale FredricksonJonathan D. GardellJuan GersRandy HamiltonWayne HartmannGerald JohnsonPatrick M. KerriganSungsoo KimPrem Kumar

Hugo MonterrubioCharles MozinaMukesh NagpalBrent OxandaleRussell W. PattersonMike ReichardMohindar SachdevKevin StephanSudhir ThakurDemetrios TziouvarasJoe UchiyamaQuintin Verzosa, Jr.Thomas WiedmanMichael WrightJohn WangMurty V. V. S. Yalla

5

Michael J. Thompson received his BS, magna cum laude, from Bradley University in 1981 and an MBA from Eastern Illinois University in 1991. He has broad experience in the field of power system operations and protection. Upon graduating, he served nearly 15 years at Central Illinois Public Service (now AMEREN), where he worked in distribution and substation field engineering before taking over responsibility for system protection engineering. Prior to joining Schweitzer Engineering Laboratories, Inc. in 2001, he was involved in the development of several numerical protective relays while working at Basler Electric. He is presently a Principal Engineer in SEL’s Engineering Services Division; a senior member of the IEEE; a main committee member of the IEEE PES Power System Relaying Committee; and a registered professional engineer. Michael was a contributor to the reference book, Modern Solutions for the Protection Control and Monitoring of Electric Power Systems, has published numerous technical papers, and has a number of patents associated with power system protection and control.

6

Charles (Chuck) Mozina received a B.S. degree in electrical engineering from Purdue University, West Lafayette, in 1965. He is a Consultant, for Beckwith Electric Co. Inc., specializing in power plant and generator protection. His consulting practice involves projects relating to protective relaying applications, protection system design and coordination. Chuck is an active 25-year member of the IEEE PES Power System Relay Committee and was the past chairman of the Rotating Machinery Subcommittee. He is active in the IEEE IAS I&CPS, PCIC and PPIC Committees, which address industrial protection systems. He is the past U.S. representative to CIGRE Study Committee 34 (now B-5) on System Protection. He has over 25 years of experience as a protective engineer at Centerior Energy (now part of FirstEnergy), a major utility in Ohio, where he was Manager of System Protection. For 10 years, he was employed by Beckwith Electric as the Manager of Application Engineering for Protection Systems. He is now a consultant for that company. He is a registered Professional Engineer in the state of Ohio and a Liife Fellow of the IEEE.

FundamentalsMultifunction Generator Protection SystemsStator Phase Fault ProtectionStator Ground Fault ProtectionField Fault ProtectionSystem Backup ProtectionGenerator Breaker FailureAbnormal Frequency ProtectionOverexcitation and Overvoltage Protection

Underexcitation / Loss-of-Excitation ProtectionCurrent Unbalance (Negative-Sequence) ProtectionLoss of Prime Mover (Antimotoring) ProtectionOut-of-Step ProtectionVoltage Transformer Signal LossInadvertent Energization ProtectionOther Protective ConsiderationsTripping Modes

Basic design and operation of synchronous generators

Power system connections

Behavior under short-circuit conditions

Generator grounding

Generator stability

IEEE guidelines

Device numbers

0

+MVAR

Overexcited

Underexcited

–MVAR

Reactive Power Into System

Reactive Power Into Generator

Overexcitation Limiter (OEL)

Rotor Winding Limited

Underexcitation Limiter (UEL)

