Generator Protection relay setting calculation

Generator Protection Relay Setting Calculations

Generator Protection – Setting Calculations

Generator Protection Sample 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.


Example Generator

One Line Diagram XT = 10%

Generator Protection – Setting Calculations V84.2 GENERATOR TYPE TLRI 93/33-36 COSΘ=0.85 DESCRIPTIONS

RATED @ 40.0° C

CURVE A @ 15.0° C

CURVE B @ 10.0° C

(MVA)

125.0

150.0

155.0

(MW)

106.2

127.5

131.7

POWER FACTOR / FREQUENCY (HZ)

0.85 / 60

0.85 / 60

0.85 / 60

STATOR CURRENT

(kA)

5.230

6.276

6.485

RATED VOLTAGE

(kV)

13.8

13.8

13.8

COLD AIR TEMPERATURE

(° C)

40.0

15.0

10.0

APPARENT POWER ACTIVE POWER

VOLTAGE RANGE (%)

-5.0 / +5.0

TYPE OF EXCITATION

STATIONARY

STANDARD

ANSI / IEC

INSULATION CLASS

B

STATOR WINDING TYPE OF COOLING

INDIRECT

COOLING MEDIUM

AIR

HEAT LOSSES DISSAPATED AT RATED LOAD

222.4 KW

STATOR CORE TYPE OF COOLING

RADIAL

COOLING MEDIUM

AIR

HEAT LOSSES DISSAPATED AT RATED LOAD

237.0 KW

ROTOR WINDING TYPE OF COOLING

DIRECT RADIAL

COOLING MEDIUM

AIR

HEAT LOSSESS DISSAPATED AT RATED LOAD

287.7 KW

STATOR WINDING – SLOT TEMPERATURE RISE

62.8° K

ROTOR WINDING – AVERAGE TEMPERATURE RISE

71.1° Κ

Generator Protection – Setting Calculations V84.2 GENERATOR TYPE TLRI 93/33-36 COSΘ=0.85 EFFICIENCIES RELATIVE TO: OUTPUT POWER FACTOR COLD GAS TEMPERATURE

RATED AT 125.0 0.85 40.0

CURVE A 150.0 0.85 15.0

CURVE B 155.0 0.85 10.0

98.46 %

98.47 %

98.46%

- 75% LOAD

98.32%

98.42%

98.43%

- 50% LOAD

97.88%

98.11%

98.15%

- 25% LOAD

96.32%

96.85%

96.94%

(MVA) (°C)

STATIONARY - 100% LOAD

OUTPUT AND ALLOWABLE LOAD UNBALANCE CONTINUOUS LOAD UNBALANCE – PERMISSIBLE I2

10%

SHORT TIME ( K= I22 t)

30 ΔT=0.8% / °K

OUTPUT AT DEVIATING COLD AIR TEMPERATURE OUTPUT LIMIT WITH 1 COOLER SECTION OUT OF SERVICE

67%

OUTPUT AT COS Θ=0 - UNDER – EXCITED

58.5 (MVAR)

- OVER – EXCITED

(MVAR)

91.3

- CURVE A

(15° C)

(MVAR)

109.6

- CURVE B

(10° C)

(MVAR)

113.6

Generator Protection – Setting Calculations V84.2 GENERATOR TYPE TLRI 93/33-36 COSΘ=0.85 GENERATOR – EXCITER CURRENTS AND VOLTAGES GENERATOR LOAD

NO LOAD 125% LOAD 100% LOAD 75% LOAD 50% LOAD 25% LOAD

EXCITER CURRENTS AND VOLTAGES RATED @ 40.0° C CURRENT FIELD VOLTAGE (A) (V) 298 142 1011 480 822 391 662 314 519 247 395 188

