Generator Protection - xa.yimg.comxa.yimg.com/kq/groups/22645223/17704508/name/Generator-Protn-APPS...• Type of prime mover and generator construction • MW and voltage ratings

Generator Protection

Generator Protection - P 2


The extent and types of protection specified will depend on the following factors :-

• Type of prime mover and generator construction

• MW and voltage ratings

• Mode of operation

• Method of connection to the power system

• Method of earthing



• Types of Prime Mover − Steam Turbines− Gas Turbines− Hydro− Diesel

• Construction− Cylindrial Rotor− Salient Pole (Hydro and small generators)

• Mode of operation− Base load− Peak lopping− Standby

• Ratings− Power from 200kVA to 1000MVA− Voltage from 440V to 24kV


Connection to the Power System

1. Direct :

2. Via Transformer :


Generator Protection Requirements

• To detect faults on the generator

• To protection generator from the effects of abnormal power system operating conditions

• To isolate generator from system faults not cleared remotely

• Action required depends upon the nature of the fault.

• Usual to segregate protection functions into :

− Urgent− Non-urgent− Alarm


Generator Faults

Mixture of mechanical and electrical problems.

Faults include :-

• Insulation Failure− Stator− Rotor

• Excitation system failure• Prime mover / governor failure• Bearing Failure• Excessive vibration• Low steam pressure• etc.


System Conditions

• Short circuits• Overloads• Loss of load• Unbalanced load• Loss of synchronism


Generator Failure


Generator Failure


Generator Failure


Generator Failure


Stator Earth Fault Protection

• Fault caused by failure of stator winding insulation

• Leads to burning of machine corewelding of laminations

• Rebuilding of machine core can be a very expensive process

• Earth fault protection is therefore a principal feature of any generator protection package

TYPE OF METHOD METHODPROTECTION OF OF

EARTHING CONNECTION


Method of Earthing

• Machine stator windings are surrounded by a mass of earthed metal

• Most probable result of stator winding insulation failure is a phase-earth fault

• Desirable to earth neutral point of generator to prevent dangerous transient overvoltages during arcing earth faults

• Several methods of earthing are in use• Damage resulting from a stator earth fault will depend upon

the earthing arrangement


Method of Earthing

Solidly Earthed Machines :

• Fault current is high

• Rapid damage occurs− burning of core iron− welding of laminations

• Used on LV machines only


Generator - Transformer Units

IF ~ 200 300 A

IF ~ 10 15 A

Method of Earthing


Method of Earthing

Desirable to limit earth fault current :

− limits damage− reduces possibility of developing into phase - phase fault

Degree to which fault current is limited must take into account :

− detection of earth faults as near as possible to the neutral point

− ease of discrimination with system earth fault protection (directly connected machines)


Method of Earthing : Limitation of Earth Fault Current

Discrimination not required ∴ can limit current to very low value. Sometimes down to 5A

F

Earth faults on the power system are not seen by the generator earth fault protection.


Method of Earthing : Limitation of Earth Fault Current

Limit To Generator Full Load Current

• Most popular.

• Used for ease of fault detection and discrimination.

• Residual connection of CTs can be used

• Can result in serious core damage.



Directly Connected Generators :

Earthed Generator : Earth fault relay must be time delayed forco-ordination with other earth fault protection on the power system.

Unearthed Generators : Other generators connected in parallelwill generally be unearthed.

Protection is restricted to faults on the generator, grading with power system earth fault protection is not required. A high impedance instantaneous relay can be used (Balanced Earth Fault protection).

51N

51N50N


Percentage Winding Protected

xV

250/1A IS

33ΩR

11.5kV; 75,000KVA

RxV F =Ι

0.8x 2501 x x.200 Ι

x.200 33

x.6600

RxV

Ι Ι operationFor

Y)S(SECONDAR

FS(PRIMARY)

<<

<<

<

<

∴ For protection of 90% of winding; x = 1-0.9 = 0.1Relay setting = 0.8 x 0.1 = 0.08A = 8% of 1A



Generators connected via step-up transformer (resistance earthed) :

Instantaneous protection (50N) :

System earth faults ARE not seen by generator earth fault protection ∴instantaneous relay may be used.

