GENERTOR
PROTECTION
FUNCTIONS AND
TEST METHODS
Created by:
VASUMURUGAN.R
SPD-VEPL.
GENERATOR PROTECTION FUNCTIONS AND TEST
METHODS
AN OVER VIEW OF GENERATOR SINGLE LINE DIAGRAM:
Generator Protections are broadly classified into three types.
CLASS – A :-
This covers all electrical protections for faults within the generating unit in which
generator field breaker, generator breaker and turbine should be tripped.
CLASS – B:-
This covers all mechanical protections of the turbine in which turbine will be tripped
first and following this generator will trip on reverse power / low forward power
protections.
CLASS – C:-
This covers electrical protection for faults in the system in which generator will be
unloaded by tripping of generator breaker only. The unit will come to house load
operation and the UAT will be in service. Various protections of this class are:
220 KV (HV side of Generator Transformer) busbar protections.
Generator Transformer HV side breaker pole discrepancy.
Generator negative phase sequence protection
Generator Transformer over current / Earth fault protection
Reverse power protection without turbine trip.
2
PROTECTION FUNTIONS:
I - For insulations failures
Differential
Inter-turn fault
Stator Earth Fault (95% & 100%)
Rotor Earth fault (2 Stage)
II – For abnormal running conditions
Loss of excitation (field failure)
Unbalanced loading (negative phase sequence)
Pole sleeping
Over frequency/Over speed
Over voltage
Reverse/Forward power
Impedance/Over current back-up protection, etc…
III – For Generator transformer protections
Differential protection
Bias test
2nd harmonics restrained.
REF protection
3
FOR INSULATION FAILURES PROTECTIONS:
1. GENERATOR DIFFERENTIAL PROTECTION (87 G): It is unit type protection, covering the stator winding for phase to phase faults due to breakdown of
insulation between stator phase windings. This relay is not sensitive for single line to earth faults as the
earth fault current is limited due to the high neutral earthing resistance. If CTs of identical ratios are used
on neutral and line side of generator, an operating current setting of 20% it can be adopted. It is
instantaneous in operation and it trips the generator breaker (Class – A) to eliminate the system in – feed to
the fault along with field breaker and turbines.
For all machines of ratings 10 MVA and above, this protection shall be provided.
Diagram:
Settings:
Pickup Value of Differential Current
T I-DIFF> Time Delay
Pickup Value of High Set Trip
T I-DIFF>> Time Delay
:
:
:
:
0.10 I/InO
0.00 sec
2.0 I/InO
0.00 sec
Testing Method:
a) Differential Pick Up Test:
Side 2 (Generator Neutral Side)
Phase
Set value I/In
cal
diff >
value(Amps)
R-N
0.1
0.41
0.0
Optd trip
time(ms)
36
Y-N
0.1
0.41
0.41
0.0
34
B-N
0.1
0.41
0.41
0.0
37
Side 1 (Generator Terminal Side)
phase
set value I/In
cal value
diff >
(Amps)
R-N
0.1
0.41
optd value
(Amps)
0.41
set time (s)
optd value
(Amps)
0.41
set time (s)
0.0
optd trip
time(ms)
38
Y-N
0.1
0.41
0.41
0.0
36
B-N
0.1
0.41
0.41
0.0
36
4
Note: Calculated value: Ifull=MVA/(1.732*KV)
Idiff=0.2*Ifull
b) DIFFERENTIAL HIGH SET TEST (I DIFF>>)
Side 2 (Gr Neutral Side)
Phase
Set Value I/In
Diff >>
R-N
Y-N
B-N
2.0
2.0
2.0
Cal Value
(Amps)
Optd Value
(Amps)
Set Time (S)
Optd Trip
Time(Ms)
8.2
8.2
8.2
8.2
8.2
8.2
0.0
0.0
0.0
33
32
31
Side 1 (Gr Terminal Side)
Phase
Set Value I/In
Diff >>
Cal Value
(Amps)
Optd Value
(Amps)
Set Time (S)
Optd Trip
Time(Ms)
2.0
2.0
2.0
8.2
8.2
8.2
8.2
8.2
8.2
0.0
0.0
0.0
30
32
32
R-N
Y-N
B-N
Remarks: Class-A tripping should be checked.
c) STABILITY TEST:
Apply the full load current on both terminal and neutral side with an angle of 180 degree phase shift
on any one side. (Angle will be vary depends on the vector group)
Dyn1 (-30° displacement between HV and LV)
Dyn11 (+30° displacement between HV and LV)
Dd0 (no phase displacement between HV and LV)
Dd6 (180° displacement between HV and LV)
2.
