Generator Protection - · PDF file3/4/2009 · Generator Protection – Setting Calculations Generator Protection Sample Relay Setting Calculations The sample calculations shown here

Generator ProtectionGenerator ProtectionRelay Setting Calculations

Generator Protection – Setting Calculations

Generator ProtectionSample Relay Setting Calculations

The sample calculations shown here illustrate steps involved in calculating the relay settings for generator protection.

Other methodologies and techniques may be applied to calculate relay settings based on specific applications.


XT = 10%

One Line Diagram

Example Generator


10.015.040.0COLD AIR TEMPERATURE (° C)

13.813.813.8RATED VOLTAGE (kV)

6.4856.2765.230STATOR CURRENT (kA)

0.85 / 600.85 / 600.85 / 60POWER FACTOR / FREQUENCY (HZ)

131.7127.5106.2ACTIVE POWER (MW)

155.0150.0125.0APPARENT POWER (MVA)

CURVE B @ 10.0° C

CURVE A @ 15.0° C

RATED @ 40.0° C

DESCRIPTIONS

BINSULATION CLASSANSI / IECSTANDARDSTATIONARYTYPE OF EXCITATION-5.0 / +5.0VOLTAGE RANGE (%)

V84.2 GENERATOR TYPE TLRI 93/33-36 COSΘ=0.85

222.4 KWHEAT LOSSES DISSAPATED AT RATED LOADAIRCOOLING MEDIUM

INDIRECTTYPE OF COOLINGSTATOR WINDING

237.0 KWHEAT LOSSES DISSAPATED AT RATED LOADAIRCOOLING MEDIUM

RADIALTYPE OF COOLINGSTATOR CORE

71.1° ΚROTOR WINDING – AVERAGE TEMPERATURE RISE62.8° KSTATOR WINDING – SLOT TEMPERATURE RISE287.7 KWHEAT LOSSESS DISSAPATED AT RATED LOADAIRCOOLING MEDIUM

DIRECT RADIALTYPE OF COOLINGROTOR WINDING


96.94%96.85%96.32%- 25% LOAD98.15%98.11%97.88%- 50% LOAD98.43%98.42%98.32%- 75% LOAD

98.46%98.47 %98.46 %STATIONARY- 100% LOAD

CURVE B155.00.8510.0

CURVE A150.00.8515.0

RATED AT 125.00.8540.0

RELATIVE TO:OUTPUT (MVA)POWER FACTORCOLD GAS TEMPERATURE (°C)

EFFICIENCIES

113.6- CURVE B (10° C) (MVAR)

109.6- CURVE A (15° C) (MVAR)91.3- OVER – EXCITED (MVAR)

58.5OUTPUT AT COS Θ=0- UNDER – EXCITED (MVAR)

67%OUTPUT LIMIT WITH 1 COOLER SECTION OUT OF SERVICEΔT=0.8% / °KOUTPUT AT DEVIATING COLD AIR TEMPERATURE

30 SHORT TIME ( K= I22 t)10%CONTINUOUS LOAD UNBALANCE – PERMISSIBLE I2

OUTPUT AND ALLOWABLE LOAD UNBALANCE



- -- -395 18825% LOAD- -- -519 24750% LOAD- -- -662 31475% LOAD

1003 476970 459822 391100% LOAD- -- -1011 480125% LOAD- -- -298 142NO LOAD

CURVE [email protected]° C

CURRENT FIELD VOLTAGE

(A) (V)

CURVE A @15.0° C


(A) (V)

RATED @ 40.0° C


(A) (V)

GENERATOR LOAD

GENERATOR – EXCITER CURRENTS AND VOLTAGES

EXCITER CURRENTS AND VOLTAGES

--15.1%XSLGSTATOR LEAKAGE

--26.8%XPPOTIER

--10.9%X0ZERO PHASE SEQUENCE16.4%X2 SAT20.3%X2 UNSATNEG PHASE SEQUENCE

--196.4%XQ UNSATQ-AXIS SYNCHRONOUS

46.1%XQ′ SAT51.3%XQ′ UNSATQ-AXIS TRANSIENT

17.2%XQ″ SAT21.2%XQ ″ UNSATQ-AXIS SUB-TRANSIENT

--206.8%XD UNSATD-AXIS SYNCHRONOUS

24.5%XD′ SAT27.2%XD′ UNSATD-AXIS TRANSIENT

15.6%XD″ SAT19.3%XD ″ UNSATD-AXIS SUB-TRANSIENTREACTANCES BASE MVA = 125 MVA

0.57NO LOAD SHORT CIRCUIT RATIO SAT.