Set to 10% of resistor rating (avoids operation due to transient surges passed through generator transformer interwinding capacitance).

Advantage : Fast

51N 50N



Time delayed protection (51N) :

Time delay prevents operation on transient surges.

A more sensitive current setting may be used.

Set to 5% of resistor rating.

Advantage : Sensitive

On large machines considered worthwhile to use bothinstantaneous and time delayed.


Restricted Earth Fault Protection

64

RSTAB

Protects approx. 90 - 95% of generator winding.


z

TerminalCT

Inputs

E/F CTInput

P342/3 Relay

2000/1 ?

500/1 ?

Connections for Biased REF

• Smaller rating machines may have only one (neutral) tail CT brought out for connection


0 1 2 3 4

1

2

3

Restrain

Operate

Biased REF Protection OperatingCharacteristic

K1

Slop

e K2

• High sensitivity (5%)

• Unit Protection

• FASTEffective bias (x In) = Max. phase current + k . I

N2

Differential current (x In)

= I + I + I + k . IA B C N


Neutral Displacement / ResidualOvervoltage - Earth Fault Protection

P340Relay

3

1

2

(1) Derived measurement from 5-limb or 3 x 1 phase VT

(2) Directly measured from a broken delta VT input

(3) Directly measured across an earthing resistor



• 100% Stator Earth Fault Protection :

• Standard relays only cover 95% of winding.

• Probability of fault occurring in end 5% is low.

• On large machines 100% stator earth fault protection may be required.

• Two methods :

− Low Frequency Injection− Third Harmonic Voltage Measurement


100% Stator Earth Fault Protection (27TN)

(1) Derived measurement from 5-limb or 3 x 1 phase VT(2) 3rd harmonic overvoltage(3) 3rd harmonic undervoltage

• 3rd harmonic undervoltage supervised by 3 phaseundervoltage and W/VA/Var at generator terminals

P340Relay

3

1

2


100% Stator Earth Fault Protection

Distribution of 3rd harmonic voltage along the stator winding• (a) normal operation• (b) stator earth fault at star point• (c) stator earth fault at the terminals

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100% Stator Earth Fault - LowFrequency Injection

For Large Machines Only

InjectionTransformer

51 Alternative InjectionPoints

• Injection Frequency 12.5 - 20Hz

• Provides protection during run up & Standstill

• High cost due to injection equipment.


Overcurrent Protection

• For small generators this may be the only protection applied.• With solid earthing it will provide some protection against

earth faults.• For a single generator, CTs must be connected to neutral end

of stator winding.

51



• For parallel generators, CTs can be located on line side.

51


51

50

FLCGen FL

Small Machines• Time delayed OC protection

• Instantaneous OC, pseudo differential• Simple overload protection

Backup Protection 50/51 Phase Overcurrent


Differential Protection

• Provides high speed protection for all fault types• May be : High impedance type

: Biased (low impedance) type

CT’s required in neutral end of winding

Relay


Differential Protection - Biased

OPERATE

BIASBIAS

Biased Differential Scheme


Differential Protection

Overall Differential Scheme

INTERPOSINGC.T.


• Independent current settings per phase• Single stage definite time delay

IA2

IB2

IC2

Interturn Protection (50DT)


Neutral Displacement / ResidualOvervoltage - Interturn Protection (59N)

GenRelay

3

1

2

• (1) Interturn, derived measurement from 5-limb or 3 x 1 phase VT• (2) Interturn, directly measured from a broken delta VT input• (3) 95% stator earth fault protection across an earthing resistor


Prime Mover Failure

• Isolated Generators :

− Machine slows down and stops. Other protection initiates shut down.

• Parallel Sets :

− System supplies power - generator operates as a motor.− Seriousness depends on type of drive.

• Steam Turbine Sets :

− Steam acts as a coolant.− Loss of steam causes overheating.− Turbulence in trapped steam causes distortion of turbine blades.− Motoring power 0.5% to 6% rated.− Condensing turbines, rate of heating slow. Loss of steam instantly recognised.


