IEEE Generator Protection Tutorial Presentation

Special Publication of the IEEE Power

System Relaying Committee

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Developed by a working group of the

Power System Relay Committee (PSRC)

ƒ First published in 1995 – widely presented

within the industry, including a presentation at the 2003 PPIC Conference

ƒ Updated, published, and presented for the

first time at the 2011 57th IEEE Pulp and Paper Industry Conference

ƒ Michael Thompson, Chair

ƒ Christopher Ruckman, Vice Chair ƒ Hasnain Ashrafi ƒ Gabirel Benmouyal ƒ Zeeky Bukhala ƒ Stephen P. Conrad ƒ Everett Fennell ƒ Dale Finney ƒ Dale Fredrickson ƒ Jonathan D. Gardell ƒ Juan Gers ƒ Randy Hamilton ƒ Wayne Hartmann ƒ Gerald Johnson ƒ Patrick M. Kerrigan ƒ Sungsoo Kim ƒ Prem Kumar ƒ Hugo Monterrubio ƒ Charles Mozina ƒ Mukesh Nagpal ƒ Brent Oxandale ƒ Russell W. Patterson ƒ Mike Reichard ƒ Mohindar Sachdev ƒ Kevin Stephan ƒ Sudhir Thakur ƒ Demetrios Tziouvaras ƒ Joe Uchiyama ƒ Quintin Verzosa, Jr. ƒ Thomas Wiedman ƒ Michael Wright ƒ John Wang ƒ Murty 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,

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.

ƒ Fundamentals

ƒ Multifunction Generator Protection Systems ƒ Stator Phase Fault Protection

ƒ Stator Ground Fault Protection ƒ Field Fault Protection

ƒ System Backup Protection ƒ Generator Breaker Failure

ƒ Abnormal Frequency Protection

ƒ Underexcitation / Loss-of-Excitation Protection

ƒ Current Unbalance (Negative-Sequence) Protection ƒ Loss of Prime Mover (Antimotoring) Protection

ƒ Out-of-Step Protection

ƒ Voltage Transformer Signal Loss ƒ Inadvertent Energization Protection ƒ Other Protective Considerations

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Basic design and operation of

synchronous generators

ƒ Power system connections

ƒ Behavior under short-circuit conditions

ƒ Generator grounding

ƒ Generator stability

ƒ IEEE guidelines

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 MVAR Normal Overexcited Operation Underexcited Operation G MW System G MVAR MW System

β X –X R –R Z 2 C V R kV MVA Angle Z R ⎛ ⎞ = _{⎜ ⎟} β ⎝ ⎠ 2 C V R kV Z Angle MVA R ⎛ ⎞ = _{⎜ ⎟} β ⎝ ⎠

Current

Current

0 2000 4000 6000 8000 time, seconds 0.01 0.1 1 10 wattseconds wattseconds Total Generator System

Accumulation of Damage Over Time

Types of Instability

ƒ Steady-State

ƒ Transient

(

)

X R Xe d e X X 2 − d e X X 2 + R-X Diagram Plot Per-Unit MVAR Per-Unit MW

MW-MVAR Per-Unit Plot

2 e d V 1 1 2 X X ⎛ ⎞ + ⎜ ⎟ ⎝ ⎠ 2 e d V 1 1 2 X X ⎛ ⎞ − ⎜ ⎟ ⎝ ⎠ G

Generator GSU System Reactance Xd V XT XS Where: Xe = XT + XS

Power System 1 2 78 G 78 = Out-of-Step Protection Es = System Voltage Eg = Generator Voltage

s = System Voltage Phase Angle g = Generator Voltage Phase Angle

T Three-Phase Short Circuit Substation GSU s s E ∠Θ g g E ∠Θ

g s max E E P X = Maximum Power Transfer PM = Pe A1 A2

All Lines in Service Breakers 1 and 2 Tripped θC 0 90° 180° θg – θs

(

)

ƒ Occurs when fast-acting AVR control

amplifies rather than damps small MW oscillations

ƒ Most likely to occur when generators

are remote from load centers

ƒ Power system stabilizer (PSS) damps

oscillations – required in Western United States

Latest developments reflected in

ƒ Std. 242, IAS Buff Book

ƒ C37.102, IEEE Guide for Generator Protection ƒ C37.101, IEEE Guide for AC Generator