INTER TURN FAULT PROTECTION OF THE STATOR WINDING (64GIT) :
Formerly, this type of protection was considered unnecessary because breakdown of insulation between
points on the same phase winding, contained in the same slot, and between which a potential difference exists, will
very rapidly change into an earth fault, and will be detective by either the differential protections or the stator earth
fault protection. An exception is the generator designed to produce a relatively high voltage in comparison to its
output and which therefore contains a large number of conductors per slot. With the size and voltage output of
generators increasing, this form of protection is becoming essential for all generating units.
Diagram:
5
The recommended relay is the high impedance relay having a setting range of 10-40% of rated current.
Settings:
L-E Voltage of Faulted Phase Uph Min
L-E Voltage of Unfaulted Phase Uph Max
Uen> Earth Displacement Voltage
T-DELAY TRIP Uen/3U0
110 V
110 V
10 V
0.50 sec
TEST:
Voltage Applied In(V)
Voltage measured
at open delta
terminal
Voltage
measured
after IVT2
Set value
(V)
Operated
value (V)
Operated
time (sec)
2.4V
10.0V
10.0V
10.0
0.52
Vr-n 61.1 0
Vy-n 63.5 -120
Vb-n 63.5 +1200
Remarks: Class-A tripping should be checked.
3.
STATOR EARTH FAULT PROTECTION (0-95%) 64G1:
It is an over voltage relay monitoring the voltage developed across the secondary of the neutral grounding
transformer in case of ground faults. It covers generator, LV winding of generator transformer and HV
winding of UAT. A pickup voltage setting of 5% is adopted with a time delay setting of about 1.0 Sec. For
all machines of ratings 10 MVA and above this shall be provided. Relay application for this protection is
mainly influenced by the method of stator earthing. Two methods are in common use.
Resistor earthing
Distribution transformer earthing
With resistor earthing, the fault current is limited to 200-300Amps while with distribution transformer
earthing; it is limited to 5-10Amps. The latter method has the advantage of ensuring minimum damage to the
stator core, but it is only practicable when the stator winding is directly connected to the delta winding of the
main transformer. The two schemes for stator earth fault protection (95%) are shown below:1.
Distribution transformer earthing (NGT)
2. Resistor earthing(NGR)
6
Distribution transformer earthing (High impedance
earthing):
Earth fault protection is provided by connecting an
Over voltage relay across its secondary, as shown.
The maximum earth fault current is determined by the
Size of the transformer and the loading resistor R. The
Relay used for this Application is an inverse time or
definite Time over voltage relay (Also known as neutral
displacement Relay) with a setting range Of 2.5 to 20
Volts. The relay is Provided with an inbuilt third
Harmonic filter so as to avoid Unwanted operations due
to third Harmonic currents and the Problems associated
with transformer inter winding capacitance. It is possible
to protect up to 95% of the generator stator Winding
with this relay.
Settings:
Stator Earth Fault Protection
U0> Pickup
T S/E/F Time Delay
Test:
Resistor earthing(Low impedance earthing):
In the resistor earthed scheme, a CT is required in the
neutral to earth connection, and the relay used is an
inverse time current relay so that it can grade with other
earth fault relays in the system. It also provides
protection for the neutral earthing resistor. In this
system, it is impossible to protect 100% of the stator
winding. The percentage of winding protected depends
on the value of the neutral earthing resistor and the relay
setting. In the figure below, the percentage of winding
protector is given for various values of earthing resistor
at different relays settings, from 5-100 %.
ON
4.8 V
0.20 sec
Voltage
injected(V)UE
Voltage measured at relay
(After voltage divider ) (V)
Set value (V)
Operated
value (V)
Set time(s)
Optd
time(s)
12.10
4.84
4.80
4.84
0.2
0.2
Remarks: Class-A tripping should be checked.
100% STATOR EARTH FAULT PROTECTION:To provide 100% stator earth fault protection, an additional relay for covering 95-100% of the winding is provided..
This is a 3rd harmonic U/V relay. It protects 100% of stator winding. During the machine running condition there
will be certain third harmonic voltage at neutral side of the generator. This 3rd harmonic voltage will come
down when a stator earth fault occurs causing this relay to operate. This shall have voltage check or current
check unit, to prevent faulty operation of the relay at generator stand still or during the machine running down
period. The third harmonic relays setting is determined from the amount of generator neutral third harmonic neutral
voltages. Calculations can be based on mission specifications and equipment capacitances or on field measurements.
To prevent 64G2 function from false tripping when there is no voltage, or low voltage, on the generator it's
supervised by the phase under-voltage relay 27.Set this relay at 90% of the rated voltage.
