Generator Protection Functions and Test Methods (Autosaved) Collection Unzip

7/23/2019 Generator Protection Functions and Test Methods (Autosaved) Collection Unzip

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GENERTOR

PROTECTION

FUNCTIONS ND

TEST METHODS

Created by:

VASUMURUGAN.R

SPD VEPL.


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GENERATOR PROTECTION FUNCTIONS AND TEST

METHODS

AN OVER VIEW OF GENERATOR SINGLE LINE DIAGRAM:

Generator Protections are broadly classified into three types.

CLASSA :- This covers all electrical protections for faults within the generating unit in which

generator field breaker, generator breaker and turbine should be tripped.

CLASSB:- 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.

CLASSC:- 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.


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PROTECTION FUNTIONS:

I - For insulations failures

Differential

Inter-turn faultStator Earth Fault (95% & 100%)

Rotor Earth fault (2 Stage)

IIFor 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

IIIFor Generator transformer protections

Differential protection

Bias test

2nd

harmonics restrained.

REF protection


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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 (ClassA) to eliminate the system infeed 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 : 0.10 I/InO

T I-DIFF> Time Delay : 0.00 sec

Pickup Value of High Set Trip : 2.0 I/InO

T I-DIFF>> Time Delay : 0.00 sec

Testing Method:

a) Differential Pick Up Test:

Side 2 (Generator Neutral Side)

Phase Set value I/Indiff >

calvalue(Amps)

optd value(Amps)

set time (s) Optd triptime(ms)

R-N 0.1 0.41 0.41 0.0 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/Indiff >

cal value(Amps)

optd value(Amps)

set time (s) optd triptime(ms)

R-N 0.1 0.41 0.41 0.0 38

Y-N 0.1 0.41 0.41 0.0 36

B-N 0.1 0.41 0.41 0.0 36


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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/InDiff >>

Cal Value(Amps)

Optd Value(Amps)

Set Time (S) Optd TripTime(Ms)

R-N 2.0 8.2 8.2 0.0 33

Y-N 2.0 8.2 8.2 0.0 32

B-N 2.0 8.2 8.2 0.0 31

Side 1 (Gr Terminal Side)

Phase Set Value I/InDiff >>

Cal Value(Amps)

Optd Value(Amps)

Set Time (S) Optd TripTime(Ms)

R-N 2.0 8.2 8.2 0.0 30

Y-N 2.0 8.2 8.2 0.0 32

B-N 2.0 8.2 8.2 0.0 32

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:


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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 110 V

L-E Voltage of Unfaulted Phase Uph Max 110 V

Uen> Earth Displacement Voltage 10 V

T-DELAY TRIP Uen/3U0 0.50 secTEST:

Voltage Applied In(V)Voltage measured

at open delta

terminal

Voltagemeasured

after IVT2

Set value(V)

Operatedvalue (V)

Operatedtime (sec)

Vr-n 61.1 0

2.4V 10.0V 10.0V 10.0 0.52Vy-n 63.5 -120

Vb-n 63.5 +1200


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 ismainly influenced by the method of stator earthing. Two methods are in common use.

Resistor earthing

Distribution transformer earthingWith 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 thestator 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)


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Distribution transformer earthing (High impedance

earthing):

Earth fault protection is provided by connecting anOver 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 ordefinite 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 dueto third Harmonic currents and the Problems associated

with transformer inter winding capacitance. It is possible

to protect up to 95% of the generator stator Windingwith this relay.

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 aninverse 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 statorwinding. 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 resistorat different relays settings, from 5-100 %.

Settings:

Stator Earth Fault Protection ON

U0> Pickup 4.8 V

T S/E/F Time Delay 0.20 sec

Test:

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


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 3rdharmonic 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 3rdharmonic 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 ON

Pickup Value of Alarm Stage Rsef< 168 OhmPickup Value of Tripping Stage Rsef Stage 0.75 A

Supervision Threshold of 20Hz Voltage 1 V

Supervision Threshold of 20Hz Current 10 mA


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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) set time (s) operated time (s)

1% of voltage 150 1 1.1


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 isachieved 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


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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 delaysetting 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 secSusceptance Intersect Characteristic2 : 0.47


Characteristic 2 Time Delay : 2.00 secSusceptance Intersect Characteristic 3 : 0.94


Characteristic 3 Time Delay : 0.30 sec


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Characteristics 1 set value 0.52 at 80 deg & 2sec. ( ) Ir from 100mA..