Ground Protection

ƒ 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 –

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

60 87O 50/ 27 87T S Unit Transformer Unit Differential 71 63

Transformer Fault Pressure Oil Low

51 TG1

51

TG2Transformer Neutral _Overcurrent

53 64F 41 Field Ground 24 2 Voltage Balance Second V/Hz 78 40 81 24 1 Frequency V/Hz Loss of Synchronism Loss of Field 59 87G 49 32 Reverse Power Generator Differential Auxiliary VTs 46 _51V21/ 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 50 51 UAT Backup 51 TG1TG251 UAT Neutral Overcurrent Unit Auxiliary

Bus Phase Time Overcurrent 51 A 87T UAT Differential (Note 1) Inadv. Energ. (Note 4) 27 TN 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

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Generator protective relaying technology

has evolved from discrete electromechanical and static relays to digital multifunction

protection systems

ƒ With availability, additional performance,

economic advantages, and reliability of

digital multifunction protection systems, this advanced technology is incorporated into

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

ƒ Dual MGPSs

ƒ Single MGPS, possibly backed up by

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

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 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 52 87O 87AT 87T 52 Generator Transformer

High-Voltage System Bus

Auxiliary Bus

Field

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Stator differential protection does not

detect turn-to-turn faults

ƒ Current can be 6 to 7 times nominal

and can damage stator

ƒ Use turn-to-turn protection schemes to

ƒ Imperfection in generator construction

ƒ Temperature variations

ƒ Winding connections

ƒ External faults

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ The Method of Generator Neutral

Grounding Determines its Performance During Ground Faults

ƒ Solidly Grounded ƒ Low Impedance ƒ High Impedance ƒ Hybrid Grounding ƒ Ungrounded

ƒ Multiple Bus (No/Low Z/High Z) ƒ Directly connected to bus

ƒ Likely in industrial, commercial, and isolated systems

ƒ May have problems with circulating 3rd _harmonic

▪ Use of single grounded machine can help

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

BUS

G G G

62 400 A 2000/5 2000/5 87 80% • 45MVA Generator • 2000/5 CTs

• 87 Set at 0.2A Pickup

• 20% of Winding Not

Protected

Low Resistance Grounding

Percentage of Stator Winding

Unprotected

87G – Generator Differential

87GD – Generator Ground Differential 51N – Neutral Overcurrent

I_G I_A I_B I_C 3_I0 I_G Residual current calculated from individual phase currents. Paralleled CTs shown to illustrate principle. 0 90 180 270 I_G 3I_O

I_G I_A I_B I_C 3I₀ I_G Residual current calculated from individual phase currents. Paralleled CTs shown to illustrate principle. 0 90 180 270 I_G 3I_O

ƒ 59N, 3V0 overvoltage, covers ≈ 95% of winding

ƒ Tuned to the fundamental frequency

ƒ Must work properly from 10 to 80 Hz during startup.

ƒ 3rd Harmonic methods cover remaining 5% of

winding near neutral

ƒ 27TN, 3rd harmonic undervoltage

ƒ 59D, Ratio of 3rd harmonic voltage at terminal and

neutral ends of winding

ƒ 64S, Subharmonic voltage injection, covers

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

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

X_HL

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 C_{o CHL} 3I_o I_o Zero-Sequence Network 3R Xo X_HL V₀ V_R 0 R 0 0 HL Z V : V • Z X ⎛ ⎞ = _{⎜ ⎟} + ⎝ ⎠

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

R

C_o

3I_3h

I_{3h A, B, C}

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

ƒ Machine construction – the pitch

of the stator

ƒ Levels of excitation (MVAR) and

machine output (MW)

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 Load Neutral –V3RD Fault at Terminal Terminal Fault at Neutral +V3RD Terminal Full Load No Load Neutral Normal Operation Full Load No Load Terminal Neutral No 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

I_3h

27N3 3I_3h

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

I_3h

27N3 3I_3h

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 59D 0% 5% 100% 59D 59D ~95% of winding from terminal by 59G ~15%–30% of winding from neutral and