Settings:
100% Stator-Earth-Fault Protection
Pickup Value of Alarm Stage Rsef<
Pickup Value of Tripping Stage Rsef<<
Time Delay of Alarm Stage Rsef<
Time Delay of Tripping Stage Rsef<<
Pickup Value of I SEF>> Stage
Supervision Threshold of 20Hz Voltage
Supervision Threshold of 20Hz Current
ON
168 Ohm
84 Ohm
10.00 sec
1.00 sec
0.75 A
1V
10 mA
7
Test: (According to the theory the test method was given below. With the help of setting, the method was
shorting the PT terminal of generator. For an example short GRP1 TB 18&20 then the relay will
operate after time delay)
set value of voltage(V)
Set value of frequency(Hz)
1% of voltage
set time (s)
150
operated time (s)
1
1.1
Remarks: Class-A tripping should be checked.
4. ROTOR EARTH FAULT (64F):
A single earth fault on the field winding or in the exciter circuit of a generator is not in itself a danger to the
machine. Should a second earth fault develop, however, part of the field winding will become short circuited,
resulting in magnetic un-balance of the filed system with subsequent mechanical damage to the machine
bearings. It is necessary to ensure that should a second rotor earth fault occur, the machine is disconnected. This is
achieved by the use of a second rotor earth fault relay which comprises adjustable resistors and a sensing element.
Diagram:
Settings:
Pickup Value of Warning Stage Re<
40.0 kOhm
Pickup Value of Tripping Stage Re<<
5.0 kOhm
Time Delay of Warning Stage Re<
10.00 sec
Time Delay of Tripping Stage Re<<
1.00 sec
Test:
Wires coming out from generator exciter are to be shorted.
TB’s to be shorted for above: For an example, GRP1/TB1-31, 32.
Set Re in (k )
Alarm ----- 40
Optd value Re in k
Set time (s)
Tested by shorting above TB’s
Trip-------5
optd time (s)
10.0
10.0
1.0
1.02
Remarks: Class-A tripping checked ok
FOR AN ABNORMAL RUNNING CONDITION:
5. LOSS OF EXCITATION OR UNDER EXCITATION(40G):
In case of loss of excitation (loss of field or field failure), the generator goes out of synchronism
and starts running asynchronously at a speed higher than the system, absorbing reactive power from the
system. Under these conditions, the stator end regions and part of the rotor get over heated.
8
Characteristics diagram:
For an example Calculation for getting the susceptance value:
Xdsec - related synchronous direct reactance, secondary,
Xdmach- related synchronous direct reactance of the machine
= 1.965
INMach -Nominal current of the machine
= 8248.1 A
UNMach -Nominal Voltage of the Machine
= 10500 V
UN-CTprim Primary Nominal Voltage of the voltage transformers = 10500 V
IN, CT prim Nominal primary CT current
= 10000A
1/Xd sec = 1/1.965* 8248.1/10500*10500/10000 = 0.42
multiplied by a safety factor of 1.05, the setting value of CHAR. 1 = 1.05 x 0.42 = 0.44 with an
angle of 80deg. Time delay setting 2.0 Second.
CHAR. 2 is set to 0.9 times CHAR. 1 = 0.9 x 0.44 = 0.4 with an angle of 90deg. Time delay
setting 2.0 Second.
CHAR. 3 is set to 2 times CHAR. 1 = 2 x 0.44 = 0.88 with an angle of 100deg. Time delay
setting 0.3 Second.
Note:
The below test was performed by means of voltage and current. But an actual setting is given in
susceptance. The susceptance value will be calculated(given above) inside the relay, when we are
injecting voltage and current.
Settings:
Under excitation Protection(with out U/V) : ON
Susceptance Intersect Characteristic 1
: 0.52
Inclination Angle of Characteristic 1
: 80 °
Characteristic 1 Time Delay
: 2.00 sec
Susceptance Intersect Characteristic2
: 0.47
Inclination Angle of Characteristic 2
: 90 °
Characteristic 2 Time Delay
: 2.00 sec
Susceptance Intersect Characteristic 3
: 0.94
Inclination Angle of Characteristic 3
: 100 °
Characteristic 3 Time Delay
: 0.30 sec
9
Characteristics 1 set value 0.52 at 80 deg & 2sec. (
Applied voltage(V)
Current inj(A)
) Ir from 100mA..