Prime Mover Failure

• Diesel Driven Sets :

− Prime mover failure due to mechanical fault.− Serious mechanical damage if allowed to persist.− Motoring power from 35% rated for stiff machine, to 5% rated for run in machine.

• Gas Turbines :

• Motoring power 100% rated for single shaft machine, 10% to 15% rated for double shaft.

• Hydro Sets :

• Mechanical precautions taken if water level drops.• Low head types - erosion and cavitation of runner can occur.• Additional protection may be required.


Prime Mover Failure

• Reverse Power Protection :

− Reverse power measuring relays used where protection required.

− Single phase relay is sufficient as prime mover failure results in balanced conditions.

− Sensitive settings required - metering class CTs required for accuracy.


Reverse Power

• Blinders at 0.5 degrees reduces operation area for low power settings where the power factor is low to improve reliability of reverse power element

Operational limits

Trip area

Q

Unstable areaUnstable area

P

α stable

naturalα = 0.16 o

-P= P0= 0.5o


Low Forward Power

• To reduce the risk of overspeed damage to steam turbine generators a low forward power element is used for interlocking the generator CB and excitation for non urgent trips (eg thermal protection, stator earth fault for high impedance earthing).

• Turbine steam valves are tripped immediatelay and when power output has reduced the generator CB and excitation are tripped.

Operational limits

Trip area

Q

Unstable areaExtended Trip areaP

0

P= P0

Trip area

α stable = 0.5o


Loss of Excitation

Effects

• Single Generator :

− Loses output volts and therefore load.

• Parallel Generators :

− Operate as induction generator (> synch speed)− Flux provided by reactive stator current drawn from system-leading pf− Slip frequency current induced in rotor - abnormal heating

Situation does not require immediate tripping,

however,

large machines have short thermal time constants - should be unloaded in a few seconds.


Loss of Excitation

X

Load Impedance

RImpedanceLocus

Offset – Preventsoperationon pole slips

Diameter

Typically :Offset 50-75%X’dDiameter 50-100% XS Time Delayed

Relay Characteristic

Impedance seen by relay follows locus shown below :


FFail1

Excitation Failure Protection

x LoadX

R

FFail2

FieldFail

Locus

Power FactorAlarm Angle

• Additional fast mho

• Conventional time delay mho

• Alarm on exceeding leading pf


Pole Slipping

• Sudden changes or shocks in an electrical power system may lead to power system oscillations - regular variations of I and V and angularsystem separation

• In a recoverable situation these oscillations will die away - a power swing

• In an unrecoverable situation the oscillations become so severe thatsynchronisation between the generator and the power system is lost -out of step/pole slipping

Causes− Transient system faults− Failure of the generator governor− Failure of the generators excitation control− Reconnection of an islanded system without synchronisation− Switching transients on a weak system


Pole slipping

Power Swing

Recoverable

Unrecoverable

Loss of Synchronism

Out-of-Step

(Power System)

Pole-Slipping

(Generator)


Theory of pole slipping

Where: EG represents the generator terminal voltage;ZG represents the generator reactance;ZT is the reactance of step-up transform;Zs represents the impedance of the power system connected to the generation unitEs represents the system voltage.

Simplified Two Machine System:


Impedance during pole slipping

GSTG

R Zn

jnnZZZZ −+−

−−++=

δδδδ

22 sin)cos()sincos()(

where:

voltagesystem the to voltageterminalgenetator theof ratio magnitude ==S

G

EEn

voltagesystem theleads voltageterminnalgenerator heby which t anglerotor EEarg

S

G ==&

&δ

Impedance measured at generator terminal:


Loss of synchronisation Characteristics

EG/ES<1

EG/ES>1EG/ES=1

R

X S

G

L


Assumption

• EG/ES is assumed to remain constant during the power swing

• Initial transients and effects of generator saliency are neglected

• Transient changes in impedance due to a fault or clearance of fault have subsided