ƒ Does not rely on third-harmonic signature

of generator

ƒ Provides full coverage protection

ƒ Provides online and offline protection –

prevents serious damage upon application of excitation

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

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Hazards of field faults

ƒ Field ground protection

ƒ Tripping considerations

ƒ Field ground relay selection and settings

Exciter Field Breaker Voltage Relay Grounding Brush Field 64F DC

„ 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

Ground #1

ƒ Use on generators with brushes ƒ Has variable detection sensitivity Exciter Field Breaker Voltage Relay Grounding Brush Field 64F DC

Exciter 64F + – Generator Field Breaker Control R2 R2 Voltage Relay Varistor Generator Field Positive Negative Field Breaker Control Test Pushbutton (optional)

Exciter Field Breaker Brush Field + – CR C1 C2 R R 64F AC

ƒ Immediate tripping is recommended on

first ground

ƒ However, most installations alarm and

shutdown the machine in orderly manner if ground alarm persists

ƒ Relays should also be provided with time

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ System backup protection for

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

ƒ Backup generator protection

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

ƒ Relay settings for backup relaying

must be sensitive to detect low fault current conditions

ƒ 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.

ƒ Choose protection based on line relay

type

ƒ If distance type, back up with distance

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

V-C overcurrent

ƒ Time coordinate with system relays

ƒ Voltage element supervises (torque controls) a

sensitive, low pickup time-overcurrent element

ƒ Under fault conditions, voltage drops below set

level – dropping out voltage element and permitting overcurrent element to operate

ƒ V-R overcurrent consists of an overcurrent element

whose pickup level varies as a function of voltage applied to relay

ƒ Normally, generator terminal voltage is above

voltage setting, V_S1, and current pickup setting is I_S

ƒ When close-in fault occurs, voltage can drop below

voltage setting, V_S2, and current pickup level is reduced by factor k to kI_S

ƒ For voltages between V_S1 and V_S2, pickup level

varies proportionately between I_S and kI_S

ƒ Set pickup below generator fault current

using synchronous reactance

ƒ V-C pickup will likely be below rated current ƒ V-R pickup must be above rated current

ƒ Calculate 51V voltage element setting to

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

ƒ To allow for selectivity, time-delay settings

must be coordinated with transmission system primary and backup protection, including breaker failure time

ƒ Coordination is usually calculated with

ƒ Use three V-C or V-R time-overcurrent relays for

complete multiphase fault coverage

ƒ 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

ƒ Check setting with fault current decrement curve

ƒ Setting detects line fault when protection

equipment fails

ƒ Relay impedance reach and time delay must be

coordinated with system primary and backup protection, including breaker failure time

ƒ Setting must remain conservatively above

machine rating to prevent inadvertent trips on

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

ƒ Sensitive settings may cause backup relays

to unnecessarily trip generator under some loading conditions or for minor, stable swings

ƒ With this system configuration, it is generally

possible to set backup relays to detect only close-in faults

ƒ 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:

ƒ 120% of longest line (with infeed) – if unit is connected to

breaker-and-a-half bus, calculate percent using adjacent line length

ƒ 50%–66.7% of load impedance (200%–150% of generator

capability curve) at machine-rated power factor

ƒ 80%–90% of load impedance (125%–111% of generator

30.0 25.0 20.0 15.0 10.0 5.0 0 10.0 15.0 20.0 –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 GCC Zone 1 Zone 2 System

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.

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

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

ƒ Fault

ƒ Abnormal

ƒ Open circuit to trip coil

ƒ Mechanism fails to open breaker

ƒ Breaker opens but breaker contacts fail to

interrupt fault

ƒ Tripping of circuit breaker left open after

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

ƒ Overexcitation ƒ Overvoltage

ƒ Need to include breaker auxiliary contact

status in addition to current detection

ƒ BF protection should be fast enough to

maintain stability but not so fast as to compromise tripping security

ƒ Breaker flashover is a type of breaker

failure

ƒ 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

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

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

importing power

ƒ Overfrequency occurs as the result of

sudden loss of load or key intertie exporting power

ƒ Regional reliability councils will typically

provide settings for underfrequency load shedding and generator tripping

ƒ Load shedding schemes must coordinate

and meet regional criteria

ƒ 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 55 0.1 1 3.3 10 100 300 Time (s) Frequency (Hz)