--0.030 STADC TIME CONSTRAINT

2.500 STQO΄ NO-LOAD0.534 STQ΄ SHORT CIRCUIT

Q-AXIS TRANSIENT

0.150 STQO΄΄ NO-LOAD0.068 SXQ΄΄ SHORT CIRCUIT

Q-AXIS SUB-TRANSIENT

7.150 STDO΄ NO-LOAD0.873 STD΄ SHORT CIRCUIT

D-AXIS TRANSIENT

0.045 STDO΄΄ NO-LOAD0.031 SXD΄΄ SHORT CIRCUIT

D-AXIS SUB-TRANSIENT

TIME CONSTANTS

0.267%R0NULL SEQUENCE

3.201%R2INVERSE SEQUENCE

0.367%R1POSITIVE SEQUENCE

0.3501 ΩRF20OF ROTOR WINDINGS @20° C

0.001674 ΩRA20OF STATOR WINDINGS @20° C

RESISTANCES




Voltages and currents that are present at the input terminals when the generator is operating at rated voltage and current.

Nominal Voltages and Currents


Voltage Inputs and their connections

3V0

.

.


A B C

A

B

C

13.8kVLLVT Ratio = 14,440 / 120 = 120

13,800 / 120 = 115 V

VT Type: Line-to-LineVNOM = 115 V

Voltage InputsOpen Delta-Open Delta VT, secondary wired L-L Example


VT Type: Line-to-LineVNOM = 115 V

Example:Generator rating VL-L = 13,800VVT Ratio = 14,400/120V = 120/1

Voltage Inputs, 3Y-3Y VT, secondary wired L-L Example

M-3425A

13,800V

13,800/120 = 115

= 120


Example:Generator rating VL-L = 13,800VVT Ratio = 14,400/120V = 120

�

�

�

�� √�

��

��

��

��

√ ��

14,440120

VT Type: Line-to-GroundVNOM = 115/√3 = 66.4 V

3Y-3Y VT, secondary wired L-G ExampleVoltage Inputs


The “Line-Ground to Line-Line” selection should be used when it is desired to provide the phase voltage-based elements (27, 59, 24 functions) with phase-to-phase voltages

They will not operate for neutral shifts that can occur during stator ground faults on high impedance grounded generators

The oscillograph in the relays will record line-ground voltage to provide stator ground fault phase identification

Voltage Inputs

3Y-3Y VT, secondary wired L-G (L-G to L-L selection)Use of L-L Quantities for Phase Voltage-based elements


A ground fault will cause LG connected phase elements through a 3Y-3Y VT to have undervoltage or overvoltage (depending on faulted phase)

System

HighImpedanceGround

SLG

ABC

a

bc

a

bc

ground

Van=Vag

Vbn=VbgVbn=Vbg

n=gvag=0

n

Van= -Vng

Vcn Vbn

VbgVcg

Neutral Shift on Ground Fault:High Impedance Grounded Generator

Fault


Generator rating VL-L = 13,800VVT Ratio = 14,400/120V

�

�

�

�� √�

��

��

��

��

√ ��

14,440120

VT Type: LG to LLVNOM = 115 V

Software convertsLG (66.5V) voltages to LL (115V) quantities

Voltage Inputs3Y-3Y VT, secondary wired L-G (L-G to L-L selection on the relay). This selection is recommended for the example generator.

(66.4V)


Determine primary current at rated powerIpri nom = MVA*106 / √3*VLLIpri nom = 125*106/(1.732*13800)Ipri nom = 5,230 A

Convert to secondary valueCt ratio is denoted as RC

RC = 8000/5 = 1600

Isec nom = I pri nom/RC

Isec nom = 5230/1600

Isec nom = 3.27 AINOM = 3.27A

Current Inputs


Delta-Y transform setting (used with 21, 51V)

This setting Determines calculation used for 21 and 51V functions (calculates the GSU high side voltages and currents)

• Disable: Used for YY and Delta/Delta connected transformers

• Delta-AB: Used for Delta-AB/Y connected transformers

• Delta-AC: Used for Delta-AC/Y connected transformers


59/27 Magnitude Select:

This setting adjusts the calculation used for the overvoltage and undervoltage functions. RMS selections keeps the magnitude calculation accurate over a wide frequency range. RMS setting ispreferred for generator protection applications where the frequency can vary from nominal value especially during startup and shutdown.

Phase Rotation (32, 46, 81):

This setting adjusts nominal rotation. We do not recommend reversing the CT and PT connections to change the rotation. Using the software switch will result in proper phase targeting.

50DT Split phase Differential:

Used for split phase hydro machine applications. This setting changes IA, IB, and IC metering labels and does not affect the operation of any protective element.


Pulse Relay:

When selected, the output contacts close for the seal in time setting then de-energize, regardless of function status.

Latched Outputs:

This function simulates lock out relay (LOR) operation. When selected, the output contacts remain closed until the function(s) have dropped out and the target reset button is pressed.

Relay Seal In Time:

Normal output mode: Sets the minimum amount of time a relay output contact will be closed.

Pulse output mode: Sets the output relay pulse length.

