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, Chair Christopher Ruckman, Vice Chair Hasnain Ashrafi Gabirel Benmouyal Zeeky Bukhala Stephen P. Conrad Everett Fennell Dale Finney Dale Fredrickson Jonathan D. Gardell Juan Gers Randy Hamilton Wayne Hartmann Gerald Johnson Patrick M. Kerrigan Sungsoo Kim Prem Kumar

Hugo Monterrubio Charles Mozina Mukesh Nagpal Brent Oxandale Russell W. Patterson Mike Reichard Mohindar Sachdev Kevin Stephan Sudhir Thakur Demetrios Tziouvaras Joe Uchiyama Quintin Verzosa, Jr. Thomas Wiedman Michael Wright John Wang Murty V. V. S. Yalla

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.

5

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. 6

Fundamentals

Multifunction Generator Protection Systems

Stator Phase Fault Protection

Stator Ground Fault Protection

Field Fault Protection

System Backup Protection

Generator Breaker Failure

Abnormal Frequency Protection

Overexcitation and Overvoltage Protection

Underexcitation / Loss-of-Excitation Protection

Current Unbalance (Negative-Sequence) Protection

Loss of Prime Mover (Antimotoring) Protection

Out-of-Step Protection

Voltage Transformer Signal Loss

Inadvertent Energization Protection

Other Protective Considerations

Tripping Modes



Basic design and operation of synchronous generators

Power system connections

Behavior under short-circuit conditions

Generator grounding

Generator stability

IEEE guidelines

Device numbers

Reactive Power Into System + MVAR Overexcited

Rotor Winding Limited

MW System

G

MVAR Normal Overexcited Operation

Overexcitation Limiter (OEL)

Stator Winding Limited + MW Real Power Into System

0

Underexcitation Limiter (UEL) Underexcited – MVAR Reactive Power Into Generator

MW

Underexcited Operation

G Stator End Iron Limited

Steady-State Stability Limit

System MVAR

kV 2 ⎛ RC ⎞ MVA = ⎜ ⎟ Z ⎝ RV ⎠ kV 2 ⎛ RC ⎞ Z= ⎜ ⎟ MVA ⎝ R V ⎠

Angle β Angle β

X

–R

R β Z

–X

Current

Current

Current

Accumulation of Damage Over Time

wattseconds

8000 wattseconds

6000 4000

Total Generator

2000 0 0.01

System 0.1 1 time, seconds

10

Most damage occurs in period after the generator breaker opens

Types of Instability

Steady-State

Transient

Dynamic

Pmax =

Pe =

Eg Es X

(

sin θg − θs

)

Power Flow L1 L2 L3

Eg∠θg

Power POWER System

SYSTEM

L4

Es∠θs

Eg Es X

Generator

GSU

G Xd V

XS Where: XT Xe = XT + XS

Per-Unit MVAR

V2 2

⎛ 1 1 ⎞ − ⎜ ⎟ X X d ⎠ ⎝ e

System Reactance

X Xe

V2 2

⎛ 1 1 ⎞ + ⎜ ⎟ X X d ⎠ ⎝ e

Xd − Xe 2

R

Xd + Xe 2

Per-Unit MW

MW-MVAR Per-Unit Plot

R-X Diagram Plot

Es∠Θs

Power System

Three-Phase Short Circuit

Substation 1

2

GSU 78 = Out-of-Step Protection Es = System Voltage Eg = Generator Voltage s = System Voltage Phase Angle g = Generator Voltage Phase Angle

78 G

Eg∠Θg

T

Pmax =

Maximum Power Transfer

Eg Es X

All Lines in Service Breakers 1 and 2 Tripped

A2 PM = Pe

Pe = A1 θC 0

90° θg – θs

180°

Eg Es X

(

sin θg − θs

)

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 in

Std. 242, IAS Buff Book

C37.102, IEEE Guide for Generator Protection

C37.101, IEEE Guide for AC Generator Ground Protection

C37.106, 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 Chapter

11

Multifunction Protection System

5.2

21

Distance Relay – Backup for System and Generator Zone Phase Faults

2.4

24

Volts / Hertz Protection for Generator Overexcitation

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 Unbalance Protection 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

51V

Voltage-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

2.5

64F

Field Ground Fault Protection

2.3

71

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

Transformer Fault Pressure

S

63 Oil Low 71

87T

51 TG1

Unit Transformer

51 Transformer Neutral TG2 Overcurrent

87O Unit Differential

50 51

Second V/Hz

24 2

UAT Backup

UAT Oil Low 71

Voltage Balance

60

UAT Fault Pressure

63 UAT

Overvoltage 59 50/ 27 Inadv. Energ. (Note 4)