ƒ Operation outside shaded area is

limited in extent, duration, and frequency of occurrence

ƒ Severe restrictions

could be imposed on the generator itself

ƒ 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 98 96 94 Copyright ©2005 IEC, Geneva Switzerland

ƒ Protection of the long tuned blading in the

low-pressure turbine element for steam units

ƒ Possibility of cumulative blading fatigue and

blading failure

ƒ Similar limitations for combustion and

combined-cycle turbines

ƒ Virtually no frequency limitations for hydro

Example of fictitious steam turbine operational limits shown in the plot

Prohibited Operation Restricted Time

Operating Frequency Limits

Continuous Operation

Restricted Time Operating Frequency Limits

Prohibited Operation 62 61 60 59 58 57 56 0.001 0.0050.01 0.050.10 0.50 1.0 5.010.0 50.0100.0 Time (Minutes)

ƒ Obtain turbine capability from manufacturer ƒ Verify if IEC 60034-3: 2007 is applicable ƒ Have manufacturer approve protection scheme 63 62 61 60 59 58 57 56 55 54 1000 100 10 1

Continuous Operating Region

10-Minute Maximum

ƒ Limits similar to steam turbine

ƒ Example of frequency limits in the plot

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ V/Hz application can result in:

ƒ Heating of stator core iron

ƒ Stray flux increasing beyond design limits causing

additional heating

ƒ Overvoltage application:

ƒ Stresses stator insulation and connected components ƒ Cannot be reliably detected using V/Hz alone

ƒ Offline generator voltage regulator problems

ƒ Operating error during unit synchronizing ƒ Control failure

ƒ VT fuse loss in voltage regulator (AVR)

ƒ System problems

ƒ Unit load rejection: full load, partial rejection

ƒ Generators: 1.05 pu (generator base) ƒ Transformers:

ƒ 1.05 pu at rated load at 0.8 PF ƒ 1.1 pu at no load

V% f% 106 104 102 100 102 98 96 104 94 98 96 94

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

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Limiting factors are rotor

and stator thermal limits

ƒ Underexcited limiting factor

is stator end iron heat

ƒ Excitation control setting

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

ƒ 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 + MW Real Power Into System 0 + MVAR Overexcited Underexcited – MVAR G MVAR MW System MVAR G MW System

ƒ Field open circuit

ƒ Field short circuit (flashover across slip rings)

ƒ Accidental tripping of field breaker

ƒ Voltage regulator control system failure

ƒ LOF to main exciter

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

ƒ Two modern offset mho

relays can be used

ƒ Relay with 1.0 pu impedance

diameter detects LOF

condition from full load to about 30% load

ƒ First relay is set with short

time delay; 0.1-second delay suggested for security

against misoperation during transients Diameter = 1.0 pu Offset = Diameter = Xd 0.5 –R –1 –2 –1 –X 1 2 +X +R ′_d X 2

ƒ Second relay is set with time

delay; 0.5 to 0.6 seconds provides protection for LOE condition up to no load

ƒ Two offset mho relays

provide LOE protection for any loading level

ƒ Both relays are set with

offset of X′_d/2 Diameter = 1.0 pu Offset = Diameter = Xd 0.5 –R –1 –2 –1 –X 1 2 +X +R ′_d X 2

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

ƒ MEL and LOF characteristic

are coordinated so they do not overlap

ƒ MEL prevents leading var

excursions into the LOF

characteristic to avoid relay misoperation for system transients

ƒ 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 1.2 0 Generator Capability SSSL LOF Relay pu (MW) Q P MEL

Generator G GSU System Reactance V Xd XT X_S Where Xe=X_T + X_S 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

ƒ This scheme combines

positive-offset mho relay, directional relay, and

undervoltage relay applied at generator terminals and set to look into machine

ƒ 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 ′ d X 2 Improves coverage

