Generator Protection Calculations Settings
Generator Protection Calculations Settings
Generator Protection Calculations Settings
Voltage Inputs,
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
VT Type: Line-to-Ground
VNOM = 115/3 = 66.4 V
13,800 V
14,440
VT Ratio = 14,410
120V120
13,800
3
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
System
a
Van=Vag
SLG
Fault
a
ground
n=g
vag=0
Vbn=Vbg
Van= -Vng
b
Vbn=Vbg
Vcg
Vbg
n
High
Impedance
Ground
c
Vcn
Vbn
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
VT Type: LG to LL
VNOM = 115 V
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
Ipri nom = MVA*106 / 3*VLL
Ipri nom = 125*106/(1.732*13800)
Ipri nom = 5,230 A
Convert to secondary value
Ct ratio is denoted as RC
RC = 8000/5 = 1600
Isec nom = I pri nom/RC
Isec nom = 5230/1600
Isec nom = 3.27 A
INOM = 3.27A
IS
VLL Rating
= 13,800 V
PRIS
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
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
0.3
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
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
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.
Pickup 5%
46DT Alarm
Time Delay = 30 s
46IT, K=29
46 Negative Sequence
29
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
X sys = 10%(125MVA)
I pu
100
V
=
=
3.9 pu
X "d + X t 15.6 + 10
I pri
20,397
=
=
= 12.75 A
Rc
1600
RW
45
RR
VK
VS
VS
Rctr = CT Resistance
Rw = Wiring Resistance
RR = Relay Burden = 0.5 VA @ 5A
= 0.02
IS
VK > VS
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
1400
1600
1800
2000
24 Volts/Hertz (Overfluxing)
10000
1000
Time in sec
Alarm Settings:
Definite Element #2
Pickup = 106%
Time Delay = 3 sec
10
0.1
100
105
110
115
120
125
130
135
140
145
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)
X2 = 16.4 %
X1SYS = 6.25%
X2
All reactances on generator base (125 MVA)
46
breaker failure
% Pickup
IFL = 3.27A
Pickup current = 3.27 x 1.5 = 4.9 A
Egen
XT
Xd
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
Vgen =
Xt
10
100% =
100% = 39%
15.6 + 10
X "d + X t
MPU =
I fault
I pickupVgen (%)
12.75
= 6.67
4.9(0.39)
MPU = 6.67
I MinFault =
E gen
Xd + Xt
100
= 0.46 pu
206.8 + 10
loadability
load swings
The fault appears farther than the actual location due to infeed.
Transformer
Direct 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
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
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
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.
(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 = 1.60
Setting Summary for 21-1
Diameter =1.6
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
Then the Zone-2 reach setting is:
= 0.1345 x 20.3 = 2.73 .
21 Zone-2 Settings:
Setting Summary for 21-2
Diameter = 2.73
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
jX
Generator loadability
considerations:
Z2
2.7
Z1
1.6
85o
Z2 reach at
RPFA 1.64 (31.8o)
Z2 at RPFA should
not exceed 150 to 200
% of generator rating
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.
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 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
BFI
MVA = kV2
Z
MW MVAR
R-X PLOT
( Rc )
Rv
-R
HeavyLoad
- Xd
2
1.0pu
LightLoad
+R
Zone1
Xd
-R
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
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
Zone-2 Settings
Diameter: X
40 Loss of Field
0
Xd = 2.5
2
Zone 1
Xd = 42.0
Zone 2
-X
Generator Characteristics
20
Q(Mvar)_)
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
jX
MEL
GCC
SSSL
(Scheme 1)
0
-30
-20
-10
-10
Zone 2
Zone 1
-20
-30
-40
-50
10
20
30
Overexcited
P (MW)
-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
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.
jX
Directional Element
0
-30
-20
-10
Zone 2
MEL
GCC
SSSL
Zone 1
-10
-20
Dir Element
X
0
10
-10
-30
-40
-50
10
20
30
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
% Motoring Power
100
10 to 15
15
25
2 to 100
1 to 4
0.5 to 1.0
78 Out-of-Step
Generator and transformer test sheet data, and system
information:
Xd =24.5%
XT = 10% on generator base
XSYS = 6.25% on generator base
78 Out-of-Step
The per unit secondary (relay) impedance = 20.3
Convert all impedances to secondary (relay):
Direct axis transient reactance (Xd) =
(24.5/100)x 20.3 = 5.0
Transformer impedance (XT) =
(10/100)x 20.3 = 2.03
System impedance (XSYS) =
(6.25/100)x 20.3 = 1.27 .
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
Offset
= -2 Xd = -10
Impedance angle = 90
Blinder distance (d) = ((Xd+ XT+XSYS)/2) tan (90-(120/2))
d = 2.4
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
104
600
92
120
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 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.
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
Safety Considerations
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 Insulation
Real-Time Monitoring
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
Brush Voltage
300
600
0.5