81

UAT Neutral Overcurrent

51 Unit Auxiliary Bus Phase Time Overcurrent

78 Loss of Synchronism 24 1

V/Hz

A

87T

UAT Differential

40

Loss of Field

Auxiliary VTs

32

Field Breaker

51 51 TG1 TG2

Frequency

Reverse Power

49

41 Stat. Temp 64F

53

87G

Generator Differential

Field (Note 1) Ground 21/ 51V

46 Negative Sequence

59G

50/ 51G

Generator Neutral Overvoltage

Generator Neutral Overcurrent

System Backup (Note 2)

27 TN

100 Percent Stator Ground (Note 3)

Notes: 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.



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

Inputs

Outputs ROM RAM

Voltage Inputs

EEPROM Current Inputs

Data Acquisition System

User Interface Microprocessor

Other Analog Inputs

Targets Digital Outputs

Digital Inputs One or More Power Supplies

Communications

High-Voltage System Bus

52

Generator Transformer 87AT

87T

Auxiliary Bus 52

87O 11G MGPS #1 Relaying Functions 24 27/59 32-1 32-2 40 46 49 50 51V or 21 50/51G 59G 60 78 81 87G 27TH or 59THD or 64S

Field

11G MGPS #2 Relaying Functions 24 27/59 32-1 32-2 40 46 49 50 51V or 21 50/51G 59G 60 64F 81 87G 27TH or 59THD or 64S

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 Grounded Low Impedance High Impedance Hybrid Grounding Ungrounded

Multiple Bus (No/Low Z/High Z)

BUS

Directly connected to bus Likely in industrial, commercial,

and isolated systems May have problems with circulating 3rd harmonic ▪ Use of single grounded machine can help

Adds complexity to discriminate

ground fault source if ground resistance is high (less than 25A)

G

G

G

Same type of grounding used on 1 or mutiple generators

Low Resistance Grounding Systems

• 45MVA Generator

2000/5

• 2000/5 CTs 80%

2000/5

87

• 87 Set at 0.2A Pickup • 20% of Winding Not Protected

400 A

62

Percentage of Stator Winding Unprotected

87G – Generator Differential 87GD – Generator Ground Differential 51N – Neutral Overcurrent

IA IB

Residual current calculated from individual phase currents. Paralleled CTs shown to illustrate principle.

90

IC IG

IG

3I O

3 I0

0

180

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

IG 270

IA IB

Residual current calculated from individual phase currents. Paralleled CTs shown to illustrate principle.

90

IC IG

IG

3I 0

180

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

0

IG 3I O 270

59N, 3V0 overvoltage, covers ≈ 95% of winding Tuned to the fundamental frequency Must work properly from 10 to 80 Hz during startup.

3rd Harmonic methods cover remaining 5% of winding near neutral 27TN, 3rd harmonic undervoltage 59D, 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 zerosequence overvoltage relay (59G) provides coverage for the ground faults involving up to 90%–95% of the winding from phase terminal R

59G

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

XHL

R

59G

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

Io

Co

CHL

⎛ Z0 ⎞ VR := V0 • ⎜ ⎟ Z + X HL ⎠ ⎝ 0

Zero-Sequence Network

XHL R 3Io

VR

3R

Xo

V0

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

Rotor MMF

I3h A, B, C

Co

Generator winding and terminal capacitances provide path for the third-harmonic stator current via grounding resistor R 3I3h

Machine construction – the pitch of the stator

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

Terminal capacitance

+V3RD

Normal Operation Neutral No Load

Full Load No Load Terminal

Full Load

+V3RD Full Load No Load

Neutral

Terminal Fault at Terminal Neutral No Load

Terminal

Full Load –V3RD

Can vary with loading Detects ground faults near neutral

–V3RD Fault at Neutral

Present in terminal and neutral ends

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

I3h

C0

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

3I3h

R

59G

27N3

I3h

C0

3I3h

R

59G

27N3

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

100%

59G

~95% of winding from terminal by 59G ~15%–30% of winding from neutral by 27N3

27N3 5% 0%

R

59G

27N3

Compares third-harmonic voltage magnitude at the generator neutral to that at the generator terminals Ferroresonance damping resistor 59D