Applied voltage(V) Current inj(A)Relay pick up(char-

1)Remarks

Vr-n 63.5 0 Ir 4.0 30 Ir 4.1 30 Reactive power = -146.5 MVAR is

observed at the relay pick up stage.

Relay has operated after 2.03 sec.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. ( ) Ir from 100mA

Applied voltage(V) Current inj(A) Relay pick up(char-2) Remarks

Vr-n 63.5 0 Ir 2.3 90 Ir 2.31 90 Reactive power = -171 MVAR isobserved at the relay pick up stage.

Relay has operated after 2.02 sec.Vy-n 63.5 -120 Iy 2.3 -30 Iy 2.31 -30

Vb-n 63.5 +120 Ib 2.3 +210 Ib 2.31 +210

Characteristics 3 set value 0.94 at 100 deg at 0.3sec. ( ) Ir from 100mA

Applied voltage(V) Current inj(A) Relay pick up(char-3) Remarks

Vr-n 63.5 0 Ir 4.6 90 Ir 4.7 90 Active power = 0 MW & Reactivepower = -335 MVAR is observed at

the relay pick up stage.

Relay has operated after 0.350 sec.

Vy-n 63.5 -120 Iy 4.6 -30 Iy 4.7 -30

Vb-n 63.5 +120 Ib 4.6 210 Ib 4.7 +210

Loss of excitation with u/v:

Under excitation Protection ON

T-Short Time Delay (Char. & Uexc< 0.50 sec

State of Excitation Volt. Supervision OFF

Excitation Voltage Superv. Pickup 2.00 V

Under voltage blocking Pickup 44.0 V

Loss of excitation + U/V :

Volts applied in(V)Current Injected in

(A)

Voltage set value

in(V)

Voltage actual optd

value Remark

Vr-n 63.5 0 Ir 3.7 30 44 44.5 Underexcitation

tripped with

under voltage.

Vy-n 63.5 -120 Iy 3.7 -90 44 44.5

Vb-n 63.5 +120 Ib 3.7 +150 44 44.5

Remarks: 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.


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Settings:

Unbalance Load Protection : ON

Continuously Permissible Current I2 : 8.25%

Warning Stage Time Delay : 20.00 sec

Negative Sequence Factor K : 12.9 sec

Time for Cooling Down : 1900 secI2>> Pickup : 54%

T I2>> Time Delay : 2.50

Test method: Put In=5A

SET % OF

In=Ir

I calculated=3 times

Ir=I injected = Ix

Injected current

(A)

Set Time (S) Optd Time

(S)

54.0 8.1 8.1 2.50 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 :ON

Fault Detection I> Pickup :6.50 AState of Under voltage Seal-in :ON

Under voltage Seal-in Pickup :77.0V

Duration of Under voltage Seal-in :3.00 sec

Back Up Impedance Test

Phases Voltage(V)

Current(A)

Setimp(Z=V/I)

Operatedimp(ohm)

Settime(Sec)

Operatedtime(sec)

R 44.45 6.5 6.8 6.79 3.0 3.02

Y 44.45 6.5 6.8 6.79 3.0 3.02

B 44.45 6.5 6.8 6.79 3.0 3.02



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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) : ON

U/f > Pickup : 1.1T U/f > Time Delay : 10 sec

U/f >> Pickup : 1.4

T U/f >> Time Delay : 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)

Calc Value in (V) Set Value in

V/F

Optd Value

in V/F

Set Time

(S)

Optd

Time(S)

69.9 121/ 3=69.85 1.10 1.10 10 10.06

Stage 2:

Voltage Applied

In Volts At @ 50hz Ph-N (In Each Phase

Separately)

Calc Value In

Volts

Set Value

In V/F

Optd Value

V/F

Set Time

(S)

Optd

Time(S)

88.9 154.0/ 3=88.9 1.40 1.40 1.0 0.99


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 ofgenerator.


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Settings:

Forward Power Supervision ON

P-forw.< Supervision Pickup 0.50%

T-P-forw.< Time Delay 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)

Relay optd current

(A)

Set value

(MW)

OPtd

Value(MW)

Set

time(S)

Optd time(S)

Vr-n 63.5 0 Ir 0.025 0

1.786 1.78 5.0 5.23Vy-n 63.5 -120 Iy 0.025 -120

Vb-n 63.5 +120 Ib 0.025 +120

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.