Stator End Iron Limited

Steady-State Stability Limit

Stator Winding Limited

+ MW Real Power Into System

MVARNormal Overexcited Operation

Underexcited Operation

GMW

System

GMVAR

MWSystem

β

X

–X

R–R

Z

2C

V

RkVMVA AngleZ R

⎛ ⎞= β⎜ ⎟

⎝ ⎠2

C

V

RkVZ AngleMVA R

⎛ ⎞= β⎜ ⎟

⎝ ⎠

Cur

rent

Cur

rent

Cur

rent

0

2000

4000

6000

8000

time, seconds0.01 0.1 1 10

wattseconds

wat

tsec

onds

TotalGenerator

System

Accumulation of Damage Over Time

Most damage occurs in period after the generator breaker opens

Types of Instability Steady-State

Transient

Dynamic

( )g se g s

E EP sin

X= θ − θ

g smax

E EP

X=

g gE ∠θL4

Power Flow

L1

L3L2

POWERSYSTEM

Power System

s sE ∠θ

X

R

Xe

d eX X2−

d eX X2+

R-X Diagram Plot

Per-Unit MVAR

Per-Unit MW

MW-MVAR Per-Unit Plot

2

e d

V 1 12 X X⎛ ⎞

+⎜ ⎟⎝ ⎠

2

e d

V 1 12 X X⎛ ⎞

−⎜ ⎟⎝ ⎠

G

Generator GSU System Reactance

Xd

VXT

XS

Where:Xe = XT + XS

Power System

1 2

78

G

78 = Out-of-Step ProtectionEs = System VoltageEg = Generator Voltage

s = System Voltage Phase Angleg = Generator Voltage Phase Angle

T

Three-Phase Short CircuitSubstation

GSU

s sE ∠Θ

g gE ∠Θ

g smax

E EP

X=

Maximum Power

Transfer

PM = Pe

A1

A2

All Lines in ServiceBreakers 1 and 2

Tripped

θC

0 90° 180°θg – θs

( )g se g s

E EP sin

X= θ − θ

Occurs when fast-acting AVR control amplifies rather than damps small MW oscillations

Most likely to occur when generators are remote from load centers

Power system stabilizer (PSS) damps oscillations – required in Western United States

Latest developments reflected inStd. 242, IAS Buff BookC37.102, IEEE Guide for Generator ProtectionC37.101, IEEE Guide for AC Generator Ground ProtectionC37.106, IEEE Guide for Abnormal Frequency Protection for Power Generating Plants

Created / maintained by the IEEE PSRC & IAS –updated every 5 years

C37.102-2006 updated version now available – includes significant changes

and additions

Device Number Function Tutorial Chapter11 Multifunction Protection System 5.2

21 Distance Relay – Backup for System and Generator Zone Phase Faults 2.4

24 Volts / Hertz Protection for GeneratorOverexcitation 3.2

27TN 100 Percent Stator Ground Fault Protection 2.2

32 Reverse Power Relay – Antimotoring Protection 3.5

40 Loss-of-Field Protection 3.3

46 Negative-Sequence Current UnbalanceProtection for Generators 3.4

49 Stator Thermal Protection –51G Time-Overcurrent Ground Relay 2.2

51TG 1&2 Backup for Ground Faults –

Device Number Function Tutorial Chapter

51VVoltage-Controlled or Voltage-Restrained

Time-Overcurrent Relay – Backup for System and Generator Phase Faults

2.4

59 Overvoltage Protection 3.2

59G Overvoltage Relay – Stator Ground Fault Protection for Generators 2.2

60 Voltage Balance Relay – Detection of Blown Voltage Transformer Fuses 3.7

63 Transformer Fault Pressure Relay –62B Breaker Failure Timer 2.564F Field Ground Fault Protection 2.371 Transformer Oil or Gas Level –78 Loss-of-Synchronism Protection 3.6

Device Number Function Tutorial Chapter

81 Frequency Relay – Both Underfrequency and Overfrequency Protection 3.1

86 Hand-Reset Lockout Auxiliary Relay 5.1

87G Differential Relay – Primary Phase Fault Protection for Generators 2.1

87N Stator Ground Fault Differential Protection 2.2

87T Differential Relay – Primary Protection for Transformers –

87U Differential Relay – Overall Generator and Transformer Protection 2.2

60

87O

50/27

87T

S

Unit Transformer

Unit Differential

71

63Transformer Fault Pressure

Oil Low

51TG151

TG2Transformer Neutral

Overcurrent

5364F

41

Field Ground

242

Voltage Balance

Second V/Hz

78

40

81

241

Frequency

V/Hz

Loss of Synchronism

Loss of Field

59

87G

49

32

ReversePower

Generator Differential

Auxiliary VTs

46 21/51V

Negative Sequence

System Backup(Note 2)

Stat. Temp

59G

50/51G

Generator Neutral

Overvoltage

Generator Neutral

Overcurrent

63

71

UAT Oil Low

UAT Fault Pressure

UAT

5051

UAT Backup

51TG1

51TG2

UAT Neutral Overcurrent

Unit Auxiliary Bus Phase Time

Overcurrent

51

A 87T UAT Differential

(Note 1)

Inadv. Energ.(Note 4)

27TN

100 Percent Stator Ground

(Note 3)1. Dotted devices optional.2. Device 21 requires external timer. See Chapter 2.4.3. See Chapter 2.2 regarding 100 percent ground protection.4. Device 50 requires external timer. See Chapter 4.1.