• Effects of voltage regulators and speed governor have been neglected


Conventional Pole Slipping Protection

Reactance Line

R

Lens

Blinder

Z A

Z B

X

θα

Z C

Zone 1

Zone 2


Pole Slipping Protection - 78

• Conventional lenticular (lens) characteristic− 2 Zones defined by reactance line− Zone 1 - pole slip in the generator− Zone 2 - pole slip in the power system− Separate counters per zone (1-20)

• Setting to detect pole slipping when :− Generating− Motoring− Both (Pumped storage generator)


Pole Slipping Protection - 78

• Pole slip when generating− Impedance position on RHS of lens characteristic− Impedance crosses lens on RHS− Impedance spends >T1 (15ms) in RHS of lens− Impedance spends >T2 (15ms) in LHS of lens− Impedance leaves lens on LHS − Zone 1 and 2 counter is incremented if in Z1− Zone 2 counter is incremented if in Z2− Trip when zone counter value exceeded

• Pole slipping when motoring is the opposite


State Transition Diagram

IDLE

DETECTED START

CONFIRM

Zm = R1 .Reset Start_Signals;Reset Flag_Zone1;IF(Any Trip_Signal) Reset Counters; Reset Trip_Signals;

(Zm = R4) & Timer2 > T2)If (C2==0) Start Reset_Timer;C2++;Set Zone2_Start;if(C2>=Count2) Set Zone2_Trip ;If (Flag_Zone1) C1++; Set Zone1_Start; if(C1>=Count1) Set Zone1_Trip;Reset Timer2;

(Zm = R3) & Timer1 > T1) Flag_Zone1=Zone1Pu();

Reset Timer1;Start Timer2;

Zm = R2Start Timer1

Zm = R1 or R2Reset Flag_Zone1;

Reset Timer2;

Zm = R3 but Timer1<T1Reset Timer1

Zm = R1 or R3

Zm = R2

Zm = R3

Zm = R4 or R2 or R3

(Reset_Timer Time Out)Actions are the same as

State Machine EntryState Machine Entry

Reset Trip_ Signals; Reset Start_ Signals;

Reset Flag_Zone1;Reset All Counters;Reset All Timers;

Zm = R1 or R4 Reset Timer1

Zm = R4 but Timer2 < T2Reset Flag_Zone1;

Reset Timer2;

Zm = R4IF(Mode_Both)Flag_Mode=!Flag_Mode;

*No Signal Condition(VA<1V or I <0.02A)

No Signal Condition*Actions are the same as

State Machine Entry

VTS-FAST-BLOCKActions are the same as

State Machine Entry


RTDS Pole Slip Simulation

Local Load

T/line 140 km 11 kV BUS132/13.5 kV

Yd1Grid System Generator with

AVR and Governor control

132 kV BUS


Pole Slipping - 80% Load, Local 3 ph fault


Loss of excitation at 100% machine loading


Rotor ThermalProtection

• Unbalanced loading leads to negative sequence current

• Double frequency slip

• Rapid overheating of rotor


Unbalanced Loading

• Gives rise to negative phase sequence (NPS) currents - results in contra-rotating magnetic field

• Stator flux cuts rotor at twice synchronous speed

• Induces double frequency current in field system and rotor body

• Resulting eddy currents cause severe over heating− Use negative sequence overcurrent relay− Relay should have inverse time characteristic to match

generator I22t withstand


Unbalanced Loading

• Machines are assigned NPS current withstand values :− Continuous NPS rating, I2R (PU CMR)− Short time NPS rating, I2

2t (K)

• If possible level of system unbalance approaches machine continuous withstand, protection is required.


Overload Protection

high load current

heating of stator and rotor

insulation failure

Governor Setting

• Should prevent serious overload automatically.• Generator may lose speed if required load can not be met by other sources.


Stator Thermal Protection

• Current operated− Over power protection− Overcurrent element − Thermal replica

• RTD Thermal Probes− PT100 Platinum probes− Embedded in machine− Alarm and trip thresholds for each RTD


Current

Time

Overload Protection (1)

• Thermal replica for stator overload protection− Current based on I1 and I2− Heating and cooling time constants− Non-volatile memory thermal state− Alarm output


Rotor Earth Fault Protection

Field circuit is an isolated DC system.