StageI : - 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 orpower swing conditions.

Settings:

Reverse Power Protection : ONP> Reverse Pickup : -0.50%

Time Delay Long (without Stop Valve) : 10.00 sec

Time Delay Short (with Stop Valve) : 2.00secPickup 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)

Relay optd current

(A)

Set value

(MW)

OPtd

value(MW)

Set

time(S)

Optd

time(S)

Vr-n 63.5 0 Ir 0.025 180

1.786 1.78 10.0 10.05Vy-n 63.5 -120 Iy 0.025 +60

Vb-n 63.5 +120 Ib 0.025 -60


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b. With turbine trip binary input

Applied current(A)

Relay optd current(A)

Set value(MW)

OPtdvalue(MW)

Set time(S) Optdtime(S)

Vr-n 63.5 0 Ir 0.05 180

1.786 1.78 2.0 2.03Vy-n 63.5 -120 Iy 0.05 +60

Vb-n 63.5 +120 Ib 0.05 -60Remarks:

Class-B with stop valve tripping checked ok

Class-A without stop valve checked ok

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 statorcurrent (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 isblocked 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 ON

I Stage Pickup 4.2 ARelease Threshold U1< 77.0 V

Pickup Time Delay T U1< 3.00 sec

Test:

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 4.2 40/1.732=23.09 3.0 3.0

Y-n 4.2 -120 4.2 40/1.732=23.09 3.0 3.0

B-N 4.2 +120 4.2 40/1.732=23.09 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 offrequency 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. )


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Figure : power swing polygon and impedance vectors with angle 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 ON

Pickup Current for Measuring Release I1> 120.00%

Pickup Current for Measuring Release I2< 20.00%

Resistance Za of the Polygon (width) 1.75 Ohm

Reactance Zb of the Polygon (reverse) 3.00 Ohm

Reactance Zc of Polygon (forward char.1) 2.20 Ohm

Reactance Dif. Char.1 - Char.2 (forward) 0.20 Ohm

Angle of Inclination of the Polygon 75.0

Number of Power Swing: Characteristic 1 2

Number of Power Swing: Characteristic 2 4

Holding Time of Fault Detection 25.00 sec

Min. Signal Time for Annun. Char. 1/2 0.15 sec

Out of step/pole slip testKeeping 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.


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Characteristic1 (Forward char-1 will have the range b/w 1.75 to 2.20 ohm)

Volts applied

In

Volts

Current Injected

In

Amps

Set value Optd

Value

Mw

Set time

(s)

Optd

Trip time(s)

Vr-n 10.0 +100 Ir 6.0 0 2.10

-67.4MW 0 0.03Vy-n 10.0 +60 Iy 6.0 -120 2.10

Vb-n 10.0 30 Ib 6.0 +120 2.10

Characteristic2 (Reverse char-2 will have the range b/w 2.20 to 3.0ohm)

Volts appliedIn

Volts

Current InjectedIn

Amps

Set value OptdValue

Mvar

Set time(s)

OptdTrip time(s)

Vr-n 15.0 270 Ir 6.0 0 2.21

101Mvar 0 0.03Vy-n 15.0 150 Iy 6.0 -120 2.21

Vb-n 15.0 30 Ib 6.0 +120 2.21

Remarks: Class-C tripping checkedok

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 underfrequency 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) Set value In Hz Optd value (Hz) Set time (s) Optd time(s)

Vr-n 63.5 0 48.5 48.40

2.50 2.53Vy-n 63.5 -120 48.5 48.40

Vb-n 63.5 +120 48.5 48.40

STAGE 2

Voltage Applied (v) Set value In Hz Optd value(Hz) Set time (s) Optd time(s)

Vr-n 63.5 0 47.4 47.30

2.00 2.03Vy-n 63.5 -120 47.4 47.30

Vb-n 63.5 +120 47.4 47.30

Remarks:

Fuse fail block checked ok

Class-C tripping checked ok


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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 : Over voltage pickup = 1.15 x UnTime delay = 10 Sec.

State-II : Over voltage pickup = 1.3 x Un

Time delay = 0.5 Sec.