R

59G

100%

~95% of winding from terminal by 59G

59G

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

59D 59D

5% 0%

R

59G

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

Injection Signal 20 Hz Generator

Pickup Setting

64S

Measurement Signal 20 Hz Filter

Measurement Value

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

Field

Field Breaker

Exciter

64F DC

Voltage Relay Grounding Brush

Ground #1 Ground #2

Shorts out part of field winding – expect unit vibrations, possible damage

Causes local rotor current – expect rotor heating, distorted rotor, vibration

Causes arc damage at fault points

Field

Field Breaker

Exciter

64F DC

Use on generators with brushes

Has variable detection sensitivity

Voltage Relay Grounding Brush

Field Breaker Control

Positive Varistor

R2 Generator

Generator Field

+ Exciter 64F

Test Pushbutton (optional)

Field Breaker Control

Voltage Relay

–

R2

Negative

Field +

Exciter Field Breaker

– Brush CR

C2

C1 AC R

64F

R

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

Note locations of current and voltage transformers.

Use either distance or voltagerestrained overcurrent relay to detect system multiphase faults.

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

98

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

Current Level

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

Current Pickup Level

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

Current Pickup Level

When close-in fault occurs, voltage can drop below voltage setting, VS2, and current pickup level is reduced by factor k to kIS

For voltages between VS1 and VS2, pickup level varies proportionately between IS and kIS

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

FLT

F4

F1

F3

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 the three 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)

GCC Zone 1 Zone 2 System

jX 30.0 Longest Line (With Infeed) 75.5 Ohms

25.0

20.0

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.

Zone 2 15.0

10.0

50-67% of GCC @ RPFA

Shortest Line (No Infeed)

RPFA

Zone 1 –5.0

0

Transformer High Side –5.0

GCC

MTA

5.0

–10.0

Zone 2 limited to 67% of generator capability curve at rated power factor.

5.0

10.0

15.0

R 20.0

Zone 1 set to cover 120% of GSU impedance.



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

Fault

Abnormal condition

Open circuit to trip coil Mechanism fails to open breaker Breaker opens but breaker contacts fail to interrupt fault Tripping 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 detection BF protection should be fast enough to maintain stability but not so fast as to compromise tripping security

Breaker flashover is a type of breaker failure Breaker 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

60

Frequency (Hz)

59

58

57 Generator tripping permitted on or below curve without requiring additional equivalent automatic load shedding.

56

55 0.1

1

3.3 Time (s)

10

100

300

V%

106

Operation outside shaded area is limited in extent, duration, and frequency of occurrence Severe restrictions could be imposed on the generator itself

94

96

104

102

98

100

104

102

f%

98

96

Possibility of frequency operational limits exists for the generator in the form of time-frequency characteristics 94

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 62

61

Restricted Time Operating Frequency Limits

60

Continuous Operation

Prohibited Operation

59 Restricted Time Operating Frequency Limits 58 57 56 0.001

Prohibited Operation 0.005 0.01

0.05

0.50 0.10 1.0 Time (Minutes)

5.0

10.0

50.0

100.0

Obtain turbine capability 63 62 from manufacturer 61

Verify if IEC 60034-3: 2007 is applicable

60

Have manufacturer approve protection scheme

57

Continuous Operating Region

59 58 10-Minute Maximum

56 55 54 1

10 100 1000 Total Accumulated Time Limit (Minutes)

Limits similar to steam turbine

Example of frequency limits in the plot

Frequency (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% 106

104

102 94

96

98

100

98

96

94 Copyright ©2005 IEC, Geneva, Switzerland

102

104 f%

130 125 120 115 110 105 100 0.1

1

10

100

140

130

120 Individual manufacturers should be consulted for limits of a specific transformer. 110 0.01

0.1

1 Time (minutes)

10

100

V/Hz (%)



Limiting factors are rotor and stator thermal limits Underexcited limiting factor is 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

Rotor Winding Limited

+ MVAR

MW G

System MVAR

Overexcited

Stator Winding Limited + MW

Real Power Into System

0

MEL Underexcited – MVAR Reactive Power Into Generator

MW SSSL Stator End Iron Limited

System

G MVAR

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

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

Two modern offset mho relays can be used

+X

0.5 –R

+R Diameter = 1.0 pu Offset =

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

X′d 2

–1

–2 Diameter = Xd –1

–X

1

2

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

0.5

Two offset mho relays provide LOE protection for any loading level

–1

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

+X

–R

+R Diameter = 1.0 pu Offset =

X′d 2

–2 Diameter = Xd –1

–X

1

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.