Relay pick up(char1)
Vr-n 63.5 0
Ir
4.0 30
Ir
4.1 30
Vy-n 63.5 -120
Iy 4.0 -90
Iy
4.1 -90
Vb-n 63.5 +120
Ib 4.0 +150
Ib
4.1 +150
Characteristics 2 set value 0.47 at 90 deg at 2 sec. (
Applied voltage(V)
Vr-n 63.5 0
Vy-n 63.5 -120
Vb-n 63.5 +120
Current inj(A)
Ir 2.3 90
Iy 2.3 -30
Ib 2.3 +210
Current inj(A)
Ir 4.6 90
Iy 4.6 -30
Ib 4.6 210
Loss of excitation with u/v:
Under excitation Protection
T-Short Time Delay (Char. & Uexc<
State of Excitation Volt. Supervision
Excitation Voltage Superv. Pickup
Under voltage blocking Pickup
Reactive power = -146.5 MVAR is
observed at the relay pick up stage.
Relay has operated after 2.03 sec.
) Ir from 100mA
Relay pick up(char-2)
Ir 2.31 90
Iy 2.31 -30
Ib 2.31 +210
Characteristics 3 set value 0.94 at 100 deg at 0.3sec. (
Applied voltage(V)
Vr-n 63.5 0
Vy-n 63.5 -120
Vb-n 63.5 +120
Remarks
Remarks
Reactive power = -171 MVAR is
observed at the relay pick up stage.
Relay has operated after 2.02 sec.
) Ir from 100mA
Relay pick up(char-3)
Ir 4.7 90
Iy 4.7 -30
Ib 4.7 +210
Remarks
Active power = 0 MW & Reactive
power = -335 MVAR is observed at
the relay pick up stage.
Relay has operated after 0.350 sec.
ON
0.50 sec
OFF
2.00 V
44.0 V
Loss of excitation + U/V :
Volts applied in(V)
Current Injected in
(A)
Vr-n 63.5 0
Vy-n 63.5 -120
Vb-n 63.5 +120
Ir 3.7 30
Iy 3.7 -90
Ib 3.7 +150
Remarks:
Voltage set value
in(V)
44
44
44
Voltage actual optd
value
44.5
44.5
44.5
Remark
Under
excitation
tripped with
under voltage.
Class-A tripping checked ok
6. NEGATIVE PHASE SEQUENCE PROTECTION (46 G):It safeguards the generator rotor against over heating caused by the induced double frequency (100
Hz) currents when negative phase sequence currents are present in the stator. The negative phase sequence
current (I2) can appear due to unbalanced single phase loads or transmission line unsymmetrical faults.
Alarm stage can be set at 50% of continuous withstand capability of the machine with a time delay of 3 to
5 Sec.
10
Settings:
Unbalance Load Protection
Continuously Permissible Current I2
Warning Stage Time Delay
Negative Sequence Factor K
Time for Cooling Down
I2>> Pickup
T I2>> Time Delay
: ON
: 8.25%
: 20.00 sec
: 12.9 sec
: 1900 sec
: 54%
: 2.50
Test method: Put In=5A
SET % OF
In=Ir
I calculated=3 times
Ir=I injected = Ix
54.0
Injected current
(A)
8.1
8.1
Set Time (S)
2.50
Optd Time
(S)
2.70
Note: In Omicron, for this test change the R, Y, B--Y, B, R or change the Phase angle 0, -120, 120--120, 120, 0
Remarks: Class-C tripping checked ok
7. BACKUP IMPEDANCE PROTECTION (21G):This operates for phase faults in the unit, in the HV yard or in the adjacent transmission lines, with a
suitable time delay. It operates as a backup when the corresponding main protection fails. In A.P. System
the reach is set as 120% of generator transformer with a time delay of about 1.0 to 1.5 Sec.
Settings:
Impedance Protection
Fault Detection I> Pickup
State of Under voltage Seal-in
Under voltage Seal-in Pickup
Duration of Under voltage Seal-in
:ON
:6.50 A
:ON
:77.0V
:3.00 sec
Back Up Impedance Test
Phases
Voltag
e(V)
Current(
A)
Set
imp(Z=V/I)
R
Y
44.45
44.45
6.5
6.5
6.8
6.8
B
44.45
6.5
6.8
Operated
imp(ohm)
Set
time(Sec)
Operated
time(sec)
6.79
6.79
3.0
3.0
3.02
3.02
6.79
3.0
3.02
Remarks: Class-A tripping checked ok
11
8. OVER FLUXING PROTECTION V/F (24):
It is basically a relay which measures v/f of the generator and transformers. As modern power
transformers are designed to operate at very near saturation flux levels under normal operating conditions,
any increase in the voltage or decrease in the frequency, results in the saturation of the core and the
additional flux tries to find its fault through core bolts damaging the core bolt insulation. To prevent this,
over fluxing relay is used.