Notes:

Field Breaker

Overvoltage

Generator protective relaying technology has evolved from discrete electromechanical and static relays to digital multifunction protection systems

With availability, additional performance, economic advantages, and reliability of digital multifunction protection systems, this advanced technology is incorporated into most new protection schemes

In most cases, new generators are protected with one of the following:

Dual MGPSs

Single MGPS, possibly backed up by single-function relays

Microprocessor

Other Analog Inputs

One or More Power Supplies

Digital Inputs

ROM

RAM

Data Acquisition

System

Inputs Outputs

Voltage Inputs

Current Inputs

Targets

User Interface

EEPROM

Communications

Digital Outputs

11GMGPS #1

Relaying Functions24

27/5932-132-240464950

51V or 2150/51G

59G607881

87G27TH or 59THD or 64S

11GMGPS #2

Relaying Functions24

27/5932-132-240464950

51V or 2150/51G

59G60

64F81

87G27TH or 59THD or 64S

52

87O

87AT87T

52

Generator Transformer

High-Voltage System Bus

Auxiliary Bus

Field

Note: Only use functions as appropriate.

Saturation

Stator differential protection does not detect turn-to-turn faults

Current can be 6 to 7 times nominal and can damage stator

Use turn-to-turn protection schemes to detect and avoid damage

Imperfection in generator construction

Temperature variations

Winding connections

External faults

Terminal voltage and load variations

The Method of Generator Neutral Grounding Determines its Performance During Ground Faults

Solidly GroundedLow ImpedanceHigh ImpedanceHybrid GroundingUngrounded

Multiple Bus (No/Low Z/High Z)Directly connected to busLikely in industrial, commercial, and isolated systemsMay have problems with circulating 3rd harmonic▪ Use of single grounded machine

can helpAdds complexity to discriminate ground fault source if ground resistance is high (less than 25A)

BUS

G G G

Same type of grounding used on 1 or mutiple generators

62

400 A

2000/5

2000/5

8780%

• 45MVA Generator

• 2000/5 CTs

• 87 Set at 0.2A Pickup

• 20% of Winding Not Protected

Low Resistance Grounding Systems

Percentage of Stator Winding Unprotected

87G – Generator Differential

87GD – Generator Ground Differential

51N – Neutral Overcurrent

IG

IA

IB

IC

3I0IG

Residual currentcalculated fromindividual phasecurrents. ParalleledCTs shown toillustrate principle.

0

90

180

270IG

3IO

-3Io x IG cos (180) = 3IoIG

IG

IA

IB

IC

3I0IG

Residual currentcalculated fromindividual phasecurrents. ParalleledCTs shown toillustrate principle.

0

90

180

270

IG

3IO-3Io x IG cos (0) = -3IoIG

59N, 3V0 overvoltage, covers ≈ 95% of windingTuned to the fundamental frequencyMust work properly from 10 to 80 Hz during startup.

3rd Harmonic methods cover remaining 5% of winding near neutral

27TN, 3rd harmonic undervoltage59D, Ratio of 3rd harmonic voltage at terminal and neutral ends of winding

64S, Subharmonic voltage injection, covers 100% of winding

High-impedance ground limits ground fault current (limits damage on internal winding to ground fault)

Conventional neutral or zero-sequence overvoltage relay (59G) provides coverage for the ground faults involving up to 90%–95% of the winding from phase terminal

51G connected in the primary or secondary neutral circuit can be used as a backup to 59G

R 59G

Last 5%–10% near neutral not covered by neutral overvoltage relay (59G) because a ground fault in this winding region bypasses grounding transformer or resistor (R) or 59G, solidly grounding the machine

R 59G

R 59G

XHL Sensitively set 59G relay to detect ground faults (up to 95% of the winding) can also pick up for faults on the HV side of GSU or in the VT secondary circuit

R

Co CHL

3Io

Io

Zero-Sequence Network

3R Xo

XHLV0VR

0R 0

0 HL

ZV : V •Z X

⎛ ⎞= ⎜ ⎟+⎝ ⎠

Third-harmonic voltage develops in stator due to inherent presence of third harmonic flux in the rotor field

Rotor MMF

R

Co

3I3h

I3h A, B, C

Generator winding and terminal capacitances provide path for the third-harmonic stator current via grounding resistor

Machine construction – the pitch of the stator

Levels of excitation (MVAR) and machine output (MW)

Terminal capacitance

Present in terminal and neutral ends

Can vary with loading

Detects ground faults near neutral

Note: If third harmonic goes away across neutral resistor, conclude a

ground fault near neutral

Full Load

No LoadNeutral

–V3RD

Fault at Terminal

Terminal

Fault at Neutral +V3RD

Terminal

Full LoadNo Load

Neutral

Normal OperationFull LoadNo Load

Terminal

NeutralNo Load

Full Load

+V3RD

–V3RD

R 59G

C0

Under normal conditions, 27N3 is picked up because of the third-harmonic voltage drop across neutral resistor

I3h

27N33I3h

R 59G

C0

For a fault close to neutral of the stator winding, 27N3 drops out because the fault bypasses the neutral resistor