Latched: No affect



Therefore, for a terminal L-G fault, there will be 140.9 V applied to the generator relay neutral voltage input connection.

59N – Neutral Overvoltage (Gen)

VLL Rating = 13,800 V

PRIS

IS

IS = 3.5 x 13,800 = 201.3A240

V59N = 0.7 x 201.3 = 140.9V


59N setpoint # 1 = 5.4 V, 2 ~ 10 sec.

This is a standard setting which will provide protection for about 96% of the stator winding- The neutral-end 4% of the stator winding will be protected by the

27TN or 59D elements

59N setpoint #1 time delay should be set longer than the clearing time for a 69 KV fault- GSU transformer-winding capacitance will cause a voltage

displacement at the neutral. 10 seconds should be long enough to avoid this situation, or the voltage generated at the neutralresistor can be calculated and a high enough setting with small delay may be applied.



59N Setpoint #2 = 35 V, 5 sec. (300 cycles)

Note: Setpoints should be coordinated with low voltage secondary VT fuses

59N #3 can be used for alarm and trigger an oscillograph (set to 5 V at 1 sec)



27TN is set by measurement of third harmonic voltage during commissioning

Observe 3rd harmonic voltage under various loading conditions

Set the 27TN pickup to 50% of the observed minimum

Set power and other supervisions as determined from the data collected above

Power / VAr

3rd

Har

mon

ic V

olta

ge

0.25

0.50

0.75

1.00

1.25

1.50

10%20%

30%40% 60% 80%

50% 70% 90%100%

Desired Minimum Setting

27TN – Third Harmonic Undervoltage


27TN – Third Harmonic Undervoltage

0.3


The 27TN function overlaps with the 59N function to provide 100% stator ground fault protection. See the graph below.

Overlap of Third Harmonic (27TN) with 59N Relay

27TN Third Harmonic Neutral Undervoltage


59N is connected to a broken-delta VT input on the line side of the generator breaker for ungrounded system bus protection

The system is ungrounded when backfed from the GSU and the generator disconnect switch is open

59N – Neutral Overvoltage (Bus)

3EO = 3 x 66.5 = 200 V

14,400

120 V VT


The maximum voltage for a solidly-grounded fault is 3 x 66.5 = 200 V.

Because of the inaccuracies between the VTs, there can be some normal unbalanced voltages.

59N Setpoint #1 Pick-up = 12 V, 12 sec (720 cycles)

59N Setpoint # 2 Pick-up = 35 V, 5.5 sec (330 cycles)

59N – Neutral Overvoltage (Bus)


Nameplate

10% continuous capability of stator rating (125 MVA), the same as that stipulated in ANSI/IEEE C37.102.

The K factor is 30.

Set Inverse Time Element for Trip

Pick-up for tripping the unit (Inverse Time) = 9%K=29

Definite Maximum time = 65,500 cycles.

Set Definite Time Element for Alarm

Pickup =5%Time delay = 30 sec (1800 cycles). Note that 30 sec should be longer than a 69 KV system fault clearing time.

46 – Negative Sequence


Relay operating time is 7 seconds for 69 kV faults. This should provide adequate coordination with 69 kV system.

Check the response of the 46 function for high-side (69 kV) phase-to-phase faults.



46IT Pickup=9%

46IT, K=29

Definite maximum time (65,500 cycles)

Pickup 5%

Time Delay = 30 s

46DT Alarm

Negative Sequence Overcurrent (46)



29


CT’s are of C800 Standard quality

87G – Generator Differential


Generator CT Short Circuit Calculation:

X”d

ARI

I

AKVI

puIVI

saturatedX

c

pri

pri

pu

d

92.201600

472,33

472,33)4.6(5230)8.13(

4.66.15

100%6.15)("

sec ===

==

≈==

=

Check for the maximum three-phase fault on the terminals of the generator to determine the secondary current for the worst-case internal fault.



69KV Fault Current Calculation:

ARI

I

AKVI

puXX

VI

MVAXsaturatedX

c

pri

pri

tdpu

sys

d

75.121600

397,20

397,209.35230)8.13(

9.3106.15

100"

)125%(10%6.15)("

sec ===

=•=

≈+

=+

=

==

Check for the maximum three-phase fault on the terminals of the generator to determine the secondary current for the worst-case external fault.


X”d


CTs should perform well since the maximum current is only 21 A (CT secondary) for worst-case short circuit.

VS

Rctr RW RR

Rctr = CT ResistanceRw = Wiring ResistanceRR = Relay Burden = 0.5 VA @ 5A

= 0.02Ω

VS

45°

VK

IS

VK > VS

87G – Generator DifferentialCT Requirement Check


IEEE Std C37.110-1996IEEE GUIDE FOR THE APPLICATION OF CURRENT TRANSFORMERS



Pick-up = 0.3 A (480 A primary sensitivity)

Slope = 10%

Time Delay = 1 cycle (no intentional time delay)(if ct saturation is possible time delay should be increased to 5 cycles)


Setting Summary




Overfluxing Capability, Diagram

24 – Volts/Hertz (Overfluxing)

0 200 400 600 800 1000 1200 1400 1600 1800 2000

1.40

p.u.