REACTANCES

CURVE A @15.0° C CURRENT FIELD VOLTAGE (A) (V) 970 459 -

CURVE B @10.0° C CURRENT FIELD VOLTAGE (A) (V) 1003 476 -

BASE MVA = 125 MVA

D-AXIS SUB-TRANSIENT

XD ″ UNSAT

19.3%

XD″

SAT

15.6%

D-AXIS TRANSIENT

XD′

UNSAT

27.2%

XD′

SAT

24.5%

D-AXIS SYNCHRONOUS

XD

UNSAT

206.8%

Q-AXIS SUB-TRANSIENT

XQ ″ UNSAT

21.2%

XQ″

SAT

17.2%

Q-AXIS TRANSIENT

XQ′

UNSAT

51.3%

XQ′

SAT

46.1%

Q-AXIS SYNCHRONOUS

XQ

UNSAT

196.4%

NEG PHASE SEQUENCE

X2

UNSAT

20.3%

ZERO PHASE SEQUENCE

X0

10.9%

-

-

POTIER

XP

26.8%

-

-

STATOR LEAKAGE

XSLG

15.1%

-

-

NO LOAD SHORT CIRCUIT RATIO SAT.

-

-

X2

-

SAT

0.57

16.4%

Generator Protection – Setting Calculations V84.2 GENERATOR TYPE TLRI 93/33-36 COSΘ=0.85 TIME CONSTANTS D-AXIS SUB-TRANSIENT D-AXIS TRANSIENT Q-AXIS SUB-TRANSIENT Q-AXIS TRANSIENT DC TIME CONSTRAINT

XD΄΄ SHORT CIRCUIT

0.031 S

TDO΄΄ NO-LOAD

0.045

S

SHORT CIRCUIT

0.873 S

TDO΄ NO-LOAD

7.150

S

XQ΄΄ SHORT CIRCUIT

0.068 S

TQO΄΄ NO-LOAD

0.150

S

0.534 S

TQO΄ NO-LOAD

2.500

S

0.030 S

-

TD΄

TQ΄

SHORT CIRCUIT

TA

RESISTANCES OF STATOR WINDINGS

@20° C

RA20

0.001674 Ω

OF ROTOR WINDINGS

@20° C

RF20

0.3501 Ω

POSITIVE SEQUENCE

R1

0.367%

INVERSE SEQUENCE

R2

3.201%

NULL SEQUENCE

R0

0.267%

-



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


Voltage Inputs and their connections

.

.

3V0


Voltage Inputs Open Delta-Open Delta VT, secondary wired L-L Example A

B

C

13.8kVLL

VT Ratio = 14,440 / 120 = 120

A

B

C

13,800 / 120 = 115 V

VT Type: Line-to-Line VNOM = 115 V


Voltage Inputs,

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

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

= 120

13,800/120 = 115

M-3425A

VT Type: Line-to-Line VNOM = 115 V


Voltage Inputs 3Y-3Y VT, secondary wired L-G Example Example: Generator rating VL-L = 13,800V VT Ratio = 14,400/120V = 120 A

B

VT Type: Line-to-Ground VNOM = 115/√3 = 66.4 V 13,800 V

C

14,440 VT Ratio = 14,410 120V120

13,800 √3

c

b

a V

NOMINAL

= 115 √3 =66.5 Line-to-Ground


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 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


Neutral Shift on Ground Fault: High Impedance Grounded Generator C B

System

A

a Van=Vag

SLG

Fault a

ground

n=g

vag=0

c

Vbn=Vbg

Van= -Vng

b Vbn=Vbg

Vcg

Vbg n

High Impedance Ground

b

c Vcn

Vbn

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


Voltage Inputs 3Y-3Y VT, secondary wired L-G (L-G to L-L selection on the relay). This selection is recommended for the example generator. Generator rating VL-L = 13,800V VT Ratio = 14,400/120V A

13,800 V

B C

14,440 VT Ratio = 14,410 120 120V

13,800 √3

c

VT Type: LG to LL VNOM = 115 V

b

a V

NOMINAL

= 115 √3 =66.5 Line-to-Ground

Software converts (66.4V) voltages to LG (66.5V) LL (115V) quantities


Current Inputs Determine primary current at rated power ¾ Ipri nom = MVA*106 / √3*VLL ¾ Ipri nom = 125*106/(1.732*13800) ¾ Ipri nom = 5,230 A Convert to secondary value ¾ Ct ratio is denoted as RC ¾ RC = 8000/5 = 1600 ¾ Isec nom = I pri nom/RC ¾ Isec nom = 5230/1600 ¾ Isec nom = 3.27 A INOM = 3.27A


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

Generator Protection – Setting Calculations 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 is preferred 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.