A supervisory overvoltage (59C) relay located at the generator terminal blocks 27N3 operation during startup or shutdown to avoid misoperation

I3h

27N33I3h

R 59G 27N3

59G

27N3

0%5%

100%~95% of winding from terminal by 59G

~15%–30% of winding from neutral by 27N3

R 59G

59D

Compares third-harmonic voltage magnitude at the generator neutral to that at the generator terminals

Ferroresonance damping resistor

R 59G

59G

59D0%5%

100%

59D

59D

~95% of winding from terminal by 59G

~15%–30% of winding from neutral and terminal by 59D

Does not rely on third-harmonic signature of generator

Provides full coverage protection

Provides online and offline protection –prevents serious damage upon application of excitation

Is frequency independent

64S

20 Hz Generator

Injection Signal

Pickup Setting

Measurement Value

20 Hz Filter

Measurement Signal For stator ground fault, 20 Hz increases and relay (64S) operates

Hazards of field faults

Field ground protection

Tripping considerations

Field ground relay selection and settings

Field overcurrent

Exciter Field Breaker

Voltage Relay

Grounding Brush

Field

64F

DC

Shorts out part of field winding – expect unit vibrations, possible damageCauses local rotor current – expect rotor heating, distorted rotor, vibrationCauses arc damage at fault points

Ground #1

Ground #2

Use on generators with brushes

Has variable detection sensitivity

Exciter Field Breaker

Voltage Relay

Grounding Brush

Field

64F

DC

Exciter64F

+

–

Generator

Field Breaker Control

R2

R2

Voltage Relay

Varistor

Generator Field

Positive

Negative

Field Breaker Control

Test Pushbutton(optional)

ExciterField

Breaker

Brush

Field

+

–

CR

C1

C2

RR

64F

AC

Immediate tripping is recommended on first ground

However, most installations alarm and shutdown the machine in orderly manner if ground alarm persists

Relays should also be provided with time delays to override transients

System backup protection for generators consists of time-delayed protection for phase-to-ground and multiphase fault conditions

Backup generator protection schemes protect against failure of system protection and subsequent long-clearing system faults

Relay settings for backup relaying must be sensitive to detect low fault current conditions

Settings must balance opposing sensitivity requirements to detect distant faults and security to prevent unnecessary generator tripping

Use either distance or voltage-restrained overcurrent relay to

detect system multiphase faults.

Note locations of current and voltage transformers.

Use a time-inverse transformer neutral connected overcurrent relay for system ground faults.

Choose protection based on line relay type

If distance type, back up with distance

If time-overcurrent type, back up with V-R or V-C overcurrent

Time coordinate with system relays including breaker failure relaying

Voltage element supervises (torque controls) a sensitive, low pickup time-overcurrent element

Under fault conditions, voltage drops below set level – dropping out voltage element and permitting overcurrent element to operate

Cur

rent

Lev

el

V-R overcurrent consists of an overcurrent element whose pickup level varies as a function of voltage applied to relay

Normally, generator terminal voltage is above voltage setting, VS1, and current pickup setting is IS

Cur

rent

Pic

kup

Leve

l

When close-in fault occurs, voltage can drop below voltage setting, VS2, and current pickup level is reduced by factor k to kISFor voltages between VS1 and VS2, pickup level varies proportionately between IS and kIS

Cur

rent

Pic

kup

Leve

l

Set pickup below generator fault current using synchronous reactance

V-C pickup will likely be below rated current

V-R pickup must be above rated current

Calculate 51V voltage element setting to avoid 51V relay misoperation under extreme emergency conditions (with lowest expected system voltage)

To allow for selectivity, time-delay settings must be coordinated with transmission system primary and backup protection, including breaker failure time

Coordination is usually calculated with zero voltage restraint

Use three V-C or V-R time-overcurrent relays for complete multiphase fault coverage

Note that generator fault current may decay rapidly when low voltage is at generator terminals – overcurrent phase fault backup may not operate for system faults

Check setting with fault current decrement curve for particular generator and excitation system

Setting detects line fault when protection equipment fails

Relay impedance reach and time delay must be coordinated with system primary and backup protection, including breaker failure time

Setting must remain conservatively above machine rating to prevent inadvertent trips on generator swings and severe voltage disturbances

F5

F4

F3

FLT

F1

F2

The impedance relay for each generator requires sensitive settings to detect

faults at the ends of long lines in the

presence of other sources.