• Insulation failure at a single point :− No fault current, therefore no danger− Increase chance of second fault occurring

• Insulation failure at a second point :− Shorts out part of field winding− Heating (burning of conductor)− Flux distortion causing violent vibration of rotor

• Desirable to detect presence of first earth fault and give an alarm.



R

Exciter

Potentiometer Method

• Required sensitivity approximately 5% exciter voltage.

• No auxiliary supply required.

• “Blind spot” - require manually operated push button to vary tapping point.



AC Injection Method

• Brushless Machines

• No access to rotor circuit

• Require special slip rings for measurement

• If slip rings not present, must use telemetering techniques (expensive)

R

AC AuxiliarySupply



Brushless Machine

A brushless generator has an excitation system consisting of:− A main excitor with rotating armature and stationary field windings− A rotating rectifier assembly, carried on the main shaft line out− A controlled rectifier producing the d.c. field voltage for the main

exciter field from the a.c. source (often a small `pilot` exciter)

Hence:− No brushes are required in the field circuit− All control is carried out in the field circuit of the main exciter− Detection of rotor circuit earth fault is still necessary− Based on dedicated rotor-mounted system that has a telemetry link to

provide an alarm/data


Generator Back-Up Protection

10 x FL

with AVR

no AVR

Cycles

FullLoad


Typical use :− Very or extremely inverse for LV machines− Normal inverse for HV machines

Must consider generator voltage decrement characteristic for close-in faults.With reliable AVR system, “conventional” overcurrent relays may be used.Otherwise, voltage controlled / restrained relays are required.


Generator Back-Up Protection


Voltage Restrained

• Operating characteristic is continuously varied depending on measured volts.• Alternatively, use impedance relay.

Voltage Controlled

• Relay switches between fault characteristic and load characteristic depending on measured volts.

F


10

O/L CHARAC

FAULT CHARAC1.0

tsec

GENERATOR DECREMENTCURVE

0.1

0.01100 AMPS10,00030001000600240

LARGESTOUTGOING FEEDER

6.6kV

5MVA115% XS

500/5200/5

Generator Back-Up Protection (2)


I>

Terminal Volts

LoadFaultk.I>

Voltage control

I>

Terminal Volts

LoadFaultk.I>

Voltage restraint

Voltage Dependent Overcurrent Protection (51V)


Impedance Relay

• 2 Zones of protection− Zone 1 - Set to operate at 70% rated load impedance. Back-up

protection for generator-transformer, busbar and outgoing feeders. Time delayed for co-ordination with external feeder phase fault protection.

− Zone 2 – Set to 50% transformer impedance. Back-up protection for generator phase faults. Faster time delay to co-ordinate with generator phase fault protection

R

X

LoadFault

Underimpedance


Under & Over Frequency Conditions

Over Frequency

• Results from generator over speed caused by sudden loss of load.

• In isolated generators may be due to failure of speed governing system.

• Over speed protection may be provided by mechanical means.

• Desirable to have over frequency relay with more sensitive settings.


Under & Over Frequency Conditions

Under Frequency

• Results from loss of synchronous speed due to excessive overload.

• In isolated generators may be due to failure of speed governing system.

• Under frequency condition gives rise to:− Overfluxing of stator core at nominal volts− Plant drives operating at lower speeds - can affect generator

output− Mechanical resonant condition in turbines

• Desirable to supply an under frequency relay.• Protection may be arranged to initiate load shedding as a first

step.


df/dt+t: Time Delayed ROCOF

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• Df/dt can operate quicker than underfrequency for large changes in frequency

• Rolling window is better than fixed window as gives faster operation• Averaging cycles is typically 5 to provide some stability for power system

oscillations• Stages can be used for load shedding or alarm/tripping of the generator

df/dt (81R)Loadshedding


Under & Over Voltage Conditions

Protection

• Under & over voltage protection usually provided as part of excitation system.

• For most applications an additional high set over voltage relay is sufficient.

• Time delayed under and over voltage protection may be provided.


Under & Over Voltage Conditions

Over Voltage

• Results from generator over speed caused by sudden loss of load.

• May be due to failure of the voltage regulator.