Generator Protection – Setting Calculations 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 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.



59N – Neutral Overvoltage (Gen)

IS

VLL Rating

= 13,800 V

PRIS

IS = 3.5 x 13,800 = 201.3A 240 V59N = 0.7 x 201.3 = 140.9V 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) 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 neutral resistor can be calculated and a high enough setting with small delay may be applied.


59N – Neutral Overvoltage (Gen) 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 3rd

Observe 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

3rd H arm o n ic V o ltag e

27TN – Third Harmonic Undervoltage

1.50 1.25 1.00 0.75 0.50 Desired Minimum Setting

0.25 10%

30% 20%

50% 40%

70% 90% 60% 80% 100%

Power / VAr


27TN – Third Harmonic Undervoltage

0.3


27TN Third Harmonic Neutral Undervoltage 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


59N – Neutral Overvoltage (Bus)

14,400 120 V VT

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

3EO = 3 x 66.5 = 200 V


59N – Neutral Overvoltage (Bus) 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)


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

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


Negative Sequence Overcurrent (46) 46IT Pickup=9% Definite maximum time (65,500 cycles)

Pickup 5% 46DT Alarm Time Delay = 30 s

46IT, K=29


46 – Negative Sequence

29


87G – Generator Differential

CT’s are of C800 Standard quality


87G – Generator Differential Generator CT Short Circuit Calculation: Check for the maximum three-phase fault on the terminals of the generator to determine the secondary current for the worst-case internal fault.

X "d ( saturated ) = 15.6% X”d

V 100 = ≈ 6.4 pu I 15.6 I pri (13.8 KV ) = 5230(6.4) = 33,472 A

I pu =

I sec

I pri

33,472 = = = 20.92 A Rc 1600


87G – Generator Differential 69KV Fault Current Calculation: 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 ( saturated ) = 15.6% X”d

X sys = 10%(125MVA) I pu

100 V = = ≈ 3.9 pu X "d + X t 15.6 + 10

I pri (13.8 KV ) = 5230 • 3.9 = 20,397 A I sec

I pri

20,397 = = = 12.75 A Rc 1600


87G – Generator Differential CT Requirement Check Rctr

RW

45°

RR

VK VS

VS Rctr = CT Resistance Rw = Wiring Resistance RR = Relay Burden = 0.5 VA @ 5A = 0.02Ω

IS VK > VS

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


87G – Generator Differential IEEE GUIDE FOR THE APPLICATION OF CURRENT TRANSFORMERS IEEE Std C37.110-1996


87G – Generator Differential Setting Summary 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)


87G – Generator Differential


24 – Volts/Hertz (Overfluxing) 1.40 p.u.

•

1.35

1.30

•

1.25

1.20

1.15

•

1.10

1.05

1.00 0

200

400

600

800

1000

1200

time

Overfluxing Capability, Diagram

1400

1600

1800

2000


24 – Volts/Hertz (Overfluxing) 10000

1000

Inverse Time Element Pickup = 110% Curve #2 K= 4.9

Generator V/Hz Capability V/Hz Protection Curve (Inverse) V/Hz Protection Curve (Definite time)

Time in sec

t = 60 e (115 +2.5 K −VHz ) / 4.8858 100

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

10

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

1

0.1 100

105

110

115

120

125

130

135

140

145

V/Hz in percent of nominal

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


24 – Volts/Hertz (Overfluxing)


50/27 – Inadvertent Energizing 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 % X1SYS = 6.25%

Values shown above are from generator test sheet

X2 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


50/27 – Inadvertent Energizing 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 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 Energizing 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).


50/27 – Inadvertent Energizing

46


Voltage Control/Restraint Overcurrent (51V)

System Configuration with Multiple In-Feeds

Provide backup for system phase faults

Difficult to set: must coordinate with system backup protection

Coordinate 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


51V Voltage Restraint Overcurrent • 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.