Sensitive settings may cause backup relays to unnecessarily trip generator under some loading conditions or for minor, stable swings

With this system configuration, it is generally possible to set backup relays to detect only close-in faults

Redundant line relaying and breaker failure relaying are necessary for line, bus, and transformer protection

Set impedance relay to smallest of thethree following criteria:

120% of longest line (with infeed) – if unit is connected to breaker-and-a-half bus, calculate percent using adjacent line length

50%–66.7% of load impedance (200%–150% of generator capability curve) at machine-rated power factor

80%–90% of load impedance (125%–111% of generator capability curve) at relay maximum torque angle (MTA)

30.0

25.0

20.0

15.0

10.0

5.0

0 20.015.010.0–10.0 5.0–5.0

–5.0

50-67% of GCC @ RPFA

Shortest Line (No Infeed)

Transformer High Side

Zone 2

Zone 1

MTA

RPFA

GCC

Longest Line(With Infeed)75.5 Ohms

jX

R

GCCZone 1Zone 2System

Zone 1 set to cover 120% of GSU impedance.

Zone 2 limited to 67% of generator capability curve

at rated power factor.

Zone 2 reach will not provide adequate phase fault system backup protection as it would

require an extremely large setting. The only way to ensure adequate protection to avoid sustained currents to the fault is to provide redundant transmission system protection.

Provides for tripping of backup breakers when the generator breaker does not open after trip initiation upon detection of

FaultAbnormalcondition

Open circuit to trip coilMechanism fails to open breakerBreaker opens but breaker contacts fail to interrupt faultTripping of circuit breaker left open after maintenance

Generator trips may not always be from high-current events (faults)

Overexcitation

Overvoltage

Sequential tripping

Need to include breaker auxiliary contact status in addition to current detectionBF protection should be fast enough to maintain stability but not so fast as to compromise tripping security

Breaker flashover is a type of breaker failureBreaker flashover is most likely to occur just prior to synchronizing or just after generator is removed from service

Three-phase simultaneous flashovers are rare, thus most protection schemes are designed to detect the flashover of one

or two poles

Underfrequency occurs as the result of sudden reduction in input power through loss of generators or key intertie importing power

Overfrequency occurs as the result of sudden loss of load or key intertie exporting power

Regional reliability councils will typically provide settings for underfrequency load shedding and generator tripping

Load shedding schemes must coordinate and meet regional criteria

Generator tripping criteria must accommodate any frequency excursion during any islanding scenario

Generator tripping permitted on or below curve without requiring additional equivalent automatic

load shedding.

60

59

58

57

56

550.1 3.31 10 100 300

Time (s)

Freq

uenc

y (H

z)

Operation outside shaded area is limited in extent, duration, and frequency of occurrence

Severe restrictionscould be imposed onthe generator itself

Possibility of frequency operational limits exists for the generator in the form of time-frequency characteristics

V%

f%

106

104

102

100 102

98

96

104

94

989694

Copyright ©2005 IEC, Geneva Switzerland

Protection of the long tuned blading in the low-pressure turbine element for steam units

Possibility of cumulative blading fatigue and blading failure

Similar limitations for combustion and combined-cycle turbines

Virtually no frequency limitations for hydro generating units

Example of fictitious steam turbine operational limits shown in the plot

Prohibited OperationRestricted Time

Operating Frequency Limits

Continuous Operation

Restricted Time Operating Frequency Limits

Prohibited Operation

62

61

60

59

58

57

56

0.0010.005

0.010.05

0.100.50

1.05.0

10.050.0

100.0Time (Minutes)

Obtain turbine capability from manufacturer

Verify if IEC 60034-3:2007 is applicable

Have manufacturer approve protectionscheme

63

62

61

60

59

58

57

56

55

541000100101

Continuous Operating Region

10-Minute Maximum

Total Accumulated Time Limit (Minutes)

Limits similar to steam turbine

Example of frequency limits in the plotFr

eque

ncy

(Hz)

V/Hz application can result in:

Heating of stator core iron

Stray flux increasing beyond design limits causing additional heating

Overvoltage application:

Stresses stator insulation and connected components

Cannot be reliably detected using V/Hz alone

Offline generator voltage regulator problems

Operating error during unit synchronizing

Control failure

VT fuse loss in voltage regulator (AVR)System problems

Unit load rejection: full load, partial rejection

Power system islanding during major disturbances

Generators: 1.05 pu (generator base)

Transformers:

1.05 pu at rated load at 0.8 PF

1.1 pu at no load

V%

f%

106

104

102

100 102

98

96

104

94

989694

Copyright ©2005 IEC, Geneva, Switzerland

100

105

110

115

120

125

130

0.1 1 10 100

Time (minutes)

110

120

130

140

0.01 0.1 1 10 100

Individual manufacturers should be consulted for limits

of a specific transformer.