Settings:
Over excitation Protection (U/f)
U/f > Pickup
T U/f > Time Delay
U/f >> Pickup
T U/f >> Time Delay
: ON
: 1.1
: 10 sec
: 1.4
: 2.00 sec
Calculation:
V/F=110volts/50Hz (Normal)
=2.2=1 P.U
For 1.10 P.U V/F=2.2*1.1=2.42. Corresponding PH-PH Volts=2.42*50=121 V.
PH-E=121/1.732=69.9V
Note: Here we can keep voltage constant and vary the frequency or frequency constant and voltage is
variable one.
Stage 1:
Voltage Applied in (V)
@ 50Hz, Ph-N(In Each
Phase Separately)
69.9
Stage 2:
Voltage Applied
In Volts At @ 50hz PhN (In Each Phase
Separately)
88.9
Calc Value in (V)
121/ 3=69.85
Calc Value In
Volts
154.0/ 3=88.9
Set Value in
V/F
Optd Value
in V/F
Set Time
(S)
Optd
Time(S)
1.10
1.10
10
10.06
Set Value
In V/F
Optd Value
V/F
Set Time
(S)
Optd
Time(S)
1.40
1.40
1.0
0.99
Remarks: Class-A tripping checked ok
9.
LOW FORWARD POWER RELAY (37G):In thermal machines, when the steam flow through turbine is interrupted by closing the ESVs(Electro static
valves) or the governor valves, the remaining steam in the turbine generates (low) power and the machine
enters to motoring conditions drawing power from the system. This protection detects low forward
power conditions of the generator and trips generator breaker after a time delay, avoiding motoring of
generator.
12
Settings:
Forward Power Supervision
P-forw.< Supervision Pickup
T-P-forw.< Time Delay
ON
0.50%
5.0 sec
Low forward power test
Set value for forward power= 0.5% of rated power.
P=1.732*V*I
Calculated value P= 0.05x 16500x1200 x 1.732 = 1.786mw (primary value)
Applied current
(A)
Vr-n 63.5 0
Vy-n 63.5 -120
Vb-n 63.5 +120
Relay optd current
(A)
Ir 0.025 0
Iy 0.025 -120
Ib 0.025 +120
Set value
(MW)
OPtd
Value(MW)
Set
time(S)
Optd time(S)
1.786
1.78
5.0
5.23
Remarks: Class-A tripping checked ok
10. REVERSE POWER RELAY (32G):Reverse power protection shall be used for all types of generators. When the input to the turbine
is interrupted the machine enters into motoring condition drawing power from the system. Reverse power
relay protects the generators from motoring condition. In thermal machines, reverse power condition
appears subsequent to low forward power condition. For reverse power relay, a setting of 0.5% of rated
active power of generator with 2 stage timer as given below.
Stage – I : - With turbine trip interlock, a time delay of 2 Sec. shall be adopted.
Stage –II:- Without ‘ turbine trip’ interlock, a time delay of about20 Sec. can be adopted to avoid
unnecessary tripping of unit during system disturbance causing sudden rise in frequency or
power swing conditions.
Settings:
Reverse Power Protection
: ON
P> Reverse Pickup
: -0.50%
Time Delay Long (without Stop Valve) : 10.00 sec
Time Delay Short (with Stop Valve)
: 2.00sec
Pickup Holding Time
: 0.02 sec
Set value for rev power
-0.5%
Formula: set power = 0.5 % rated power. Rated power =1.732*V*I.
Calculated value= (0.05x1200) x 16500 x 1.732 = 1.786mw (primary value)
Angles b/w voltages & currents are reversed to achieve reverse power.
a. Without turbine trip binary input
Applied current
(A)
Vr-n 63.5 0
Vy-n 63.5 -120
Vb-n 63.5 +120
Relay optd current
(A)
Ir 0.025 180
Iy 0.025 +60
Ib 0.025 -60
Set value
(MW)
OPtd
value(MW)
Set
time(S)
Optd
time(S)
1.786
1.78
10.0
10.05
13
b. With turbine trip binary input
Applied current
Relay optd current
Set value
(A)
(A)
(MW)
Vr-n 63.5 0
Ir 0.05 180
1.786
Vy-n 63.5 -120
Iy 0.05 +60
Vb-n 63.5 +120
Ib 0.05 -60
Remarks:
Class-B with stop valve tripping checked ok
Class-A without stop valve checked ok
OPtd
value(MW)
Set time(S)
Optd
time(S)
1.78
2.0
2.03
11. INADVERTENT ENERGISING(27/50)
In generator turbine was on by using turning gear, the field was not ON. The breaker will be closed by means of
human error. At this condition generator has energized by turn on the turbine. The machine will draw large stator
current (2 to 6 I rated) and possible damage to rotor. This current has induced to rotor body, and then rapid over
heating was damage the rotor also. So we need to avoid this, an inadvertent protection has provided. The
inadvertent energizing protection is blocked by a voltage criterion on exceeding a minimum voltage, in order
to avoid that it picks up during normal operation. This blocking is delayed to avoid that the protection is
blocked immediately by the time of an unwanted connection. Another pickup delay is necessary to avoid an
unwanted operation in case of high-current faults with a heavy voltage dip. This is otherwise known as dead
machine protection.
