Generator Protection

GENERATOR PROTECTION By

Subhash Thakur PE-Elect [email protected]

Generator Protection       

Gen Stator Thermal Protection Field Thermal Protection Gen stator fault Protection Gen rotor field Protection Gen abnormal operating conditions System backup Protection Power transformer Protection

Generator Protection Stator Thermal protection Thermal protection for the generator stator core and windings  Generator overload  

Winding Temperature Over current

 Failure of cooling systems  

RTDs Thermocouple Flow and pressure sensor

 Localized hot spots caused by core lamination insulation failures or by localized or rapidly developing winding failures 

Generator Core monitor

Generator Protection

Turbine-generator short time thermal capability for balanced three-phase loading

Generator Protection Generator Field Thermal protection Thermal Protection  Direct rotor Body temperature measurement not possible  Core Monitor may detect overheating

Protection for field over excitation  IDMT/ Definite Time  Excitation limiters

Generator Protection

Generator field short time thermal capability

Generator Protection Requirement  Generator faults are considered to be serious since they may cause severe and costly damage to insulation, windings, and the core may also produce severe mechanical torsional shock to shafts and couplings.  Fault current may continue to flow for many seconds even after the generator is tripped, because of trapped flux within the machine, thereby increasing the amount of fault damage.  As a consequence, for faults in or near the generator that produce high magnitudes of short-circuit currents, some form of high-speed protection is normally used to trip and shut down the machine as quickly as possible in order to minimize damage.

Stator fault Protection  High Speed Differential protection

– Will detect Phase to Phase Faults, Double phase faults involving earth – Single phase to Earth will not be detected due to limited earth fault current available.

 Two types of high-speed differential relays are commonly used for stator phase fault detection: – High-impedance differential – Biased differential

High Impedance Differential Relay Use two sets of identical dedicated CTs. PS class CT with stringent parameters to be used This scheme has higher sensitivity than the percentage differential relay.  Through fault stability achieved by using   

stabilising resistors in the relay circuit.

High Impedance Differential Relay Stabilizing resistor calculation : Vs = If (Rct+2Rl) If - Maximum through fault current in the system (converted to sec side) Rct- Secondary resistance of the CT Rl – lead resistance of the sec connection (typ 8.73 ohms per km for 2.5 sq mm cu cable) Rs = Vs/Is – (VA/Is*Is) Typical setting 5- 10% of rated current.

Biased Type Diff Relay  Less stringent CT parameters. CTs can be shared with other protections.  Through fault stability achieved through biasing.  CT mismatch (typ of the order of 1:5 ) can be accommodated.  More suitable for numerical integrated protection systems as the CTs can be shared for many functions.

 Modern numerical relays have flexible settings for  Id, b (point of slope change) and the slopes.

Biased Differential protection

Typical bias setting: 10% of rated current.

INTERTURN PROTECTION  Current based system – For generators with split neutrals with all six terminals brought out on neutral side. – Delayed low-set o/c relay which senses the current in the connection between the neutrals of the stator windings Voltage based system – Relay compares the neutral NGT sec voltage and Genertaor terminal open delta voltage. – Balance during external E/F or normal condition – During inter turn fault open delta voltage will be developed and NGT sec voltage will be zero, resulting in a differential voltage which makes the relay operate. Typical setting Definite time type relays: minimum setting with 1 sec delay.

Inter turn protection

Split Phase Protection

Voltage Based V o l

Generator Grounding Practices It is common practice to ground all types of generators through some form of external impedance  limit the mechanical stresses and fault damage in the machine,  to limit transient voltages during faults, and  to provide a means for detecting ground faults within the machine.

Typical Grounding practices  Ungrounded  Solid Grounding  High-impedance grounding  Low-resistance grounding  Reactance grounding  Grounding-transformer grounding

Generator Grounding Practices  Ungrounded – Phase to ground fault current limited – Generators are not often operated ungrounded as it may produce high transient over-voltages during faults and makes the fault location difficult to determine.  Solid Grounding – Solid grounding of a generator neutral is not generally used since this practice may result in high mechanical stresses and excessive fault damage in the machine.

Generator Grounding Practices  High Impedance Grounding – High resistance grounding

The high-resistance grounding method utilizes a resistor connected across the secondary of the distribution transformer to limit the maximum ground fault current. For a single-phase-to-ground fault at the machine terminals, the primary fault current will be limited to a value in the range of about 3 A to 25 A.