V/H

z (%

)

Limiting factors are rotor and stator thermal limits

Underexcited limiting factoris stator end iron heat

Excitation control setting control is coordinated with steady-state stability limit (SSSL)

Minimum excitation limiter (MEL) prevents exciter from reducing the field below SSSL

Reactive Power Into System

Reactive Power Into Generator

Rotor Winding Limited

MEL

Stator End Iron Limited

SSSL

Stator Winding Limited

+ MWReal Power Into System0

+MVAR

Overexcited

Underexcited

–MVAR G

MVAR

MWSystem

MVARG

MWSystem

Field open circuit

Field short circuit (flashover across slip rings)

Accidental tripping of field breaker

Voltage regulator control system failure

LOF to main exciter

Loss of ac supply to excitation system

Machine that initially operates at 30% load and underexcited. Impedance locus follows path from E to F to G and oscillates in region between F and G

Generally for any loading, impedance terminates on or varies from D to L

Impedance variation with the machine operating at or near full load – locus follows path from C to D

Two modern offset mho relays can be used

Relay with 1.0 pu impedance diameter detects LOF condition from full load to about 30% load

First relay is set with short time delay; 0.1-second delay suggested for security against misoperation during transients

Diameter = 1.0 puOffset =

Diameter = Xd

0.5

–R

–1

–2

–1 –X 1 2

+X

+R

′dX2

Second relay is set with time delay; 0.5 to 0.6 seconds provides protection for LOE condition up to no load

Two offset mho relays provide LOE protection for any loading level

Both relays are set with offset of X′d/2

Diameter = 1.0 puOffset =

Diameter = Xd

0.5

–R

–1

–2

–1 –X 1 2

+X

+R

′dX2

Experience has shown that these settings are secure over a wide range of system conditions. However, transient

stability analysis should be performed to verify this.

MEL and LOF characteristicare coordinated so they do not overlap

MEL prevents leading var excursions into the LOF characteristic to avoid relay misoperation for system transients

Negative-offset mho element characteristic leaves underprotected area relative to SSSL and stator end iron limit curve of the machine capability

0.8

0.4

0

–0.4

–0.8

0.4 0.8 1.20

Generator Capability

SSSL

LOF Relay

pu (MW)

Q

P

MEL

Generator

G

GSU SystemReactance

VXd XT

XSWhere

Xe=XT + XS

V2 1_ + 1 2 Xe Xd

Per Unit MW

Per Unit Mvar

V2 1 1 2 Xe Xd

MW - Mvar PER UNIT PLOT

X

R

Xd + Xe 2

Xe

Xd - Xe 2

R-X DIAGRAM PLOT

This scheme combines positive-offset mho relay, directional relay, and undervoltage relay applied at generator terminals and set to look into machine

Directional unit supervises mho unit because positive-offset allows it to operate for faults external to generator terminals

XS

1.1 (Xd)

Offset =

Machine Capability

MEL

SSSL

Z2 Setting

Z1 Setting

R

X

′dX2

Improves coverage

System AsymmetriesOpen system circuits

Downed conductors

Stuck breaker poles or open switchesUnbalanced loads

Untransposed transmission lines

Single-phase GSU with unequal impedancesUnbalanced system faults

Strongest I2 source is generator phase-to-phase fault

Generators connected with delta-wye GSU transformer

System ground faults appear as phase-to-phase faults to the generator

Generator ground faults typically do not create as much I2

I2 in the stator creates a magnetic field component that rotates in opposite direction of rotor and power system (positive-sequence) field component

As a result, double-frequency current is induced in rotor

At twice fundamental frequency, skin effect promotes current in rotor surface areas and, to a smaller degree, in the field winding

Beyond a point, the induced surface currents can cause heating of metal

wedges that hold field windings and / or retaining rings on rotor ends, causing them

to anneal, expand, and loosen with catastrophic results

For salient-pole machines, double-frequency currents concentrate at pole faces and teeth

Much current appears in the pole-face amortisseur windings

Continuous Unbalance Current CapabilityGenerator Type Permissible I2 Stator

Rating PercentSalient Pole

Connected Amortisseur WindingsNonconnected Amortisseur Windings

105

Cylindrical RotorIndirectly CooledDirectly Cooled

To 350 MVA351–1250 MVA1251–1600 MVA

10

88 – [(MVA-350)/300)]

5

Short-Time Unbalance Current Capability

Generator TypeK Permissible

(I2 in pu)Salient Pole 40Synchronous Condenser 30Cylindrical Rotor

Indirectly CooledDirectly Cooled

0–800 MVA801–1600 MVA

30

10See Graph (next slide)

22I t

[ ]= − −22I t 10 (0.00625)(MVA 800)