Pickup = 1.5 x Generator Full Load Rating

% Pickup

IFL = 3.27A ∴ Pickup current = 3.27 x 1.5 = 4.9 A

Input Voltage (% of rated voltage)

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


Voltage Control/Restraint Overcurrent (51V) Calculate the fault current for a 3 phase 69 KV fault:

Egen

XT

X”d

X"d (saturated) = 15.6% X sys = 10% (125MVA) E gen

100 I pu = = ≈ 3.9pu X"d + X t 15.6 + 10 I pri (13.8KV) = 5230(3.9) = 20,397A I sec =

I pri Rc

=

20,397 = 12.75A 1600


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

Vgen =

Xt 10 100% = 100% = 39% 15.6 + 10 X "d + X t

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

MPU =

I fault I pickupVgen (%)

=

12.75 = 6.67 4.9(0.39)


Definite Time Overcurrent Curve Select the Curve and Time Dial to get 1.0 sec clearing time for 69KV fault: Definite Time curve Time Dial = 4.5

MPU = 6.67


Voltage Control/Restraint Overcurrent (51V) 51V Setting Summary: • Pickup = 4.9 A • Definite Time Curve • Time Dial = 4.5 • Voltage Restraint


Voltage Control/Restraint Overcurrent (51V) Now calculate the lowest fault current for a 3-phase fault: Assumptions: Generator was not loaded prior to fault Automatic Voltage Regulator was off-line Transient 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 except replace the subtransient reactance of the generator with synchronous reactance (Xd) of 206.8%.

I MinFault =

E gen Xd + Xt

=

100 = 0.46 pu 206.8 + 10

I sec = I MinFault I no min al = 0.46(3.27) = 1.5 A


Voltage Control/Restraint Overcurrent (51V) 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:


Voltage Control/Restraint Overcurrent (51V) • 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.


Voltage Control/Restraint Overcurrent (51V)

=>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.


System Phase Fault Backup (21)

Provides protection for failure of system primary relaying

Provides protection for breaker failure

Must balance sensitivity vs. security -

loadability

-

load swings



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

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



Transformer Direct Connected

Transformer DeltaAC Connected

Transformer DeltaAB Connected

VT Connection

VT Connection

VT Connection

L-L or L-G to L-L

L-G

L-L or L-G to L-L

L-G

L-L or L-G to L-L

L-G

AB Fault

VAB Ia-Ib

VA-VB Ia-Ib

VBC-VAB (3)Ib

VB-VO Ib

VAB-VCA (3)Ia

Va-Vo Ia

BC Fault

VBC Ib-Ic

VB-VC Ib-Ic

VCA-VBC (3)Ic

VC-VO Ic

VBC-VAB (3)Ib

Vb-Vo Ib

CA Fault

VCA Ic-Ia

VC-VA Ic-Ia

VAB-VCA (3)Ia

VA-VO Ia

VCA-VBC (3)Ic

Vc-Vo Ic



0.85 power factor corresponds to 31.8º


21 Phase Distance The 21 function should be set to provide system backup protection. To 5559 line 86

line 96 3976

To PP4

3975 line 87

125 MVA base 10% GEN

69 KV 4,000 foot cable

21 To line 83

•

To sub 47

3974

3977

line 97 3978

3972

3973 line 94

To sub PP4

To PP4

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 MVA 5280 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 Zone-1 Settings: Zone-1 will be set to look into the low side of the step-up transformer, but not into the 69kV system.

125 MVA base 10% or 0.10 p.u. GEN

(0.19 + j0.35)% 69 KV 4,000 foot cable 21


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 21-1 Diameter =1.6 Ω Time delay = 0.5 sec. (30 cycles) Angle of maximum torque: 85° 60FL supervised


21 Zone-2 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


Phase Distance (21) RPFA: Rated Power Factor Angle

jX

Generator loadability considerations:

Z2

2.7 Ω

Z1 1.6 Ω

85o

0

Z2 reach at RPFA 1.64 (31.8o)

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

R

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.


(21) – Phase Distance


Breaker Failure-50BF 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.


