Generator Protection
Relay Setting Calculations
Generator Protection – Setting Calculations
Generator Protection
Sample Relay Setting Calculations
ƒ The sample calculations shown here illustrate
steps involved in calculating the relay settings for
generator protection.
ƒ Other methodologies and techniques may be
applied to calculate relay settings based on
specific applications.
Generator Protection – Setting Calculations
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%
-
Generator Protection – Setting Calculations
Generator Protection – Setting Calculations
Nominal Voltages and Currents
Voltages and currents that are present
at the input terminals when the
generator is operating at rated voltage
and current.
Generator Protection – Setting Calculations
Voltage Inputs and their connections
.
.
3V0
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
ƒ 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
ƒ They will not operate for neutral shifts that can occur during
stator ground faults on high impedance grounded generators
ƒ The oscillograph in the relays will record line-ground voltage
to provide stator ground fault phase identification
Generator Protection – Setting Calculations
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
ƒ A ground fault will cause LG connected phase elements
through a 3Y-3Y VT to have undervoltage or overvoltage
(depending on faulted phase)
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
Current Inputs
ƒ 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
ƒ 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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
59N – Neutral Overvoltage (Gen)
ƒ 59N setpoint # 1 = 5.4 V, 2 ~ 10 sec.
ƒ 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
ƒ 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.
Generator Protection – Setting Calculations
59N – Neutral Overvoltage (Gen)
ƒ 59N Setpoint #2 = 35 V,
5 sec. (300 cycles)
Note: Setpoints should be
coordinated
with
low
voltage secondary VT
fuses
ƒ 59N #3 can be used for
alarm and trigger an
oscillograph (set to 5 V
at 1 sec)
Generator Protection – Setting Calculations
ƒ 27TN is set by measurement of
third harmonic voltage during
commissioning
3rd
ƒ Observe
harmonic voltage
under various loading conditions
ƒ Set the 27TN pickup to 50% of the
observed minimum
ƒ 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
Generator Protection – Setting Calculations
27TN – Third Harmonic Undervoltage
0.3
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
59N – Neutral Overvoltage (Bus)
14,400
120 V VT
ƒ 59N is connected to a
broken-delta VT input
on the line side of the
generator breaker for
ungrounded system
bus protection
ƒ The
system
is
ungrounded
when
backfed from the GSU
and the generator
disconnect switch is
open
3EO = 3 x 66.5 = 200 V
Generator Protection – Setting Calculations
59N – Neutral Overvoltage (Bus)
ƒ The maximum voltage for a solidly-grounded fault
is 3 x 66.5 = 200 V.
ƒ Because of the inaccuracies between the VTs, there
can be some normal unbalanced voltages.
ƒ 59N Setpoint #1 Pick-up = 12 V, 12 sec (720 cycles)
ƒ 59N Setpoint # 2 Pick-up = 35 V, 5.5 sec (330
cycles)
Generator Protection – Setting Calculations
46 – Negative Sequence
Nameplate
ƒ 10% continuous capability of stator rating (125 MVA),
the same as that stipulated in ANSI/IEEE C37.102.
ƒ The K factor is 30.
Set Inverse Time Element for Trip
ƒ
ƒ
Pick-up for tripping the unit (Inverse Time) = 9%
K=29
ƒ
Definite Maximum time = 65,500 cycles.
Set Definite Time Element for Alarm
ƒ Pickup =5%
ƒ Time delay = 30 sec (1800 cycles). Note that 30 sec
should be longer than a 69 KV system fault clearing
time.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
Negative Sequence Overcurrent (46)
46IT Pickup=9%
Definite maximum time (65,500 cycles)
Pickup 5%
46DT Alarm
Time Delay = 30 s
46IT, K=29
Generator Protection – Setting Calculations
46 – Negative Sequence
29
Generator Protection – Setting Calculations
87G – Generator Differential
CT’s are of C800 Standard quality
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
ƒ CTs should perform well since the maximum current is only
21 A (CT secondary) for worst-case short circuit.
Generator Protection – Setting Calculations
87G – Generator Differential
IEEE GUIDE FOR THE APPLICATION OF CURRENT TRANSFORMERS
IEEE Std C37.110-1996
Generator Protection – Setting Calculations
87G – Generator Differential
Setting Summary
ƒ Pick-up = 0.3 A (480 A primary sensitivity)
ƒ Slope = 10%
ƒ Time Delay = 1 cycle (no intentional time delay)
(if ct saturation is possible time delay should be
increased to 5 cycles)
Generator Protection – Setting Calculations
87G – Generator Differential
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
ƒ
Protection can be provided with an inverse time element (24IT) in combination
with a definite time element (24DT#1)
ƒ
Another definite time element (24DT#2) can be used for alarm with a typical
pickup of 106% and a time delay of 3 sec
Generator Protection – Setting Calculations
24 – Volts/Hertz (Overfluxing)
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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).