Settings:
Inadvertent energization
I Stage Pickup
Release Threshold U1<
Pickup Time Delay T U1<
Test:
ON
4.2 A
77.0 V
3.00 sec
Current inj in
phase In Amps
Optd
value(amps)
Set value for reset
threshold (volts)
Pickup set
time (s)
Opt time
(s)
R-n 4.2 0
Y-n 4.2 -120
B-N 4.2 +120
4.2
4.2
4.2
40/1.732=23.09
40/1.732=23.09
40/1.732=23.09
3.0
3.0
3.0
3.0
3.0
3.0
Remarks:
Fuse fail block checked ok
Class-A tripping checked ok
12. OUT-OF-STEP PROTECTION OR POLE SLIP(78G):
This condition occurs when the machine is subjected to severe system disturbances involving rapid change
of voltage and frequency. In the present days, vector surge relays are used along with rate of change of
frequency relays (df/dt) to take care of these conditions. If the generator goes out of synchronism for more than
preset time, these relays will disconnect the machine from the system.
Characteristic diagram:
(This characteristic may differ from relay to relay. This is basically obtained from SIEMENS relay. According to
the settings it will drawn inside the relay. When the settings exceed beyond the range, then it will operate. )
14
Figure : power swing polygon and impedance vectors with angle δ
Ztot = Zb+Zc = 3.0 + 2.2 = 5.2 ohm. Za = 0.289 x 5.2 = 1.503 ohm. Selected za = 1.75 ohm.
Out-of-Step Protection
Pickup Current for Measuring Release
Pickup Current for Measuring Release
Resistance Za of the Polygon (width)
Reactance Zb of the Polygon (reverse)
Reactance Zc of Polygon (forward char.1)
Reactance Dif. Char.1 - Char.2 (forward)
Angle of Inclination of the Polygon
Number of Power Swing: Characteristic 1
Number of Power Swing: Characteristic 2
Holding Time of Fault Detection
Min. Signal Time for Annun. Char. 1/2
ON
I1> 120.00%
I2< 20.00%
1.75 Ohm
3.00 Ohm
2.20 Ohm
0.20 Ohm
75.0 °
2
4
25.00 sec
0.15 sec
Out of step/pole slip test
Keeping current constant, voltage angle is varied from 0 to 180 or 180 to 0 to achieve pole slip. Here
we are varying the angle. Reason is that, Za, Zb; Zc values should be with in zone. Then only it will
operate.
15
Characteristic – 1 (Forward char-1 will have the range b/w 1.75 to 2.20 ohm)
Volts applied
In
Volts
Vr-n
Vy-n
Vb-n
10.0 +100
10.0 +60
10.0 30
Current Injected
In
Amps
Ir
Iy
Ib
6.0 0
6.0 -120
6.0 +120
Set value
2.10
2.10
2.10
Optd
Value
Mw
Set time
(s)
Optd
Trip time(s)
-67.4MW
0
0.03
Optd
Value
Mvar
Set time
(s)
Optd
Trip time(s)
101Mvar
0
0.03
Characteristic – 2 (Reverse char-2 will have the range b/w 2.20 to 3.0ohm)
Volts applied
In
Volts
Vr-n
Vy-n
Vb-n
15.0 270
15.0 150
15.0 30
Current Injected
In
Amps
Ir
Iy
Ib
6.0 0
6.0 -120
6.0 +120
Set value
2.21
2.21
2.21
Remarks: Class-C tripping checked ok
13. GENERATOR UNDER FREQUENCY PROTECTION (81 G):
The Under Frequency protection prevents the steam turbine and generator from exceeding the permissible
operating time at reduced frequencies. It ensures that the generating unit is separated from the network at a preset
value of frequency. It Prevents overfluxing (v/f) of the generator (large overfluxing for short times).The stator under
frequency relay measures the frequency of the stator terminal voltage.
Setting Recommendations:For Alarm
: 48.0 Hz, 2.0 Sec. time delay.