• An over voltage condition :

− Causes overfluxing at nominal frequency− Endangers integrity of insulation

Under Voltage

• No danger to generator. May cause stalling of motors.

• Prolonged under voltage indicates abnormal conditions.


Generator Abnormal Frequency Protection (81AB)

• 6 independent bands of abnormal frequency protection

• Accumulation of time up to 1000 hours in each band

• Band data provided by generator manufacturer

• Bands match resonance, blade stress frequencies …

• Dead band timer before accumulation starts allows time for resonance to established

• When generator is off-line bands can be blocked


Generator Abnormal Frequency Protection (81AB)

Band 1f nom

Band 4

Band 3

Band 2

Timer 1Timer 2Timer 3Timer 4


Application Negative Sequence Overvoltage (47)

Generator/MotorCB

Negative Sequence Overvoltage

Swapping of 2 phases to motor (pump water)

47

Generator/Motor47

b ac

Block CB Close

Busbar

Hydro machines can operate as motors/pumps by swapping 2 phases (phase rotation is reversed)

a bc


Generator differentialUnder & over voltageUnder & over frequencyReverse powerStator earth faultLoss of excitationVoltage dependent overcurrentNegative phase sequence

87G27 & 5981U & 81O32R51N4051V46

• When the units are being used to generate power the protection could be as below:

• When the units pump water the protection applied will change

2 31 4

Four groupsavailable

32R Reverse power

Use of Alternative Setting GroupsExample : Pumped Storage Unit


Phase Rotation

• Phase rotation for hydro generator/motor applications where 2 phases are swapped to make the machine operate as a pump (motor)

G x

P340

PhaseReversalSwitches

CT1 CT2

Case 1 : Phase Reversal Switches affecting all CTs and VTs

G x

P343/4/5

PhaseReversalSwitches

CT1 CT2

Case 2 : Phase Reversal Switches affecting CT1 only


Phase Rotation

• Phase rotation settings can be changed for generator/motor operation using 2 setting groups

Setting Range Default SYSTEM CONFIG Phase Sequence Standard ABC /

Reverse ACB Standard ABC

VT Reversal No Swap / A-B Swapped / B-C Swapped / C-A Swapped

No Swap

CT1 Reversal No Swap / A-B Swapped / B-C Swapped / C-A Swapped

No Swap

CT2 Reversal (P343/4/5 only)

No Swap / A-B Swapped / B-C Swapped / C-A Swapped

No Swap


50

27

VTS

&tPU

tDO

& Trip

Unintentional Energisation at Standstill

• Overcurrent element detects breaker flashover or starting current (as motor)

• Three phase undervoltage detection

• VTS function checks no VT anomalies


Check Synch (25)

• Check is used when closing generator CB to ensure synchronism with system voltage.

• Check synch relay usually checks 3 things:− Phase angle difference− Voltage− Frequency difference


Check Synchronising (25)

• Phase angle difference− Single phase comparison

• Can select either A-N, B-N, C-N, A-B, B-C, C-A is settings− Typical setting is ±20º to reduce mechanical stresses on generators.

• Voltage − Check synch relay inoperative if :-

• Generator/busbar voltage is below or above preset limit (independent settings for generator and busbar under/overvoltages)

• voltage difference exceeds preset limit− Typical settings for undervoltage: 80 - 85% Vn− Typical settings for difference voltage: 6 - 10% Vn

• Frequency difference− Usually measured by time to traverse phase angle limits or direct slip frequency

measurement (Fgen – Fbus)• Eg Timer setting of 2 secs over ±20º :• Slip frequency = 2 x (20 x ½) / 360 = 0.055Hz = 0.11% (50Hz)• Timer usually set to 2 secs or 10 x C.B. closing time whichever is greater).


Check Synchronising (25)

• Check synch has 2 stages – Check Sync 1/2− Usually only 1 stage is required for generator applications− Check Sync 2 has CB closing time compensation− Check Sync2 only permits closure for decreasing angles of slip

• Check synch has vector compensation to account for phase shift across transformer with Main VT Vect Grp setting 0-11

• Check synch has ratio correction to correct ratio errors of VTs

• Voltage monitors for dead/live generator/busbar

• System Split output operates for phase angle > setting adjustable from 90 to 175 degrees


Check Synch (25)

Check synch stages 1 and 2


1

Loss ofSynch.