– Ground fault neutralizer grounding

 The ground fault neutralizer grounding method utilizes a secondary tunable reactor to limit the maximum ground fault current.

 Low –resistance grounding

 In this method, a resistor is connected directly between the generator neutral and ground.  For a single-phase-to-ground fault at its terminals the primary fault current will be limited to a value in the range of about 200 A up to 150% of rated full-load current.  Resistor cost and size usually preclude the use of resistors.

Stator Earth Fault Protection

 E/F current is typically limited to 5-10A to minimizes the damage to laminations.  First earth fault is less critical but needs clearance as  It may develop into a ph to ph fault .  Second fault will result in very high current.

 Two types of coverage:  100 % winding  95 % winding

95 % Stator Earth Fault  Any fault involving earth results shift of Neutral voltage.  This shift can be detected by measuring the Voltage across Grounding Resistor Or from the generator terminal Open Delta voltage.  Typical coverage 95% Of Stator Winding.  Typical Setting:

– 5% with 1 Sec TD

100 % Stator E/F Protection • Third Harmonic Principle • Relay responds to the reduction of the 3rd Harmonic Component • For a Stator Phase-to-ground fault at or near the Generator Neutral, there will be an increase in third Harmonic Voltage at The Generator Terminals, which Will Cause Relay Operation.

100% SEF based on third harmonics measurements

100% SEF based on third harmonics measurements Disadvantages Due to design variations, certain generating units may not produce sufficient third harmonic voltages. This method does not protect the machine during stand still conditions.

100% stator earth fault protection (Low freq. injection principle) Detects the ground faults by injecting a low frequency signal (say 20 hz) at the neutral earthing transformer and monitor the earth current in the winding. 

max. 200 V

20 Hz RE I

SEF USING INJECTION PRINCIPLE TYPICAL CONNECTION Earthing transformer

Low ohmic

Bandpass (8 Ω at 20 Hz)

20-Hz-Generator (appr. 25 V)

a DC or AC

RL b

Blocking 400A 5A

Relay U a Neutral transformer

I

b

Typical settings for 500 MW unit Trip : 1 KOhm / 1 sec Alarm : 10 Kohm /10 sec

Rotor Earth Fault Protection Effects  First rotor E/F does not cause immediate damage  Second E/F results in short circuit of rotor winding.  Causes magnetic unbalance/mechanical forces Measure 

Low frequency injection method

Modern rotor earth fault protection relay operates on the principle of low frequency injection into the field winding via capacitors. – Corresponding current or resistance during E/F is sensed –



Typical setting for a 500 mw Generator Alarm 25 k ohm time = 10 sec Trip 5 k ohm time = 1 sec

Rotor E/F Using Low frequency injection method

Rotor E/F Using Low frequency injection method

Negative sequence protection  Causes of negative squence current – one pole open in line – Unbalanced loads – Unbalanced system faults  Induces double frequency rotor current in the rotor surface thereby leading to high and dangerous temperatures in a short span of time.

 Negative sequence protection relays shall be set to the NPS withstand capability of the machine which is given by k = i22x t  Typical for 500 mw Permissible neg seq current = 5 – 8 % of stator current permissive i22x t = 5 – 10 settings adopted for ntpc i2 = = 7.5 % i 2xt = 8

Negative sequence protection

Loss of field protection

Loss of field protection  Acts as an induction generator  Induced eddy currents in the field winding, rotor body, wedges and retaining rings  MW flow in to the system/ MVAR flows in to the machine.  The apparent imp moves in to the forth quadrant of x-y plane  Method of detection: Impedance measurement with Under Voltage  Some relays are set in the admittance plane matching with the capability curve of the machine.