1.35

1.30

1.25

1.20

1.15

1.10

1.05

1.00

•

•

•

time


Protection can be provided with an inverse time element (24IT) in combination with a definite time element (24DT#1)Another definite time element (24DT#2) can be used for alarm with a typical pickup of 106% and a time delay of 3 sec

0.1

1

10

100

1000

10000

100 105 110 115 120 125 130 135 140 145

V/Hz in percent of nominal

Tim

e in

sec

Generator V/Hz Capability

V/Hz Protection Curve (Inverse)

V/Hz Protection Curve (Definite time)

Alarm Settings:Definite Element #2Pickup = 106%Time Delay = 3 sec

Inverse Time ElementPickup = 110%Curve #2K= 4.9

Definite time element #1 Pickup = 135% Time Delay = 4 sec

8858.4/)5.2115(60 VHzKet −+=





The 50/27 inadvertent energizing element senses the value of the current for an inadvertent energizing event using the equivalent circuit below.

X2 = 16.4 %Values shown above are from generator test sheet

All reactances on generator base (125 MVA)

Where X2 is the negative sequence reactance of the generator

The current can be calculated as follows:

I = ES/(X2 + XT1 + X1SYS)

= 100/(16.4 + 10 + 6.25)

= 3.06 pu

= 3.06 x 5230 = 16,004 A

X2

50/27 – Inadvertent Energizing

X1SYS = 6.25%


The relay secondary current :

= 16004/RC = 16004/1600 = 10 A

Set the overcurrent pickup at 50% of this value = 5 A

For situations when lines out of the plant are removed from service, X1SYS can be larger. Considering this case set 50 element pickup at 125% of full load or 4.0 A. Many users set the 50 Relay below full load current for more sensitivity, which is ok.

50/27 – Inadvertent EnergizingThe current can be calculated as follows:

I = ES/(X2 + XT1 + X1SYS)

= 100/(16.4 + 10 + 6.25) = 3.06 pu

= 3.06 x 5230 = 16,004 A


The undervoltage element pickup should be set to 40 to 50% of the nominal value:

The undervoltage pickup = 0.4 x 115 V = 46.1 V

The pickup time delay for the 27 element should be set longer than system fault clearing time.

Typical value is 5 sec (300 cycles)

The dropout time delay is set to 7 sec (420 cycles).




46


System Configuration with Multiple In-Feeds

Provide backup for system phase faultsDifficult to set: must coordinate with system backup protectionCoordinate general setting criteria- backup relaying time- breaker failure- Consideration should be given to system emergency conditions.

Voltage Control/Restraint Overcurrent (51V)


Voltage control/restraint needed because of generator fault current decay

Voltage Control Types:Voltage Control (VC): set 51V pickup at a percent of full load (40-50%)Voltage Restraint (VR): set 51V pickup at about 150% of full load



• This function provides backup protection for phase faults out in the power system.

• Set this relay for Voltage Restraint mode.

• It will have the following characteristic.

Input Voltage (% of rated voltage)

Where % pickup is the adjusted pickup current based on the voltage as a percent of pickup setting.

% Pickup

51V Voltage Restraint Overcurrent

Pickup = 1.5 x Generator Full Load Rating

IFL = 3.27A

∴ Pickup current = 3.27 x 1.5 = 4.9 A


X”dXT

Calculate the fault current for a 3 phase 69 KV fault:


12.75A1600

20,397RI

I

20,397A5230(3.9)(13.8KV)I

3.9pu1015.6

100XX"

EI

(125MVA) 10%X15.6%)(saturatedX"

c

prisec

pri

td

genpu

sys

d

===

==

≈+

=+

=

==

Egen


Multiples of pickup (MPU) for a 3 phase fault on 69KV bus:

Voltage Control/Restraint Overcurrent (51V)Determine generator phase voltage for 3 phase 69KV fault:

%39%100106.15

10%100"

=+

=+

=td

tgen XX

XV

67.6)39.0(9.4

75.12(%)

===genpickup

fault

VII

MPU


Definite Time Overcurrent Curve

Select the Curve and Time Dial to get 1.0 sec clearing time for 69KV fault:

Definite Time curveTime Dial = 4.5

MPU = 6.67


51V Setting Summary:

• Pickup = 4.9 A

• Definite Time Curve

• Time Dial = 4.5

• Voltage Restraint



Now calculate the lowest fault current for a 3-phase fault:

Assumptions:

Generator was not loaded prior to faultAutomatic Voltage Regulator was off-lineTransient and Subtransient times have elapsed and the machine reactance has changed to its steady state value (Xd).