Power Limit

Rated PFStatorCurrent

Limit

Max.Field

Current

2

3

Leading Lagging MVar

MW

1

2

3

32O Overload51P / RTD ThermalFfail Alarm Angle

P340 Protection -Matched to the Generator Capability

Typical Schemes


Protection Package for Diesel Generator

G87

R64

R64

V5132

32 Reverse Power64R Rotor Earth Fault 64S Stator Earth Fault 51V Voltage Dependent Overcurrent87G Generator Differential

Protection P343


Overall Protection of Generator Installation

Generator Feeder Protn.

51 V

64R

32

40

87

46

64S

Overcurrent Voltage Restraint

RestrictedE/F

Buchholz Winding Temp.

Reverse Power

Field Failure

Generator Differential

Rotor E/F Prime Mover Protection

Negative Phase Sequence

Stator E/F

Overall Gen/Trans Diffl Protn.


Overall Protection of Generator Installation

Generator Feeder Protection

Low Steam Pressure, Loss of VacuumLoss of Lubricating OilLoss of Boiler Water

Governor FailureVibration, Rotor Distortion

O/C Circuit Breaker Fail

Busbar Protection

Restricted E/F

Buchholz Winding Temperature

V.T.sO/CTransformer Overfluxing

Restricted E/F

Standby E/F

BuchholzO/C + E/F

Unit Transformer Differential Protn.

Overall Generator Transformer

Differential Protn.

Rotor E/F

Permissive (Low Power)

Interlock Pole SlippingField Failure

Generator Differential

Negative Phase Sequence

Stator E/F Protection

Embedded Generation


PES system

PES system

81U/O

27/59

59N

df/dt

dV

Frequency

Voltage

Residual Voltage

81U/O

27/59

59NIslanded load fed unearthed

AR?

O/C & E/F50/51N

df/dt

dV

ROCOF

Voltage Vector Shift

Co-generation/Embedded Machines

NPS Voltage

NPS O/C

47/46

Check Synch25


Embedded Generation

USED TO PROVIDE:

• Emergency Power Upon Loss Of Main Supply

• Operate In Parallel To Reduce Site Demand

• Excess Generation May Be Exported Or Sold


Engineering Recommendation G59

• ER G59 relates to the connection of generating plant to the distribution systems of licensed distribution network operators (DNOs)

• ER G83/1 covers connection of generating units rated < 16A / phase in parallel with LV distribution system

• ER G59 COVERS:− Safety Aspects− Legal Requirements− Operation− Protection



• The main function of the protection systems and settings is to prevent Generating Plant supporting an islanded section of the Distribution System when it would or could pose a hazard to theDistribution System or customers connected to it.

General Requirements Protective Equipment



• To disconnect the Generating Plant from the Distribution System in the event of loss of one or more phases of the DNOs supply.

• LoM is required to ensure requirements for earthing and out of synch closure are complied with and customers are not supplied with voltage and frequency outside statutory limits

LoM (Loss of Mains = Islanding) Protection Requirements


Loss of Mains Problem

• Loss of mains is where a generator is inadvertently isolated from the grid and continues to supply local load

• Loss of mains can be caused by:

− Protection tripping

− Accidentally due to network reconfiguration


Loss of Mains Problem

• Islanding is unacceptable for a number of reasons:

− Safety risk - for example, through personnel working on the network under the assumption that no parts of the network are energised

− Stresses from out of synchronism re-closure

− Loss of system earth where the earth is on the star winding of a network transformer. This can cause problems for existing earth fault protection to detect earth faults if the system is unearthed.

− Utility is legally bound to maintaining quality of supply (frequency and voltage ) to local demand.


Existing LoM Methods – Performance Assessment

• Loss of mains performance can be assessed in terms of sensitivity and stability

• Sensitivity

− Smallest possible mismatch between local generation and the demand at the instant of islanding.