Trip characteristics of loss of field protection

Trip characteristics of loss of field protection

Trip characteristics of loss of field protection

Generator Capability Curve

RELAY LINE

Out of step protection     

Machine runs out of synchronism with the network Cyclic variation of rotor angle Current increases. Results in the winding stress It may also damage the auxiliaries of the affected unit

Method of detection – Variations in impedance measured at Gen Terminal – Distinguish between the recoverable swing and the irrecoverable swing – blinders and a supervisory mho element, – Trips the machine when imp is inside the mho and cross the blinders with the specified time. – Minimum impedance (multiple zone) + counting no of swings

Out of step protection settings

Typical Over Fluxing Withstand Capability

Accidental back energisation  Cause – –

Flash over of the generator breaker Incorrect closing of the generator breaker

 Effects – Cause operation as an induction motor – Damage machine and turbine – The rapid heating iron paths near the rotor surface due to stator induced current.  Over current + CB auxiliary contacts – checks for the current when the gen breaker contacts are open – set below the rated current(90%) – o/c and u/v measurements

 Setting - o/c 1.2 times & u/v 70%

Accidental Back Energisation

Reverse /Low forward power Protection

Low forward and reverse power inter lock  To allow entrapped steam in the turbine to be utilized to avoid damage of the turbine blade.  To protect the machine from motoring action  Trip under class B after a short time delay in case the turbine is already tripped ( typ set at 2 sec)  Trip under class A, after a long time delay if turbine is not tripped (typically set at 10 -30 sec)  Power setting typ 0.5 % of rated power

O/V & U/F protection Typical settings of a 3 stage o/v relay is as follows – Alarm 110 % 2 sec – Trip 120 % 1 sec – 140 % instantaneous Abnormal Frequency protection Typical setting: U/F Alarm - 48.5hz 5 sec Trip - 47.4 hz 2 sec

51 hz

O/F 1 sec

Backup impedance protection  For uncleared system fault  The backup protection is time delayed to coordinate with the zone 3 setting of lines  Detected by – over current – impedance – Impedance type preferred as the line is provided with distance relays  Setting should be made to cover the GT imp and the longest line impedance.  Setting should take care of the infeed from other generators connected to the same bus also.  Time setting 1.5 –2 sec

Over view of type of fault Vs protection

FAULT/ ABNML

EFFECT

PROTECTION

Thermal over Over heating of stator wdg / loading insulation failure

Thermo couples/ Over current relays

External fault Unbalanced loading stress

Over load/negative phase sequence relay, Backup Impedance/ Earth Fault

Stator faults Winding burn out Differential protection Shorting of of core lamination 100% E/F prot/95% E/F Inter turn protection Rotor fault

Damage to shaft/bearing

Two stage rotor E/F protection

Motoring

Damage to turbine blades

LFPR/Rev power Inter lock

O/V,O/F,U.F Insulation failure,Heating of core failure of blades

O/V relay Volt/Hz relay U/F relay

Loss of field

Loss of field

Induction gen operation Absorb MVAR from system/damage to rotor wdg

COMMONLY USED GEN/GEN TRFR RELAYS

PROTECTION ALSTOM/AREVA

ABB

HIGH IMP DIFF

RADHA REG 216

CAG 34 MICOM P343

SIEMENS

7UM SERIES

REMARK

In case of duplicated diff, one low imp & one high imp preferred For trfr biased relay preferred

BIASED DIFF MBCH MICOM P 633

RADSB RET 316

7 UT

POWER RELAYS

RXPE

PPX

7 UM SERIES

LOSS OF FIELD

YCGF

RAGPC(DIR 7UM SERIES O/C+U/V)