50BF – Generator Breaker Failure ¾ Steady state bolted fault current for a 3-phase fault at the transformer terminals is 1.5 A (relay secondary). ¾ Set the 50BF phase function current pickup at 1 A, which is below the fault current. ¾ Set the breaker failure time longer than the maximum clearing time of the breaker plus the margin. ¾ Initiate 50BF with all relays that can trip the generator breaker. ¾ Set the 50BF Timer: 4(margin) + 1(accuracy) + 5(breaker time) = 10 cycles. ¾ Use programmable inputs to initiate the breaker failure for all other relays that trip the generator breaker.


50BF – Generator Breaker Failure Setting Summary

¾ 50BF Pickup = 1 A ¾ Time Delay = 10 cycles ¾ Initiate the breaker failure with programmable inputs from external trip commands. ¾ Initiate the breaker failure with the outputs (from internal trip commands) connected to trip.


50BF – Generator Breaker Failure 1.00

9

Breaker Failure Trip Output

BFI

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.


Loss of Field Protection (40) TYPICAL GENERATOR CAPABILITY CURVE


TRANSFORMATION FROM MW-MVAR TO R-X PLOT

MVA = kV2 Z

MW – MVAR

R-X PLOT

( Rc ) Rv


LOSS OF FIELD PROTECTION SETTING CHARACTERISTICS +X

-R

HeavyLoad

- Xd’ 2

1.0pu

Heavy Load Light Load

LightLoad +R

Zone1

Xd

-R

XTG +Xmin SG1 - Xd’ 2

Zone 2

ImpedanceLocus During Loss of Field

Zone 1 1.1Xd

Zone2

-X

Scheme 1

Scheme 2

Directional Element

+R

Impedance Locus During Loss of Field


40 – Loss of Field Generator Ratings (Primary): Rated (base) MVA = 125 Rated (base) Phase-PhaseVoltage (VB): 13.8 kV Rated (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 (Scheme 1) Generator Parameters (125 MVA base) Xd = 2.068 pu X' = 0.245 pu d

Zone-1 Settings Diameter: 1.0 pu = 1.0 x 20.3 = 20.3 ohms Offset = -X ' /2 = (0.245/2)x20.3 = -2.5 ohms d

Time Delay = 5 cycles

Zone-2 Settings Diameter: X

d

= 2.068 x 20.3 = 42.0 ohms

Offset = -X' /2 = (0.245/2)x20.3 = -2.5 ohms d

Time Delay = 30 cycles


40 – Loss of Field 0

X’d = 2.5 Ω 2

R

Zone 1

1.0 p.u. = 20.3 Ω

Xd = 42.0 Ω

Zone 2

-X


Generator Characteristics 20

Q(Mvar)_)

Reactive Power into the Generator

Overexcited Real Power into the System

P (MW)

0 0

20

40

60

80

100

120

140

Underexcited -20

-40

-60

MEL

GCC

SSSL

MEL GCC SSSL

-80

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.


Loss of Filed Settings on the R-X Plane 10

jX

MEL GCC SSSL

(Scheme –1)

R

0 -30

-20

-10

0

-10

Zone 2

Zone 1 -20

-30

-40

-50

10

20

30


Loss Field Settings on P-Q Plane (Scheme – 1) 20

Overexcited P (MW)

Real Power into the System 0 0


-20

20

40

60

80

100

120

Underexcited MEL

GCC SSSL

-40

MEL GCC SSSL

-60

Zone 2 -80

-100

Q (Mvar)_

140

-120

-140

Zone 1


40 – Loss of Field (Scheme 1)


40 – Loss of Field (Scheme 2) Zone-1 Settings Diameter = 1.1 Xd – X’d/2 = 1.1 x 42 – 5/2 = 43.7 ohms Off-set

= -X’d/2 = -5/2 = -2.5 ohms

Time Delay

= 15 cycles

Zone-2 Settings Diameter = 1.1 Xd + XT + Xsys = 1.1 x 42+2.03+1.27 = 49.5 Ohms Off-set = XT+Xsys = 2.03 + 1.27 = 3.3 ohms Angle 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 V Time Delay with undervoltage = 60 cycles.