=22I t 10

2 2It C

apab

ility

Values shown in Tables I and II of this chapter are for machines manufactured to IEEE C50 standards since 2005

Equipment nameplate data and / or the manufacturer may be consulted to verify machine capabilities

Has limited I2 sensitivity of about 60% of generator full-load rating

Generally insensitive to load unbalances or open conductors

Limited protection as damaging heat can occur even at low levels of I2

Allows backup protection for unbalanced faults (high levels of I2)

Allows relay characteristics that can match generator I2 capabilities

Allows I2 pickup settings down to 0.03 pu

Can be set to alarm at lower than generator limits, allowing plant operator to attempt to reduce I2 before trip occurs

Minimum Pickup 0.04 pu

K Setting Adjustable Over

Range 2–40

10

40

2

5

Negative-Sequence Current (per unit)0.1 101

0.10.01

1 • 103

100

1

10

Tim

e (s

econ

ds)

Generator Type Potential Damage

Diesel Risk of Explosion

Gas Turbine Gear Damage

Hydro Blade Cavitation

Steam Overheating

Generator Type Typical Motoring Power

Diesel 5% - 25%

Gas Turbine > 50%

Hydro 0.2 - 2%

Steam 0.5% - 3%

The 78 protection scheme protects the generator from OOS or pole-slip conditions

Common relay schemes for detecting generator OOS events include:

Single blinder

Double blinder

Concentric circle

When a Generator Goes Out-of-Step (Synchronism) with the Power System, High Levels of Transient Shaft Torque are Developed.

If the Slip Frequency Approaches Natural Shaft Frequency, Torque Produced can Break the Shaft.

High Stator Core End Iron Flux can Overheat and Damage the Generator Stator Core.

GSU Subjected to High Transient Currents and Mechanical Stresses.

171

One pair of blinders (vertical lines)

Supervisory offset mho

Mho limits reach of scheme to swings near the generator

Double Lens

Scheme

Double BlinderScheme

The most popular OOS protection is the single blinder scheme

Pickup area is restricted to shaded area defined by inner region of mho circle and area between Blinders A and B

Z3(t3)

Z0(t0)Z2(t2)

Z1(t1)

A B

Positive-sequence impedance must originate outside either Blinder A or Blinder B

It should swing through the pickup area and progress to the opposing blinder

Swing time should be greater than time-delay setting

Rotor Angle Generator G_1

Ang

le (d

egre

es)

Time (seconds)

–— Case 1 (tc = 90 ms), with controls



– – Case 1 (tc = 90 ms), without controls



R-X diagrams show trajectory followed by impedance seen by relay during disturbance

When an oscillation in the generator is stable, the point of impedance does not cross the line of the system

When an OOS condition occurs, the point of impedance crosses the line of the system impedance each time the slip is completed

R-X Diagram for Case 1R-X Diagram for Case 1R-X Diagram for Case 1

Case 1Tc = 0.09 ms

Case 2Tc = 0.18 ms

Case 3Tc = 0.19 ms

R (ohm) R (ohm)

X (o

hm)

R (ohm)

X (o

hm)

.

Apply OOS if swing impedance passes through GSU or generator

This zone is protected by differential relays that do not respond to power swings

Consider application of OOS if swing passes outside GSU but line protection is blocked or does not respond to swings

Common causesWiring failureOpen in VT draw-out assemblyBlown fuse due to short-circuitFuse left out after maintenance

Affected functions21, 27, 32, 40, 50/27, 51V, 67N, 78, 81Automatic voltage regulator (AVR runaway)

When fuse blows, unbalanced voltages created

Two sets of VTs required

Loss of One or Two Phases

Negative-sequence voltage & no negative-sequence current = fuse loss

Negative-sequence voltage & negative-sequence current = fault

Three-Phase Loss

Low three-phase voltages & low three-phase current & positive-sequence current = fuse loss

Low three-phase voltages & high three-phase currents = fault

Wye-wye grounded VTs on ungrounded system

Mitigation

Line-to-line rated VTs

Broken-delta VTs

VT loading resistor

Operating errors

Breaker head flashovers

Control circuit malfunctions

Combination of above

Typically, normal generator relaying is not adequate to detect inadvertent energizing

Generator behaves as induction motor

Flux induced into generator rotor causing rapid rotor heating

Rotor current is forced into negative-sequence path in rotor body

X1S = system positive-sequence reactance

X1T = transformer positive-sequence reactance

X2G = generator negative-sequence reactance

EG = generator terminal voltage

ES = system voltage

ET = transformer high-side voltage

I = current

R2G = generator negative-sequence resistance

UnitStep-Up

Transformer

EquivalentHigh-Voltage

System

Equivalent SystemVoltage

X1T X1S

X2G

R2G

Gen.EG ET ES

Gen.