For Trip
: 47.5 Hz, 1.0 Sec.
(or)
As recommended by Generator Manufacturers.
Under frequency test:
STAGE 1
Voltage Applied (v)
Vr-n
Vy-n
Vb-n
63.5 0
63.5 -120
63.5 +120
STAGE 2
Voltage Applied (v)
Vr-n
Vy-n
Vb-n
63.5 0
63.5 -120
63.5 +120
Set value In Hz
Optd value (Hz)
Set time (s)
Optd time(s)
48.5
48.5
48.5
48.40
48.40
48.40
2.50
2.53
Set value In Hz
Optd value(Hz)
Set time (s)
Optd time(s)
47.4
47.4
47.4
47.30
47.30
47.30
2.00
2.03
Remarks:
Fuse fail block checked ok
Class-C tripping checked ok
16
14. GENERATOR OVER VOLTAGE PROTECTION (59 G):
An over voltage on the terminals of the generator can damage the insulator of the generator, bus
ducting, breakers, generator transformer and auxiliary equipment. Hence over voltage protection should be
provided for machines of all sizes.
Settings recommendations:Stage-I
State-II
: Over voltage pickup
Time delay
: Over voltage pickup
Time delay
= 1.15 x Un
= 10 Sec.
= 1.3 x Un
= 0.5 Sec.
Overvoltage test
STAGE 1
Volts applied in
Volts
Vr-n 69.9 0
Vy-n 69.9 -120
Vb-n 69.9 +120
Set value
121.0/ 3=69.86
121.0/ 3=69.86
121.0/ 3=69.86
Pickup
value (v)
69.9
69.9
69.9
Drop up
value (v)
66.20
66.20
66.20
Set time
(s)
Optd trip
time(s)
1.0
1.01
STAGE 2
volts applied in volts
set value
optd value in volts
set time (s)
optd trip
time(s)
76.3
76.3
76.3
0.05
0.07
Vr-n 76.3 0
132.0/ 3=76.2
Vy-n 76.3 -120
132.0/ 3=76.2
Vb-n 76.3 +120
132.0/ 3=76.2
Remarks: Class-A tripping checked ok
FOR TRANSFORMER PROTECTION:
1.
DIFFERENTIAL RELAYS:
A Differential relay compares the currents on both sides of the transformer. As long as there is no
fault within the protected equipment (Transformer), the current circulates between the two CTs and no
current flows through the differential element. But for internal faults the sum of the CTs secondary currents
will flow through the differential relay making it to operate.
Two basic requirements that the differential relay connections are to be satisfied are:
a) It must not operate for load or external faults.
b) It must operate for internal faults.
Settings:
I-RESTRAINT for Start Detection
0.10 I/InO
Factor for Increasing of Char. at Start
1
Maximum Permissible Starting Time
0.0 sec
Pickup for Add-on Stabilization
2.00 I/InO
17
Differential relay Diagram:
TRANSFORMER
I1
I2
O.C
R.C
Test:
a) DIFFERENTIAL PROTECTION (I DIFF>)
LV SIDE:
Current In
Phase
R
Y
B
Set Value
I /In=I Diff>
0.1
0.1
0.1
Calculated
Value(Amps)
0.44
0.44
0.44
Operated
Value(Amps)
0.433
0.433
0.433
Set Trip Time
(Ms)
0.0
0.0
0.0
Operated
Trip Time(Ms)
31
31
31
Operated
value(amps)
0.104
0.104
0.104
Set trip time
(ms)
0.0
0.0
0.0
Operated
Trip time(ms)
31
31
31
Note: Calculated value: Ifull=MVA/(1.732*KV)
Idiff=0.2*Iful
HV SIDE:
Current in
phase
R
Y
B
Set value
I/in diff >
0.1
0.1
0.1
Calculated
value(amps)
0.094
0.094
0.094
b) DIFFERENTIAL PROTECTION (I DIFF>>)
LV SIDE:
Current in phase
R
Y
B
Set value
I /in diff >>
2
2
2
Calculated
value(amps)
8.8
8.8
8.8
Operated
value(amps)
8.85
8.85
8.85
Set trip time
(ms)
0.0
0.0
0.0
Operated
trip time(ms)
31
31
31
18
HV SIDE:
Current in phase
R
Y
B
Set value
I /in diff >>
2
2
2
Calculated
value(amps)
2.08
2.08
2.08
Operated
value(amps)
2.10
2.10
2.10
Set trip time
(ms)
0.0
0.0
0.0
Operated trip
time(ms)
30
30
30
c) STABILITY TEST:
Apply the full load current on both terminal and neutral side with an angle of 180 degree phase shift
on any one side. (Angle will be vary depends on the vector group)
Dyn1 (-30° displacement between HV and LV)
Dyn11 (+30° displacement between HV and LV)
Dd0 (no phase displacement between HV and LV)
Dd6 (180° displacement between HV and LV)
2. DIFFERENTIAL BIAS TEST:
To avoid unwanted relays operation under the above two conditions a "Percentage Bias" differential relays is
used. This test will also get vary from relay to relay.