Impedance /

100% E/F

PVMM MICOM P343 PG871

GIX

7UE22

REG 216

7UM SERIES

Low frequency injection type preferred over 3 rd harmonic principle

7UM SERIES

Open delta of gen sec VT

7UM 516

Minimum impedance

95% E/F

VDG

BACK UP IMP

YCG15 MICOM SERIES

RAKZB REG

Directional power relays

admittance

PROTECTIO ALSTOM N

ABB

SIEMENS

Remarks

OVER FLUXING

GTTM

RATUB RALK

7RW

IDMT

POLE SLIPPING

ZTO+YTGM1 RXZF+RXPE 5

7UM 516

IMPEDANCE IMP+ DIR O/C IMP+NO OF POWER SWINGS

ACC. BACK CTIG ENERG

RAGUA

7UM SERIES

O/C +CB AUX CONTACT CURRENT ELEMENT+U/V

INTER TURN

VDG MICOM

REG

7UM SERIES

comp of open delta 0n gen term+ngt sec voltage

NEG PH SEQ

CTN

RARIB

7UM SERIES

MEASUREMENT OF I2

REF

CAG/FAG

RADHD

7UM SERIES

HIGH IMP PREFFERED

REG SERIES

7UR 22 7 UM SERIES

ROTOR E/F VDG MICOM SERIES

Type of fault

Protection

Channel

Short circuit

87 G1 87G2 87 GT

1 2 1 OR 2

Stator Earth Fault

64G1 64G2

1 2

Inter turn

95G

1 OR 2

unbalance

46G

1 OR 2

Over load

51G

Alarm

Loss of excitation

40G1 40G2

1 2

Out of step

98G

1 OR 2

Motoring

32 G1/2 / 37 G1/G2

1/2

O/V,O/F U/F

59/99 81G1/81G1

1 /2 1/2

System back up

21G

1&2

Accidental energisation

50GDM

1 &2

Rotor E/F

64F

1 OR 2

Recommendatio n

>100 MW

Generator Transformer Protection  Differential – biased differential

20 % bias setting (to cover tap range and ct mismatch if any) time: instantaneous Back up earth fault Definite time or IDMT relay 30 % with 2 sec time delay To be coordinated with distance prot zone 3

UT PROTECTION Differential Biased differential used biased setting 20% Back up over current 2-3 times the full load current Delay of 1 sec to take care of any large motor starting case Restricted E/F High impedance Set to 5%-10% in high impedance earthing Backup E/F Set to 30% rated current with delay of 1 sec

Other Protections  Overall Differential Protection (87GT) - Covers generator, GT & UT  GT overhang differential Protection (87HV) - Protects GT HV wdg & overhang portion between GT bushing and switchyard.

Typical Gen Prot SLD

Typical Generator protection scheme

NON GCB SCHEME

GCB SCHEME

TRIP LOGIC OF GENERATOR PROTECTION  Two independent channels with independent CT/VT inputs/ DC supply/ Trip relays  Class “A” Trip (Urgent Trips) – All electrical trip – Issues instantaneous Trip to Turbine , Excitation, Generator EHV CBs,UT LV CBs – In GCB Scheme Class A1 and A2 – Class A1 Issues instantaneous Trip to Turbine , Excitation, Generator EHV CBs,GCB, UT LV CBs – Class A2 Issues instantaneous Trip to Turbine , Excitation, GCB  Class-B Trip (Non-urgent Trips) – Turbine Trips, GT and UT OTI/WTI trips – Issues delayed Trip to (After Low Forward Power timer)  In Non-GCB scheme-Excitation, Generator CBs,UT LV CBs  In GCB scheme, only GCB and field are tripped, UT remains charged through GT.  Class C Trip Trips HV CB only.

CLASS OF TRIP

Class A

Class B

Class C

BREAKERS TO BE TRIPPED UNDER VARIOUS CLASSES OF TRIPPING GCB SCHEME NON GCB SCHEME (additional LV CB between Gen and GT) A1: GCB,HVCB,UT LV CB, HVCB,UT LV CB, FIELD, FIELD, TURBINE TURBINE (All the system tripped) (All the system tripped) A2 : GCB, FIELD, TURBINE (Generator circuit tripped & Auxiliaries charged from the grid through GT&UT) GCB,FIELD BREAKER Initiated by Turbine trip & Low Forward /reverse power, to release the trapped steam. Generator circuit breaker tripped & Auxiliaries charged from the grid through GT&UT) HVCB (Generator under House load )

HVCB,UT LV BREAKER.

HVCB (Generator load )

CB,

under

FIELD

House

RELAY GROUPING SL NO

PROTECTION FUNCTION

1.

2.

Generator Differential Protection, (87 G) (DUPLICATED IN CASE OF GCB SCHEME) Overall Di fferential Protection (87GT).

CLASS OF TRIP NON GCB GCB A A2

A

A1

Generator Transformer Differential protection (87 T) Over hang differential protection(87 HV)

A

A1

A

A1

Stator Earth Fault Protection covering 100% of winding based on low frequency injection principle.(64G1). Stator Standby Earth Fault Protection covering 95% of winding (64 G2) Inter -turn Fault Protection (95G1),

A

A2

A

A2

A

A2

8.

Duplicated Loss of field protection (40G1/2 ).

A

9.