The fault current is given by the same equivalent circuit exceptreplace the subtransient reactance of the generator with synchronous reactance (Xd) of 206.8%.


AIII

puXX

EI

alnoMinFault

td

genMinFault

5.1)27.3(46.0

46.0108.206

100

minsec ===

=+

=+

=


It can be seen that for a bolted 3-phase fault (at the transformer terminals), the current is less than 50% of the full load current. This is the reason why we need to apply Voltage restraint/Voltage control setting for overcurrent function.

The voltage at the generator terminals during this condition is given by:

Vgen = (Egen x XT)/(Xd + XT)

= 100 x 10/(206.8+10) = 0.04612 pu = 0.04612 x 115 = 5.3 V

Since the voltage is below 25% of the rated voltage, the overcurrent pickup will be 25% of the setting:



• Over Current pickup = 4.9 x 25% = 1.225 A.

• Since the fault current is 1.5 A, the multiple of pickup is 1.5/1.225 = 1.23 multiple.

• With time dial setting of 4.5 and definite time curve, the relay operating time is around 5.3 seconds.

• Since the actual fault current during transient and subtransient periods are much higher than 1.5 A the operating time will be between 1 and 5.3 seconds.



=>Enable Voltage Restraint=>Do not select blocking on VT fuse loss (only for Beckwith Relays, other relays may require blocking). VT fuse-loss blocking is not required for Voltage restraint and it is only required for Voltage Control. For voltage restraint the relay will internally keep the 51V pickup at 100% during VT fuse-loss condition.



Provides protection for failure of system primary relaying

Provides protection for breaker failure

Must balance sensitivity vs. security

- loadability

- load swings

System Phase Fault Backup (21)


For a fault at F the approximate apparent impedance effect is:


The fault appears farther than the actual location due to infeed.



Vc-Vo

Ic

VCA-VBC

(3)Ic

VA-VO

Ia

VAB-VCA

(3)Ia

VC-VA

Ic-Ia

VCA

Ic-IaCA Fault

Vb-Vo

Ib

VBC-VAB

(3)Ib

VC-VO

Ic

VCA-VBC

(3)Ic

VB-VC

Ib-Ic

VBC

Ib-IcBC Fault

Va-Vo

Ia

VAB-VCA

(3)Ia

VB-VO

Ib

VBC-VAB

(3)Ib

VA-VB

Ia-Ib

VAB

Ia-IbAB Fault

L-GL-L or L-G to L-L



VT ConnectionVT ConnectionVT Connection

Transformer Delta-AB Connected

Transformer Delta-AC Connected

Transformer Direct Connected


0.85 power factor corresponds to 31.8º



21

GEN

125 MVA base10%

To line 83

69 KV4,000 foot cable

To 5559line 86

3976

3977

39783972

line 96

line 873975

3974

3973

line 94

line 97

To PP4

To sub 47

To sub PP4

To PP4

The 21 function should be set to provide system backup protection.

• All breakers have breaker failure protection. • All lines out of the substation have high-speed pilot

wire protection. • The 4,000 foot cable of 69 KV is protected by a HC8-1

pilot wire scheme. We need to provide backup if this high-speed scheme fails. Set 21-2 unit to look into the substation.

21 Phase Distance


Typical 69 kV cable impedance: (0.2 + j0.37)% per mile

= (0.2 + j0.37) x 4000 = (0.152 + j0.28)% @100 MVA5280

Change base to 125 MVA:

= (0.152 + j0.28)x (125/100) = (0.19 + j0.35)%

The transformer impedance is 0.1 pu on generator base

The secondary (relay) impedance = 0.1 x 20.3 = 2.03 ohms.

21 Phase Distance


(0.19 + j0.35)%69 KV

4,000 foot cable

125 MVA base10% or 0.10 p.u.

21

GEN

Zone-1 will be set to look into the low side of the step-up transformer, but not into the 69kV system.

21 Zone-1 Settings:


Set zone 21-1 into generator step-up transformer but short of 69 kV bus. A margin of .8 is used to compensate for LTC (if used).

(0.1 for margin, and 0.1 for the LTC variation)

2.03 x .8 = 1.60Ω

Setting Summary for 21-1Diameter =1.6 ΩTime delay = 0.5 sec. (30 cycles)Angle of maximum torque: 85°

60FL supervised

21 Zone-1 Settings:


Zone-2 will be set to look up to the substation bus.

Calculate zone 21-2 setting as follows:(0.19 + j0.35) + j10.0 = 0.19 + j10.35 ≈ 10.35%

Set zone 21-2 with 1.3 margin:∴10.35% x 1.3 ≈ 13.45%

From our earlier calculations 1.0 pu secondary (relay) impedance= 20.3 Ω

Then the Zone-2 reach setting is: = 0.1345 x 20.3 = 2.73 Ω.