Overvoltage test

STAGE 1

Volts applied inVolts

Set value Pickupvalue (v)

Drop upvalue (v)

Set time(s)

Optd triptime(s)

Vr-n 69.9 0 121.0/ 3=69.86 69.9 66.20

1.0 1.01Vy-n 69.9 -120 121.0/ 3=69.86 69.9 66.20

Vb-n 69.9 +120 121.0/ 3=69.86 69.9 66.20

STAGE 2

volts applied in volts set value optd value in volts set time (s) optd triptime(s)

Vr-n 76.3 0 132.0/ 3=76.2 76.3

0.05 0.07Vy-n 76.3 -120 132.0/ 3=76.2 76.3

Vb-n 76.3 +120 132.0/ 3=76.2 76.3


FOR TRANSFORMER PROTECTION:

1. DIFFERENTIAL RELAYS:

A Differential relay compares the currents on both sides of the transformer. As long as there is nofault 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


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Differential relay Diagram:

TRANSFORMER I2

Test:

a) DIFFERENTIAL PROTECTION (I DIFF>)

LV SIDE:

Current InPhase

Set ValueI /In=I Diff>

CalculatedValue(Amps)

OperatedValue(Amps)

Set Trip Time(Ms)

OperatedTrip Time(Ms)

R 0.1 0.44 0.433 0.0 31

Y 0.1 0.44 0.433 0.0 31

B 0.1 0.44 0.433 0.0 31

Note: Calculated value: Ifull=MVA/(1.732*KV)

Idiff=0.2*Iful

HV SIDE:

Current in

phase

Set value

I/in diff >

Calculated

value(amps)

Operated

value(amps)

Set trip time

(ms)

Operated

Trip time(ms)

R 0.1 0.094 0.104 0.0 31

Y 0.1 0.094 0.104 0.0 31

B 0.1 0.094 0.104 0.0 31

b)

DIFFERENTIAL PROTECTION (I DIFF>>)

LV SIDE:

Current in phase Set valueI /in diff >>

Calculatedvalue(amps)

Operatedvalue(amps)

Set trip time(ms)

Operatedtrip time(ms)

R 2 8.8 8.85 0.0 31

Y 2 8.8 8.85 0.0 31

B 2 8.8 8.85 0.0 31

O.C

R.C

I1


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HV SIDE:

Current in phase Set valueI /in diff >>

Calculatedvalue(amps)

Operatedvalue(amps)

Set trip time(ms)

Operated triptime(ms)

R 2 2.08 2.10 0.0 30

Y 2 2.08 2.10 0.0 30

B 2 2.08 2.10 0.0 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:

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 extremetaps 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 |

|I1-I2 |Bias Setting = -----------

(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)

Positive

Negative Torque Region

I1-I2


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Setting:

Slope 1 =20%

Side 1 (Hv Side)

3 Phase Current

(Amps)

Side 2 (Lv Side)

3 Phase Current

(Amps)

Calculated

Slope (%)

Relay

Condition

Ir=4.4 0Iy=4.4 -120

Ib=4.4 120

Ir=0.94 150Iy=0.94 270

Ib=0.94 30

0.0 Stable

Ir=4.4 0

Iy=4.4 -120

Ib=4.4 120

Ir=1.37 150

Iy=1.37 270

Ib=1.37 30

18.6 Operated

Note: During bias test we have to put 180deg phase shift b/w both sides current. This angle may vary dependsupon the vector group of transformer. Here DYn1 i.e. -30deg displacement b/w HV and LV. So 180-

30=150degree balance angle.

2NDHARMONIC 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

50Hz Current

Injected (A)

100Hz Current

Injected (A)

100Hz Current

Optd Value (A)

2nd

HarmonicSet Value

(%)

2nd

HarmonicOptd

Value(%)

R 0.947 0.80 0..171

20 18.05Y 0.947 0.80 0..171

B 0.947 0.80 0..171


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LV SIDE:

Current In

Phase

50Hz Current

Injected (A)

100Hz Current

Injected (A)

100Hz Current

Optd Value (A)

2nd

HarmonicSet Value

(%)

2nd

HarmonicsOptd

Value (%)

R 4.40 2.0 0.80

20 18.18Y 4.40 2.0 0.80B 4.40 2.0 0.80

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% or20% 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.


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TEST:

Stage 1

Set valueI

Optd value(amps) Set time(s)

Optd trip time

0.1 0.1 0.0 20ms

Stage 2Set valueI

Optd value(amps) Set time(s)

Optd trip time

1.5 1.5 0.0 20ms

Remarks: Class-a tripping checked ok.

Documents

Generator Protection Functions and Test Methods (Autosaved) Collection Unzip