2

MEL and LOF characteristic are 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

Q

Generator Capability

0.4

0

LOF MEL Relay SSSL

–0.4

–0.8

P 0

0.8

0.4

pu (MW)

1.2

Generator

GSU

G Xd

Per Unit Mvar

V

XT

System Reactance XS Where Xe=XT + XS X Xe

V2 2

1 Xe

1 Xd

V2 2

1_ + 1 Xe Xd

Xd - Xe 2

R Xd + Xe 2

Per Unit MW

MW - Mvar PER UNIT PLOT

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 1.1 (X )

X

Z2 Setting

XS

Z1 Setting R X′d Offset = 2

Machine Capability

d

Directional unit supervises mho unit because positiveoffset allows it to operate for faults external to generator terminals

MEL

SSSL

Improves coverage



System Asymmetries

Open system circuits Downed conductors Stuck breaker poles or open switches

Unbalanced loads Untransposed transmission lines Single-phase GSU with unequal impedances

Unbalanced system faults

Strongest I2 source is generator phase-tophase 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 Capability Generator Type

Permissible I2 Stator Rating Percent

Salient Pole Connected Amortisseur Windings

10

Nonconnected Amortisseur Windings

5

Cylindrical Rotor Indirectly Cooled

10

Directly Cooled To 350 MVA

8

351–1250 MVA

8 – [(MVA-350)/300)]

1251–1600 MVA

5

Short-Time Unbalance Current Capability Generator Type

K Permissible I22 t (I2 in pu)

Salient Pole

40

Synchronous Condenser

30

Cylindrical Rotor Indirectly Cooled

30

Directly Cooled 0–800 MVA 801–1600 MVA

10 See Graph (next slide)

I22 t Capability

I22 t = 10

I22 t = 10 − [(0.00625)(MVA − 800)]

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

2

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

Time (seconds)

1 • 103

100

K Setting Adjustable Over Range 2–40

10

40 Minimum Pickup 0.04 pu

1

10 5 2

0.1 0.01

0.1 1 Negative-Sequence Current (per unit)

10



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

172

One pair of blinders (vertical lines)

Supervisory offset mho

Mho limits reach of scheme to swings near the generator

Double Lens Scheme

Double Blinder Scheme

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

A

B

Z3(t3) Z0(t0) Z2(t2) Z1(t1)

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

Angle (degrees)

Rotor Angle Generator G_1 –—

Case 1 (tc = 90 ms), with controls

–—


–—


– – Case 1 (tc = 90 ms), without controls – – Case 2 (tc = 180 ms), without controls – – Case 3 (tc = 190 ms), without controls

Time (seconds)

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 1

X (ohm)

X (ohm)

.

R (ohm)

Case 1 Tc = 0.09 ms

R (ohm)

R (ohm)

Case 2 Tc = 0.18 ms

Case 3 Tc = 0.19 ms

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 causes Wiring failure Open in VT draw-out assembly Blown fuse due to short-circuit Fuse left out after maintenance

Affected functions 21, 27, 32, 40, 50/27, 51V, 67N, 78, 81 Automatic 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 negativesequence path in rotor body

Unit Step-Up Transformer

Equivalent High-Voltage System

X1T

X1S

X1S = system positive-sequence reactance X1T = transformer positive-sequence reactance X2G = generator negative-sequence reactance

I

Gen.

Gen.

X2G

R2G

EG

ET

ES Equivalent System Voltage

EG = generator terminal voltage ES = system voltage ET = transformer high-side voltage I = current R2G = generator negative-sequence resistance

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 element gets a chance to trip if voltage is higher than 27 setting during event

Generator Phase Voltage Fault Inception

Breaker Opens Generator Phase Currents



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 ms

Two 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 limits

Typical 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

8

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

7

Pickup in Multiples of 60 Hz Pickup

6

5

(B)

(C)

(D)

(E)

(D) 4

3

(B) (C)

2

1

(A)

(E)

(A) 0

10

(F) 20

30

40 50 Frequency in Hz

60

70

(A)

Plunger-Type Current Relay

(B)

Induction Overcurrent Relay

(C)

Generator Differential Relay

(D) (E)

Generator Ground Relay Harmonic Restraint Transformer Differential Relay

(F)

Plunger-Type Voltage Relay

80



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 N means “neutral” or “ground”

21 or 51V 24 32 40 46 50/27 50/51G 51TG2 50/51 UAT 59

59G 63 63UAT 67N 78 87G 87GN 87T 87T UAT 87O

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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