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

System Asymmetries

ƒ Open system circuits

ƒ Downed conductors

ƒ Stuck breaker poles or open switches

ƒ Unbalanced loads

ƒ Untransposed transmission lines

ƒ Single-phase GSU with unequal impedances

ƒ Strongest I₂ source is generator

phase-to-phase fault

ƒ Generators connected with delta-wye

GSU transformer

ƒ System ground faults appear as

phase-to-phase faults to the generator

ƒ Generator ground faults typically do not create

I₂ in the stator creates a magnetic field component that rotates in opposite

direction of rotor and power system (positive-sequence) field component

ƒ As a result, double-frequency current is

induced in rotor

ƒ 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

ƒ For salient-pole machines,

double-frequency currents concentrate at pole faces and teeth

ƒ 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

Nonconnected Amortisseur Windings

10 5 Cylindrical Rotor Indirectly Cooled Directly Cooled To 350 MVA 351–1250 MVA 1251–1600 MVA 10 8 8 – [(MVA-350)/300)] 5

Short-Time Unbalance Current Capability

Generator Type K Permissible

(I₂ in pu) Salient Pole 40 Synchronous Condenser 30 Cylindrical Rotor Indirectly Cooled Directly Cooled 0–800 MVA 801–1600 MVA 30 10

See Graph (next slide)

2 2

[ ] = − − 2 2 I t 10 (0.00625)(MVA 800) = 2 2 I t 10 2 It C 2 apabi lit y

ƒ Values shown in Tables I and II of this

chapter are for machines manufactured to IEEE C50 standards since 2005

ƒ Equipment nameplate data and / or the

manufacturer may be consulted to verify machine capabilities

ƒ Has limited I₂ sensitivity of about 60% of

generator full-load rating

ƒ Generally insensitive to load unbalances or

open conductors

ƒ Limited protection as damaging heat can

occur even at low levels of I₂

ƒ Allows backup protection for unbalanced

ƒ Allows relay characteristics that can

match generator I₂ capabilities

ƒ Allows I₂ pickup settings down to 0.03 pu

ƒ Can be set to alarm at lower than

generator limits, allowing plant operator

Minimum Pickup 0.04 pu K Setting Adjustable Over Range 2–40 10 40 2 5

Negative-Sequence Current (per unit)

0.1 1 10 0.1 0.01 1 • 103 100 1 10 T ime (seconds)

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

Generator Type Potential Damage

Diesel Risk of Explosion

Gas Turbine Gear Damage

Hydro Blade Cavitation

Generator Type Typical Motoring Power

Diesel 5% - 25%

Gas Turbine > 50%

Hydro 0.2 - 2%

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ The 78 protection scheme protects the

generator from OOS or pole-slip conditions

ƒ Common relay schemes for detecting

generator OOS events include: ƒ Single blinder

ƒ Double blinder ƒ Concentric circle

ƒ When a Generator Goes Out-of-Step (Synchronism) with the Power System, High Levels of Transient

Shaft Torque are Developed.

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

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

ƒ GSU Subjected to High Transient Currents and Mechanical Stresses.

ƒ One pair of blinders

(vertical lines)

ƒ Supervisory offset

mho

ƒ Mho limits reach of

scheme to swings near the generator

Double Lens Scheme Double Blinder Scheme

ƒ The most popular OOS

protection is the single blinder scheme

ƒ 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

ƒ Positive-sequence impedance must

originate outside either Blinder A or Blinder B

ƒ It should swing through the pickup

area and progress to the opposing blinder

ƒ Swing time should be greater than

Rotor Angle Generator G_1

Angle (degrees)

Time (seconds)

–— Case 1 (tc = 90 ms), with controls

–— Case 2 (tc = 180 ms), with controls

–— Case 3 (tc = 190 ms), with controls

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

– – Case 2 (tc = 180 ms), without controls

ƒ R-X diagrams show trajectory followed by

impedance seen by relay during disturbance

ƒ When an oscillation in the generator is

stable, the point of impedance does not cross the line of the system

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

Case 1 T_c = 0.09 ms Case 2 T_c = 0.18 ms Case 3 T_c = 0.19 ms R (ohm) _{R (ohm)} X ( ohm ) R (ohm) X (ohm) .