− Also referred to as non-detection zone

• Stability

− Stability for different fault types with varying duration and retained voltage at the point of measurement

• When designing LoM method objective is to have a small non detection zone and be stable for as many fault characteristics as possible

STABILITY

SENSITIVITYGenerator/demand Imbalance

Network faults


Existing Loss of Mains Methods

• Passive Methods

− Under/over frequency and voltage• Requires large change in load, time delayed

− Df/dt – rate of change of frequency• Sensitive, fast operating

− Voltage vector shift• Not as sensitive as df/dt, fast operating

− Direct inter-tripping

• Not load dependent, fast, expensive, signalling can be complex

• Active Methods

− Active frequency drift

− Reactive Error export

• There is an abundance of active methods proposed in the technical literature, however, their application in practice has been limited to date. The traditional protection philosophy of independence from other systems makes the introduction of these methods difficult.


An expression for a sinusoidal mains voltage waveform is generally given by the following:

V = Vp sin (wt) or V = Vp sin θ (t)

where θ(t) = wt = 2πftIf the frequency is changing at constant rate Rf from a frequency fo then the variation in the angle θ(t) is given by:

θ(t) = 2π∫f dt, (F = Fo + Rf t)

which gives θ(t) = 2π{fo t + t Rf t/2}

and V = V sin {2π(fo + t Rf/2)t}

Hence the angle change Δθ(t) after time t is given by:

Δθ(t) = πRf t2

Voltage Vector Shift Protection

Loss of Mains Methods


Single phase line diagram showing generator parameters

E

R

T

jX

VIL

Loss of Mains Methods – Voltage Vector Shift


Vector Diagram Representing Steady State Condition

E

I XL

II RL

VT

L




Transient voltage vector change θ due to change in load current ΔIL

L

L

E

I

I XI RV

L

L

ΔI X”

θ

VT

L

T

IΔ


Loss of Mains Methods - ROCOF

The rate of change of speed, or frequency, following a power disturbance can be approximated by:

df/dt =

where P = Change in power output between synchronised and islanded operation

f = Rated frequency

G = Machine rate MVA

H = Inertia constant

df/dt

ΔP.f

2GH



df/dt =

Two consecutive calculations must give a result above the setting threshold before a trip decision can be initiated

P341 df/dt calculation

F - f

3 cycle

n n - 3 cycle


df/dt+t: Time Delayed ROCOF

t

f

df/dt Setting

Start

TripPick up cycles

Time delay



G59 Other Protection

• Neutral voltage

• Overcurrent

• Earth fault

• Phase unbalance

• Reverse power − Used when generator does not export power during normal operation


G59 Protection Settings

Protection Settings for Long-Term Parallel Operation

Notes: K1 = 1.0 (low impedance networks or 1.66-2 (high impedance networks)K2 = 1.0 (low impedance networks or 1.6 (high impedance networks)A fault level of < 10% system design max fault level is high impedance* Might need to be reduced if auto-reclose time <3s

Intertripping expectedK2 x 0.125Hz/sK1 x 0.125 Hz/sLoM (RoCoF)

Intertripping expectedK1 x 6 degreesK1 x 6 degreesLoM (Vector Shift)

0.5s52Hz0.5s52HzO/F st 2

90s51.5Hz90s51.5Hz90s51.5HzO/F st 1

0.5s47Hz0.5s47Hz0.5s47HzU/F st 2

20s47.5Hz20s47.5Hz20s47.5HzU/F st 1

0.5sVph-ph +13%0.5sVph-n +15%O/V st 2

1.0sVph-ph +10%1.0sVph-ph +10%1.0sVph-n +10%O/V st 1

0.5sVph-ph -20%0.5sVph-n -20%U/V st 2

2.5s*Vph-ph -20%2.5sVph-ph -13%2.5s*Vph-n -13%U/V st 1

TimeSetting TimeSettingTimeSetting

HV ConnectedLV Connected

Medium Power StationSmall Power StationProt Function


G59 Protection for HV Generator connected to DNO HV System for Parallel Operation Only


G59 Protection for HV Generator connected to DNO HV System for Standby and Parallel Operation

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Documents

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