21 Zone-2 Settings:


Setting Summary for 21-2

• Diameter = 2.73 Ω

• Time delay = 1.0 sec (60 cycles). This should cover backup clearing for fault on transmission (69 KV) system. Most lines have a dual primary.

• Angle of maximum torque: 85°

• 60FL supervised

21 Zone-2 Settings:


In our example Zone-2 reach at RPFA should not exceed 50% to 66.66% of 1.0 pu impedance (200% to 150% load).

50% impedance = 10.15 Ohms at 0.85 pf (31.8o)With Zone-2 set at 2.7 Ohms and MTA of 85o the reach at RPFA of 31.8o

= 2.73 x (Cos (MTA-RPFA) = 1.64 Ohms.Normal load will not encroach into the Zone-2 characteristic.

jX

R0

1.6 Ω2.7 Ω

85oZ2 reach at

RPFA 1.64 (31.8o)

Z2

Z1

Phase Distance (21)RPFA: Rated Power Factor Angle

Generator loadability considerations:

Z2 at RPFA should not exceed 150 to 200 % of generator rating


(21) – Phase Distance


When the relay (or another device) send a trip signal to open the breaker and current continues to flow OR the breaker contact continues to indicate closed, the upstream breaker is tripped.

Breaker Failure-50BF


Steady state bolted fault current for a 3-phase fault at the transformer terminals is 1.5 A (relay secondary).

Set the 50BF phase function current pickup at 1 A, which is below the fault current.

Set the breaker failure time longer than the maximum clearing time of the breaker plus the margin.

Initiate 50BF with all relays that can trip the generator breaker.

Set the 50BF Timer: 4(margin) + 1(accuracy) + 5(breaker time) = 10 cycles.

Use programmable inputs to initiate the breaker failure for all other relays that trip the generator breaker.

50BF – Generator Breaker Failure


Setting Summary

50BF Pickup = 1 A

Time Delay = 10 cycles

Initiate the breaker failure with programmable inputs from external trip commands.

Initiate the breaker failure with the outputs (from internal trip commands) connected to trip.



BFI

Output Initiate – Output contacts within M-3425A that trip generator breaker.

Input Initiate – Input into breaker failure logic tripping of generator breaker of other trip device – i.e., turbine trip, other relays.

Breaker Failure Trip OutputBFI

1.00



TYPICAL GENERATOR CAPABILITY CURVELoss of Field Protection (40)


TRANSFORMATION FROM MW-MVAR TO R-X PLOT

MW – MVAR R-X PLOT

MVA = kV2

Z( Rc )

Rv


LOSS OF FIELD PROTECTION SETTING CHARACTERISTICS

Scheme 1 Scheme 2

+R-R

- Xd’ 2

Xd

Heavy Load Light Load

Impedance LocusDuring Loss of Field1.0 pu Zone 1

Zone 2

+X

-X

+R-R - Xd’ 2

1.1Xd

Heavy Load Light Load

Impedance LocusDuring Loss of Field

Zone 1

Zone 2

XTG +Xmin SG1DirectionalElement


Generator Ratings (Primary):

Rated (base) MVA = 125 Rated (base) Phase-PhaseVoltage (VB): 13.8 kVRated (base) Current (IB) = MVA x 103/(√3 VB) = 5,230 A

Secondary (Relay) quantities:

CT Ratio (RC) = 8000/5 = 1600; VT Ratio (RV) = 14400/120 = 120

Nominal VT Secondary (VNOM): = VB/ RV

= 13.8 x 103/120 = 115 V

Nominal CT Secondary (INOM): = IB/ RC = 5230/1600 = 3.27 A

Nominal (1.0 pu) impedance = VNOM/INOM

= 115/ (√3 x 3.27) = 20.3 Ω

40 – Loss of Field


Generator Parameters (125 MVA base) Xd = 2.068 pu '

dX = 0.245 pu

Zone-1 Settings

Diameter: 1.0 pu = 1.0 x 20.3 = 20.3 ohms Offset = - '

dX /2 = (0.245/2)x20.3 = -2.5 ohms

Time Delay = 5 cycles Zone-2 Settings

Diameter: dX = 2.068 x 20.3 = 42.0 ohms Offset = - '

dX /2 = (0.245/2)x20.3 = -2.5 ohms

Time Delay = 30 cycles

40 – Loss of Field (Scheme 1)


40 – Loss of Field

Zone 1

Zone 2

1.0 p.u. = 20.3 Ω

X’d = 2.5 Ω2

R

-X

Xd = 42.0 Ω

0


-80

-60

-40

-20

0

20

0 20 40 60 80 100 120 140

P (MW)

Q(M

var)_

)

MELGCCSSSL

Real Power into the System

Rea

ctiv

e Po

wer

into

the

Gen

erat

or

Underexcited

Overexcited

MEL GCC

SSSL

If it is possible, it is desirable to fit the relay characteristic between the steady state stability limit and generator capability curve. In this example the Zone-2 diameter can be reduced to meet this criteria.