Generator Protection – Setting Calculations
50/27 – Inadvertent Energizing
46
Generator Protection – Setting Calculations
Voltage Control/Restraint Overcurrent (51V)
System Configuration with Multiple In-Feeds
ƒ
Provide backup for system phase faults
ƒ
Difficult to set: must coordinate with system backup protection
ƒ
Coordinate general setting criteria
-
backup relaying time
-
breaker failure
-
Consideration should be given to system emergency conditions.
Generator Protection – Setting Calculations
Voltage Control/Restraint Overcurrent (51V)
Voltage control/restraint needed because of generator fault current decay
ƒ
ƒ
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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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)
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
Voltage Control/Restraint Overcurrent (51V)
51V Setting Summary:
• Pickup = 4.9 A
• Definite Time Curve
• Time Dial = 4.5
• Voltage Restraint
Generator Protection – Setting Calculations
Voltage Control/Restraint Overcurrent (51V)
Now calculate the lowest fault current for a 3-phase fault:
Assumptions:
ƒ Generator was not loaded prior to fault
ƒ Automatic Voltage Regulator was off-line
ƒ 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
Generator Protection – Setting Calculations
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:
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
System Phase Fault Backup (21)
ƒ
Provides protection for failure of system primary relaying
ƒ
Provides protection for breaker failure
ƒ
Must balance sensitivity vs. security
-
loadability
-
load swings
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
System Phase Fault Backup (21)
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
Generator Protection – Setting Calculations
System Phase Fault Backup (21)
0.85 power factor corresponds to 31.8º
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
(21) – Phase Distance
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
Loss of Field Protection (40)
TYPICAL GENERATOR CAPABILITY CURVE
Generator Protection – Setting Calculations
TRANSFORMATION FROM MW-MVAR TO R-X PLOT
MVA = kV2
Z
MW – MVAR
R-X PLOT
( Rc )
Rv
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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 Protection – Setting Calculations
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
ƒ 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 Protection – Setting Calculations
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
Generator Protection – Setting Calculations
Loss Field Settings on P-Q Plane
(Scheme – 1)
20
Overexcited
P (MW)
Real Power into the System
0
0
Reactive Power into the Generator
-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
Generator Protection – Setting Calculations
40 – Loss of Field (Scheme 1)
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
Loss Field Settings on P-Q Plane
(Scheme – 2)
Q(Mvar)_)
Reactive Power into the Generator
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
Generator Protection – Setting Calculations
40 – Loss of Field (Scheme 2)
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
78 – Out-of-Step
Generator and transformer test sheet data, and system
information:
ƒ X′d =24.5%
ƒ XT = 10% on generator base
ƒ XSYS = 6.25% on generator base
Use graphical method to determine settings.
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
78 – Out-of-Step
Generator Protection – Setting Calculations
Fuse Loss Detection (60FL)
(block 51V, 21, 40, 78, 32)
Generator Protection – Setting Calculations
Phase Undervoltage (27)
ƒ
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
81 Frequency Protection
Florida Regional Coordinating Council
guidelines:
Generator Protection – Setting Calculations
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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
Field Ground Protection (64F)
Field Tests of the 64F
Safety Considerations
ƒ The signal applied by the
M-3425 64F is less than
20Vp-p.
ƒ Generator and Field must
be
de-energized for
this test.
ƒ All test equipment must
be removed prior to
energization.
Generator Protection – Setting Calculations
Field Ground Protection (64F)
Injection Frequency adjustment
ƒ
ƒ
ƒ
ƒ
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
Generator Protection – Setting Calculations
Field Ground Protection - Metering
Real-Time Insulation Measurements
Field Insulation
Real-Time Monitoring
Generator Protection – Setting Calculations
Field Ground Protection (64F)
ƒ
ƒ
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
Generator Protection – Setting Calculations
Field Ground Protection (64F)
ƒ 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.
Generator Protection – Setting Calculations
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
Generator Protection – Setting Calculations
Field Ground Fault Protection
Real-Time Measurement
Brush Voltage
Generator Protection – Setting Calculations
Brush Lift Detection (64B)
Setting the 64B:
ƒ General Guidelines:
- 64B pickup = unfaulted voltage + 0.5 (faulted brush voltageunfaulted brush voltage)
- 64B delay = 600 cycles
ƒ 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.
Generator Protection – Setting Calculations
64F/B - Field Ground Protection
300
600
0.5
©2008 Beckwith Electric Co., Inc.