Back up Impedance Protection, 3 pole (21G) Backup Earth Fault Protection on Generator Transformer HV neutral (51NGT) Negative Sequence Current Protection, (46G)

A

A1

A

A1

A

A2

3. 4. 5.

6. 7.

10.

11.

A2

Preferred grouping of protection 87 G and 87 GT shall be on two different channels of protection.

87 T shall be in a different channel than 87 GT 87 HV shall be in a different channel than 87T 64 G1 and 64 G2 shall be on two different channels of protection.

40G1 and 40G2 shall be on two different channels of protection. 21 G and 51 NGT be in different channels

1.

Duplicated Low-Forward Power / reverse power Interlock for steam turbine generator (37 /32G1 & 37/32 G2), each having two stages, a) short time interlocked with trip b) long time independent of trip.

2. 3. 4.

5.

6.

37/32 G1 and 37/32 G2 shall be in two different channels of protection

delayed turbine

B

B

delayed turbine

A

A2

Two Stage Rotor Earth Fault Protection based on injection principle.(64F). Definite Time Delayed Over-Voltage Protection (59G) Generator Under Frequency Protection (81G) with df/dt elements. i) Over Fluxing Protection (99 T) for Generator Transformer ii) Over fluxing protection for Generator (99 G)( only incase of GCB scheme) Accidental Back Energisation protection (50GDM) on two principles

A

A2

A

A2

C

C

A

A1

-----

A2

A

A1

A

A2

A

A2

a) based on U/V and O/C

7.

8.

b) based on CB status and O/C Instantaneous and time delayed Over Current protection to be used on HV side of excitation transformer. Generator Pole protection(98G)

slipping

Over Flux function (99) shall be in a different channel than O/V and U/F functions

50 GDM based on the two principle shall be on two different channels.

1.

Unit Transformer Differential Protection, 3 pole (87UT)

A

2.

Unit Transformer LV back-up earth fault protection . ( 51NUT).

A

A1

3.

Unit Transformer LV REF (64 UT LV)

A

A1

4.

Unit transformer back-up over current protection (51UT). Gen Transformer OTI/WTI trip

A

A1

Turbine Trip

Turbine Trip

5.

A1

6.

Gen Transformer Buchholtz, PRD /other mechanical Protections

A

A1

7.

Unit Transformer OTI/WTI trip

UT LV CB Trip & signal for change over of unit board. A

UT LV CB Trip & signal for change over of unit board.

8.

Unit Transformer Buchholtz, PRD /other mechanical Protections 9. 64 GT (For GT LV wdg & UT HV wdg) 10. EHV CB/GCB LBB 11. EHV BB PROTN

A1 A1

A A

A1 A1

87 UT & 51 NUT can be in one channel and 64 UT LV & 51UT shall be in another channel.

After turbine trip other breakers are tripped through class B

ADDITIONAL control/protection interlocks realized through GRP

SL.NO INITIATION 1

ACTION

GT PROTECTION

FIRE TRIP CLASS A AND DISCONNECT POWER SUPPLY TO GT MB

2

UT PROTECTION

FIRE TRIP CLASS A AND DISCONNECT POWER SUPPLY TO UT MB

3

GT TAP CHANGER TRIP CLASS A OPERATED & HVCB CLOSED

4

HV CB /FCB CLOSED

5

GT COOLER SUPPLY TRIP CLASS A AFTER TIME DELAY TOTAL FAILURE

6

AVR TROUBLE

START GT COOLER

SERIOUS TRIP CLASS A

Numerical integrated generator protection systems Many functions in the same relay Takes multiple CT/VT inputs. Minimum of 2 nos to be used. All the prot functions are to be divided in to 2 groups . Built in DR(fast scan)/SOE functions Self supervision Communicable Has programmable logic gates which simplifies the auxiliary circuits. COMMON RELAYS ARE REG series OF ABB 7UM SERIES OF SIEMENS MICOM SERIES OF AREVA.        

GENERATOR DISTURBANCE RECORDER  Record the graphic form of instantaneous values of power system variables  Fast scan (1-5 khz) and slow scan (5/10 hz) features  Sufficient analogue/digital inputs.  Triggering from digital inputs and threshold/rate of change of analogue values.  Adequate memory  Good frequency response  Individual acquisition units and commom evaluation unit for a station

Thank You For Your Time