Loss of Filed Settings on the R-X Plane (Scheme – 2) 10

jX

Directional Element

R

0 -30

-20

-10 Zone 2

MEL GCC SSSL

0

Zone 1 -10

-20

Dir Element X 0 10 -10

-30

-40

-50

10

20

30


Loss Field Settings on P-Q Plane (Scheme – 2)

Q(Mvar)_)


20

Overexcited Real Power into the System

P (MW)

0 0

20

40

60

80

100

120

140

Underexcited -20

MEL

GCC Zone 2

-40

SSSL

-60

-80

MEL GCC SSSL

Zone1


40 – Loss of Field (Scheme 2)


Reverse Power (32) Prevents generator from motoring on loss of prime mover Typical motoring power in percent of unit rating Prime Mover Gas Turbine: Single Shaft Double Shaft Four cycle diesel Two cycle diesel Hydraulic Turbine Steam Turbine (conventional) Steam Turbine (cond. cooled)

% Motoring Power 100 10 to 15 15 25 2 to 100 1 to 4 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.


78 – Out-of-Step Generator and transformer test sheet data, and system information: X′d =24.5% XT = 10% on generator base XSYS = 6.25% on generator base

Use graphical method to determine settings.


78 – Out-of-Step The per unit secondary (relay) impedance = 20.3 Ω Convert all impedances to secondary (relay): Direct axis transient reactance (X′d) = (24.5/100)x 20.3 = 5.0 Ω Transformer impedance (XT) = (10/100)x 20.3 = 2.03 Ω System impedance (XSYS) = (6.25/100)x 20.3 = 1.27 Ω.


Out-of-Step (78) jX

XSYS 1.5 XT = 3 ohms

XT

1.5 XT 0

T GEN (Xd' )

R N 120o

S swing locus

' 2 Xd = 10 ohms d 2.4 ohms


Settings of 78 Function From Graph: Circle diameter

= (2 X’d+ 1.5 XT) = 10 Ω + 3 = 13 Ω

Offset

= -2 X’d = -10 Ω

Impedance angle = 90° Blinder distance (d) = ((X’d+ XT+XSYS)/2) tan (90-(120/2)) d = 2.4 Ω Time delay = 2 to 6 cycles (3 cycles) Trip on mho exit = Enable Pole slip counter = 1.0 Pole slip reset = 120 cycles


78 – Out-of-Step


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


Phase Undervoltage (27)

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.

Definite time element #1 Pickup = 90% (104 V) Time delay = 10 sec (600 cycles)

Definite time element #2 Pickup = 80% (92 V) Time delay = 5 cycles

104 600

92 120

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


Phase Overvoltage (59) 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.

127 600

173

Set the overvoltage function as follows: Definite time element #1 Pickup = 110% (127 V) Time delay = 10 sec (600 cycles) Definite time element #2 Pickup = 150% (173 V) Time delay = 5 cycles


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 they must 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.


81 Frequency Protection Florida Regional Coordinating Council guidelines:


81 Frequency Protection Generator limits: IEC 60034-3: 2005 This 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 limits may be in place that should be considered when setting this element.


81 Frequency Protection Setting Summary: 81-1 : Pickup: 60.6 Hz Time 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


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

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) Injection Frequency adjustment

Decade Box

Initial Conditions: Field breaker closed Relay energized Generator and excitation system must 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


Field Ground Protection - Metering Real-Time Insulation Measurements

Field Insulation Real-Time Monitoring


Field Ground Protection (64F)

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 -

Time delay setting must be greater than 2/finjection


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

- 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.


Brush Lift Detection (64B)

Initial Conditions: > Field breaker closed > Relay energized > Generator and excitation system must be ground free (resistance field-ground >100Kohms) Brush lift-off simulation: > Using the M-3425 secondary metering screen or the status display, record the brush lift detection voltage. > Remove the machine ground connection and record the brush voltage (denoted as faulted condition). > Restore the ground connection


Field Ground Fault Protection Real-Time Measurement

Brush Voltage


Brush Lift Detection (64B) Setting the 64B: General Guidelines: - 64B pickup = unfaulted voltage + 0.5 (faulted brush voltageunfaulted 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.


64F/B - Field Ground Protection

300

600

0.5

©2008 Beckwith Electric Co., Inc.

Generator Protection relay setting calculation

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