I

Undervoltage (27) supervises low-set, instant overcurrent (50) –recommended 27 setting is 50% or lower of normal voltage

Pickup timer ensures generator is dead for fixed time to ride through three-phase system faults

Dropout timer ensures that overcurrent elementgets a chance to trip if voltage is higher than 27 setting during event

GeneratorPhaseVoltage

Generator Phase

Currents

Fault Inception

Breaker Opens

Large gas turbines are started as a motor using static frequency converter

V/Hz is maintained constant until rated voltage is reached, after which rated voltage is maintained

Extended operation occurs at low speeds while purging and firing cycles are completed

Generator must be protected during low-frequency operation

Some protection such as phase overcurrent and phase unbalance is provided by converter controls

To be effective, multifunction generator relays must maintain protection down to low frequencies

At lower frequencies, protective functions may deviate from normal specifications

In some cases, protective functions may have to be disabled during starting because of possible false operation

Fault-to-ground on dc link cannot be detected by converter controls

Fault causes dc current to flow through any wye-connected VTs and generator ground

.

DC current saturates magnetic elements (VTs and distribution transformer in generator neutral)Damage can occur if fault is not cleared – PT can be damaged in approximately 50 msTwo strategies to address this fault include

Measure dc current in generator neutral (e.g., with transducer) and use dc relay and turn converter off before damage occurs

Eliminate any ground path through magnetic elements during starting (use delta-connected VTs and disconnect generator neutral while starting)

To avoid damage to generator or GSU unit, synchronizing across breaker should be done within tight limitsTypical recommendations are

Electrical degrees ±10

Voltage 0 to +5 percent

Frequency difference < 0.067 Hz

Synchronizing equipment or supervising relays should take into account breaker closing time and relative slip, closing breaker in advance so that angle between generator and system at closing is as close to zero as possible

Generators may be operated at lower frequency during startup and shutdown

Electromechanical relays can become very insensitive at off nominal frequencies

Plunger-type overcurrent relays have flat characteristics down to low frequencies and are used to provide supplementary protection during start up and shutdown –these relays cannot be energized continuously and have to be disconnected during normal operation

Microprocessor-based relays can provide protection down to lower frequencies and generally do not require supplementary protection

(E)(D)(C)(B)(D)

(B)

(E)

(C)

(A)

(A)(F)

8

7

6

5

4

3

2

1

0 70 80605040302010

Pic

kup

in M

ultip

les

of 6

0 H

z P

icku

p

Frequency in Hz

Harmonic Restraint Transformer Differential Relay

Plunger-Type Current RelayInduction Overcurrent RelayGenerator Differential RelayGenerator Ground Relay

Plunger-Type Voltage Relay

(A)(B)(C)(D)(E)(F)

Generator protection functions with same trip / shutdown modes are grouped together

Operated by protective functions, auxiliary lockout relays, 86G (usually hand-reset), perform most tripping

Where possible, primary and backup relays trip via separate paths / lockouts

Includes tripping of all electrical and mechanical power sources

Provides fastest way to isolate generator

Does not shut down prime mover

Used when abnormality can be corrected quickly allowing fast reconnection

Only trips generator breaker(s)

Used when disturbance is on system and it is desired to have generator run its own auxiliaries

Used to prevent overspeed when delayed tripping of breakers is not detrimental –following a prime mover trip, planned or unplanned, breakers are tripped after reverse or low (hydro) power is detected

Not used for clearing faults

Much tripping philosophy depends on ability of generating unit to continue operating after disconnection from system (full load rejection)

If unit cannot support its own auxiliaries, then a tripping mode that transfers auxiliaries should be incorporated

Table II provides suggested steam unit trip logic by IEEE protective function numbers

Some functions are alarmed only

In general, G means “generator” and Nmeans “neutral” or “ground”

21 or 51V2432404650/2750/51G51TG250/51 UAT59

59G6363UAT67N7887G87GN87T87T UAT87O

51TG1 and 81 are examples of functions set to trip in unit separation mode

Table III provides typical tripping for hydroelectric units

Trip requirements are similar to thermal generators but may need slightly different slip / shutdown operations

Slower rotation devices

Different mechanical control devices

A generator disconnect switch is often used when tie to transmission system is dual-breaker arrangement

Sometimes generator protective functions are enabled / disabled by utilizing auxiliary switch contacts based on position of disconnect switch

Be cautious about bad or incorrect disconnect position status leaving generator unprotected

ieee generator protection tutorial presentation

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