Generator Characteristics


-50

-40

-30

-20

-10

0

10

-30 -20 -10 0 10 20 30

R

jX MELGCCSSSL

Zone 1Zone 2

Loss of Filed Settings on the R-X Plane

(Scheme –1)


-140

-120

-100

-80

-60

-40

-20

0

20

0 20 40 60 80 100 120 140

P (MW)

Q (M

var)_

MELGCCSSSL

Zone 2

Zone 1

Rea

ctive

Pow

er in

to th

e G

ener

ator

Real Power into the System Overexcited

UnderexcitedMEL GCC

SSSL

Loss Field Settings on P-Q Plane(Scheme – 1)




Zone-1 SettingsDiameter = 1.1 Xd – X’d/2 = 1.1 x 42 – 5/2 = 43.7 ohms

Off-set = -X’d/2 = -5/2 = -2.5 ohmsTime Delay = 15 cycles

Zone-2 SettingsDiameter = 1.1 Xd + XT + Xsys

= 1.1 x 42+2.03+1.27 = 49.5 OhmsOff-set = XT+Xsys = 2.03 + 1.27 = 3.3 ohmsAngle of Directional Element: -13o

Time Delay = 3,600 cycles (60 cycles if (accelerated tripping with undervoltage supervision is not applied)

Undervoltage Supervision:Undervoltage Pickup = 80% of nominal voltage

= 0.8 x 115 = 92 VTime Delay with undervoltage = 60 cycles.



X0 10

-10

Dir Element

-50

-40

-30

-20

-10

0

10

-30 -20 -10 0 10 20 30

R

jX

MELGCCSSSL

Zone 1Zone 2

Directional Element

Loss of Filed Settings on the R-X Plane

(Scheme – 2)


-80

-60

-40

-20

0

20

0 20 40 60 80 100 120 140

P (MW)

Q(M

var)_

)

MELGCCSSSL

Zone1

Zone 2

Real Power into the System

Rea

ctiv

e Po

wer

into

the

Gen

erat

or

Underexcited

Overexcited

MEL GCC

SSSL

(Scheme – 2)

Loss Field Settings on P-Q Plane




Prevents generator from motoring on loss of prime mover

Typical motoring power in percent of unit rating

Prime Mover % Motoring PowerGas Turbine:

Single Shaft 100Double Shaft 10 to 15

Four cycle diesel 15Two cycle diesel 25Hydraulic Turbine 2 to 100Steam Turbine (conventional) 1 to 4Steam Turbine (cond. cooled) 0.5 to 1.0

Reverse Power (32)


• Generator is not affected by motoring (runs like a synchronous motor)

• Turbine can get damaged

• Since the example generator is driven by a gas turbine (10 to 15%) the reverse power relay pickup is set at 8%

• Time delay is set at 30 sec.

Reverse Power (32)


In some applications it is desirable to set a low forward power setting instead of reverse power.

This can be achieved by selecting Under Power selection along with a positive pickup setting.

Reverse Power (32)


Generator and transformer test sheet data, and system information:X′d =24.5%XT = 10% on generator baseXSYS = 6.25% on generator base

Use graphical method to determine settings.

78 – Out-of-Step


The per unit secondary (relay) impedance = 20.3 ΩConvert all impedances to secondary (relay):Direct axis transient reactance (X′d) =

(24.5/100)x 20.3 = 5.0 ΩTransformer impedance (XT) =

(10/100)x 20.3 = 2.03 ΩSystem impedance (XSYS) =

(6.25/100)x 20.3 = 1.27 Ω.

78 – Out-of-Step


jX

GEN(Xd)

R

swing locusT N S

XT

XSYS

'

01.5 XT

1.5 XT = 3 ohms

2 Xd = 10 ohms'

120o

d2.4 ohms

Out-of-Step (78)


Circle diameter = (2 X’d+ 1.5 XT) = 10 Ω + 3 = 13 ΩOffset = -2 X’d = -10 ΩImpedance angle = 90°Blinder distance (d) = ((X’d+ XT+XSYS)/2) tan (90-(120/2))

d = 2.4 ΩTime delay = 2 to 6 cycles (3 cycles)Trip on mho exit = EnablePole slip counter = 1.0Pole slip reset = 120 cycles

Settings of 78 Function From Graph:


78 – Out-of-Step


Fuse Loss Detection (60FL)(block 51V, 21, 40, 78, 32)


Ensure fuse loss and breaker position (52b) are set to block.

Under voltage condition generally does not cause generator damage.

The limitation will be with the dropping of the plant auxiliaries

Undervoltage function is typically set to Alarm rather than Trip.