Simple Slope diagram:
Positive
Torque Region
I1-I2
Negative Torque Region
I1+I2/2 ----
The current flowing through the operating coil of the relay should be nearly zero during normal operating
conditions and when external short circuit occurs the relay should not operate. While setting the differential relay on
a transformer, the (mismatch) current through differential element at normal tap and positive and negative extreme
taps are to be computed. Differential element pickup setting and/or bias settings is adopted based on maximum
percentage mismatch adding some safety margin.
Differential Current
=
| I1-I2 |
Bias Setting
=
|I1-I2 |
----------(I1+I2)/2
DIFFERENTIAL BIAS TEST
Side 2 Current Is Increased & Slope Is Verified From Tripping Values Of Current.
Slope= (I1-I2)/(I1+I2/2)
19
Setting:
Slope 1 =20%
Side 1 (Hv Side)
3 Phase Current
(Amps)
Ir=4.4 0
Iy=4.4 -120
Ib=4.4 120
Ir=4.4 0
Iy=4.4 -120
Ib=4.4 120
Side 2 (Lv Side)
3 Phase Current
(Amps)
Ir=0.94 150
Iy=0.94 270
Ib=0.94 30
Ir=1.37 150
Iy=1.37 270
Ib=1.37 30
Calculated
Slope (%)
Relay
Condition
0.0
Stable
18.6
Operated
Note: During bias test we have to put 180deg phase shift b/w both sides current. This angle may vary depends
upon the vector group of transformer. Here DYn1 i.e. -30deg displacement b/w HV and LV. So 18030=150degree balance angle.
2ND HARMONIC RESTRAINT TEST:
As second harmonic always present predominantly in the inrush currents, hence second harmonics is used as
a stabilizing bias against inrush effect. The differential current is passed through a filter which extracts the
second harmonics; this component is then applied to produce a restraining quantity sufficient to overcome
the operating tendency due to the whole of the inrush current which flows in the operating circuit. The relay will
restrain when the second harmonic component exceeds 20% of the current.
Inrush current characteristic:
.
Test:
1a Current Is Injected At 50 Hz Simultaneously In Each Phase & 100 Hz Current Is Reduced Till Relay Operates.
HV SIDE:
Current In
Phase
R
Y
B
50Hz Current
Injected (A)
100Hz Current
Injected (A)
100Hz Current
Optd Value (A)
0.947
0.947
0.947
0.80
0.80
0.80
0..171
0..171
0..171
2nd
Harmonic
Set Value
(%)
2nd
Harmonic
Optd
Value
(%)
20
18.05
20
LV SIDE:
Current In
Phase
R
Y
B
50Hz Current
Injected (A)
100Hz Current
Injected (A)
100Hz Current
Optd Value (A)
4.40
4.40
4.40
2.0
2.0
2.0
0.80
0.80
0.80
2nd
Harmonic
Set Value
(%)
2nd
Harmonics
Optd
Value (%)
20
18.18
Remark: Class-A trip checked.
3.
RESTRICTED EARTH FAULT:
This relay is operative only for the internal faults of the transformer and thus fast operating timer can be achieved.
An external fault on the star side will result in current flowing in the line CT of the affected phase
and a balancing current in the neutral CT and current in the relay is zero and hence relay is stable.
During an internal fault, the line current on the line CT gets reversed and hence relay operates.
The arrangement of residually connected CTs on the delta side of a transformer is only sensitive to earth faults
on the delta side because zero sequence currents are blocked by the delta winding. For external faults no
current flows through REF unless a CT gets saturated. Hence minimum pickup current setting is adopted (10% or
20% In) on REF relay. Based on this, through fault current, the stabilizing resistor is set such that the relay will not
operate for external fault when a CT gets saturated. This relay operates only for internal earth faults,
instantaneously.
21
TEST:
Stage 1
Set value
I
0.1
Stage 2
Set value
I
1.5
Optd value(amps)
0.1
Optd value(amps)
1.5
Set time
(s)
0.0
Optd trip time
Set time
(s)
0.0
Optd trip time
20ms
20ms
Remarks: Class-a tripping checked ok.
22