ƒ Apply OOS if swing impedance passes

through GSU or generator

ƒ This zone is protected by differential relays

that do not respond to power swings

ƒ Consider application of OOS if swing

passes outside GSU but line protection is blocked or does not respond to swings

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Common causes

ƒ Wiring failure

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

ƒ Affected functions

ƒ 21, 27, 32, 40, 50/27, 51V, 67N, 78, 81

ƒ When fuse blows, unbalanced voltages created ƒ Two sets of VTs required

Loss of One or Two Phases

ƒ Negative-sequence voltage

& no negative-sequence current = fuse loss

ƒ Negative-sequence voltage

& negative-sequence current = fault

Three-Phase Loss

ƒ Low three-phase voltages

& low three-phase current & positive-sequence

current = fuse loss

ƒ Low three-phase voltages

& high three-phase currents = fault

ƒ Wye-wye grounded VTs on ungrounded system ƒ Mitigation

ƒ Line-to-line rated VTs ƒ Broken-delta VTs

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Operating errors ƒ Breaker head flashovers ƒ Control circuit malfunctions ƒ Combination of above

ƒ Typically, normal generator relaying is not

adequate to detect inadvertent energizing

ƒ Generator behaves as induction motor

ƒ Flux induced into generator rotor causing

rapid rotor heating

ƒ Rotor current is forced into

X_1S = system positive-sequence reactance X_1T = transformer positive-sequence reactance X_2G = generator negative-sequence reactance

E_G = generator terminal voltage E_S = system voltage

E_T = transformer high-side voltage I = current R_2G = generator negative-sequence resistance Unit Step-Up Transformer Equivalent High-Voltage System Equivalent System Voltage X1T X1S X2G R2G Gen. EG ET ES Gen. I

ƒ Undervoltage (27) supervises low-set, instant overcurrent (50) –

recommended 27 setting is 50% or lower of normal voltage

ƒ Pickup timer ensures generator is dead for fixed

time to ride through three-phase system faults

ƒ Dropout timer ensures that overcurrent element

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

Generator Phase Voltage Generator Phase Currents Fault Inception Breaker Opens

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

ƒ Large gas turbines are started as a motor using

static frequency converter

ƒ V/Hz is maintained constant until rated voltage is

reached, after which rated voltage is maintained

ƒ Extended operation occurs at low speeds while

purging and firing cycles are completed

ƒ Generator must be protected during low-frequency

ƒ Some protection such as phase overcurrent and

phase unbalance is provided by converter controls

ƒ To be effective, multifunction generator relays

must maintain protection down to low frequencies

ƒ At lower frequencies, protective functions may

deviate from normal specifications

ƒ In some cases, protective functions may have to

be disabled during starting because of possible false operation

ƒ Fault-to-ground on dc link cannot

be detected by converter controls

ƒ Fault causes dc current to flow

through any wye-connected VTs and generator ground

ƒ DC current saturates magnetic elements (VTs and

distribution transformer in generator neutral)

ƒ Damage can occur if fault is not cleared – PT can

be damaged in approximately 50 ms

ƒ Two strategies to address this fault include

ƒ Measure dc current in generator neutral (e.g., with

transducer) and use dc relay and turn converter off before damage occurs

ƒ Eliminate any ground path through magnetic elements

during starting (use delta-connected VTs and disconnect generator neutral while starting)

ƒ To avoid damage to generator or GSU unit, synchronizing

across breaker should be done within tight limits

ƒ Typical recommendations are

ƒ Electrical degrees ±10 ƒ Voltage 0 to +5 percent

ƒ Frequency difference < 0.067 Hz

ƒ 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

ƒ Generators may be operated at lower

frequency during startup and shutdown

ƒ Electromechanical relays can become

very insensitive at off nominal frequencies

ƒ 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

ƒ 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 10 20 30 40 50 60 70 80 Pickup i n Mu ltip les of 60 Hz Pickup Frequency in Hz

Harmonic Restraint Transformer Differential Relay Plunger-Type Current Relay

Induction Overcurrent Relay Generator Differential Relay Generator Ground Relay Plunger-Type Voltage Relay (A) (B) (C) (D) (E) (F)

IEEE TUTORIAL ON THE PROTECTION

OF SYNCHRONOUS GENERATORS

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

ƒ Operated by protective functions, auxiliary

lockout relays, 86G (usually hand-reset), perform most tripping

ƒ Where possible, primary and backup