Phase Undervoltage (27)

104

92120

600

Definite time element #1Pickup = 90% (104 V)

Time delay = 10 sec (600 cycles)

Definite time element #2Pickup = 80% (92 V)

Time delay = 5 cycles


Generators are designed to operate continuously at 105% of the rated voltage

Overvoltage condition can cause over fluxing and also can cause excessive electrical stress.

Set the overvoltage function as follows:

Definite time element #1Pickup = 110% (127 V)Time delay = 10 sec (600 cycles)

Definite time element #2Pickup = 150% (173 V)Time delay = 5 cycles

Phase Overvoltage (59)

127

600

173


81 Frequency Protection

• The generator 81U relay should be set below the pick-up of underfrequency load shedding relay set-point and above the off frequency operating limits of the turbine generator.

• If there are any regional coordinating council requirements theymust be met also.

• The multiple setpoint underfrequency protection is common on Steam turbine generators and for gas turbines a single setpoint underfrequency protection may be employed.

• In this example the Florida Coordinating Council requirements are used as a guideline for under frequency/over frequency settings. Due to the lack of information from the generator/turbine manufacturer and load shedding relay settings.



Florida Regional Coordinating Council guidelines:



Generator limits: IEC 60034-3: 2005This IEC standard specifies that the generator is required to deliver rated power at the power factor over the ranges of +/- 5% in voltage and +/-2% in frequency.

Operation beyond these limits must be restricted both in time and extent of abnormal frequency.

Generator/Turbine Mechanical Limits:

Depending upon the type of machine, additional mechanical limitsmay be in place that should be considered when setting this element.


81 Frequency ProtectionSetting Summary:

81-1 : Pickup: 60.6 HzTime Delay: 10 sec

(may be set to alarm)

81-2: Pickup: 59.4 Hz

Time Delay: 60 sec

81-3: Pickup: 58.4 Hz

Time Delay: 10 sec

81-4: Pickup: 57.4 Hz

Time Delay: 1 sec


Safety Considerations

The signal applied by the M-3425 64F is less than 20Vp-p.Generator and Field must be de-energized for this test.All test equipment must be removed prior to energization.

Field Ground Protection (64F)Field Tests of the 64F


DecadeBox

Field Ground Protection (64F)Initial Conditions:Field breaker closedRelay energizedGenerator and excitation systemmust be ground free (resistance field-ground >100Kohms)Test Setup:Connect a decade box (0-100K range) between the field winding and ground

Injection Frequency Adjustment:• Set the decade box to 50K ohms• Monitor the measured field

insulation resistance and adjust the injection frequency setting until a 50K ohm reading is obtained.

• Reset the decade box to 5K and check the measured resistance. Reset the decade box to 90K and check the measured resistance.

• Fine tune the injection frequency for best overall performance

• Disconnect the decade box

Injection Frequency adjustment


Field Insulation Real-Time Monitoring

Field Ground Protection - MeteringReal-Time Insulation Measurements


Setting the 64F:General Guidelines

- Setting should not exceed 60% of ungrounded resistance reading to prevent nuisance tripping

Typical settings - #1 Alarm 20 K ohms, 600 cyc

delay- #2 Trip 5 K ohms, 300 cyc

delay

Field Ground Protection (64F)

- Time delay setting must be greater than 2/finjection


Brushes

Field Ground Protection (64F)Factors affecting 64F performance

- Excitation systems have capacitors installed between the +/- field and ground for shaft voltage and surge suppression. To minimize this effect, injection frequency may be adjusted downwards at the expense of response time.


Initial Conditions:> Field breaker closed> Relay energized> Generator and excitation

systemmust be ground free (resistancefield-ground >100Kohms)

Brush lift-off simulation:> Using the M-3425 secondary

metering screen or the statusdisplay, record the brush lift detection voltage.

> Remove the machine groundconnection and record the brush voltage (denoted as faulted condition).

> Restore the ground connection

Brush Lift Detection (64B)


Brush Voltage

Field Ground Fault ProtectionReal-Time Measurement


Setting the 64B:General Guidelines:- 64B pickup = unfaulted voltage + 0.5 (faulted brush voltage-

unfaulted brush voltage)- 64B delay = 600 cycles

Factors affecting 64B performance:- The brush voltage rise (faulted brush voltage-unfaulted

brush voltage) varies directly with the capacitance between the rotor and ground. Therefore machines with lower capacitance will exhibit a smaller change in brush voltage when faulted. These machines may require experimentation to yield a pickup setting that provides the necessary security and sensitivity.

Brush Lift Detection (64B)


64F/B - Field Ground Protection

600

0.5

300

©2008 Beckwith Electric Co., Inc.

Documents

Generator Protection - · PDF file3/4/2009 · Generator Protection – Setting Calculations Generator Protection Sample Relay Setting Calculations The sample calculations shown here