Generator Protection 2t75n

Generator Protection. 1. Loss of Prime Mover : Generator Motoring 2. Generator Reverse Power Protection 3. Generator Over/Under Frequence Protection. 4. Over Excitation : Volt per hertz Protection. 5. Under Excitation Protection. 6. Generator Minimum Impedance Protection 7. Generator Negative Phase Sequence Current Protection 8. Generator Inter turn Fault Protection 9. Thermal Over Load. 10.Over Voltage. 11.Loss of Synchronism. 12.Diff Protection. 13.Diff Over All Differential Protection. 14.Rotor Earth Fault Protection. 15.Stator Earth Fault Protection

Excitation System Protection and Limiter. 1) 2) 3) 4)

Field Grounds. Field Over Excitation. Field Under Excitation. Practical consideration.

Distributed Generator Intertie Protection. 1) Power Quality Protection. 2) Power System Fault Protection. 3) System Protection for faults on distributed. 1)Loss of Prime Mover : Generator Motoring(32) Loss of prime mover is due to the loss of Steam supply to turbine.In case of loss of prime mover , ie loss of mechanical inputs, The generator continue to remains synchronized with the grid. The generator now running as synchronous motor. The generator now draws a small amount of active power from the grid in order to drive the turbine. At the same time the generator supply reactive power to grid since its excitation is intact (AVR is supplying field voltage & field current). Running in this mode is not harmful to generator but is definitely harmful to prime mover (Steam Turbine). Loss of Steam supply to the Prime Mover (Steam Turbine) causes a churning of trapped steam in the turbine, which causes the temperature rise and may damage the turbine blades.

Therefore, it imperative to detect the Loss of Prime Mover quickly and followed by the tripping of Generator.

Preventive action:Directional relay. During the normal condition generator stator supply full load current to the grid. During the loss of Prime Mover the magnitude of stator current is smaller than when it was generating and the stator current goes 180 deg. Phase shift. The magnitude of phase current is very small compared to forward current, hence the degree sensitivity of Directional relay used for Loss of Prime Mover should be very hi compared to Direction relay used for over current application. Therefore, these can be protected by using Directional Relay. The Directional relay input are:- Phase Voltage & Phase Current , Output:- Tripping to Generator CB. 2)GENERATOR REVERSE POWER PROTECTION (32) Reverse power can be occur when there is loss of Prime Mover as already discussed or when two or more generator are running in parallel. if one generator does not accept load usually because its unloaded running speed is less than the other generator (called speed droop) then the other generator will motorized the drooping generator. The generator are classified by their Prime Mover which determine the amount of Reverse power they can motor. Sr.No Prime Mover Motorizing Power in % of Unit Rating 1 Gas Turbine (single shaft) 100% 2 Gas Turbine (Double Shaft) 10-15% 3 4 Cycle Diesel 15% 4 2 Cycle Diesel 25% 5 Hydraulic Turbine 2-100 6 Steam Turbine 1-4% (Conventional) 7 Steam Turbine (Cond 0.5 to 1.0% Cooled) Say for example Generator Capacity-37500KVA Generator Terminal Voltage:- 11KV CT-2400/1, PT -11KV/110V, 50Hz. Let us assume Unit motoring power rated as 1% of ratedKVA=375KVA

Generator full load at Unity PF=>, 37500/11*1.732=1968 Amp Primary During Motoring Condition Im(Primary)=375/11*1.732=19.68 Im (Sec)= 19.68*1/2400=0.0082 Amp. Therefore, during motoring condition, when 0.0082 amp flows, Relay gives trip command with time delay setting. AT 30MW ACBPL Setting for Reverse Power Protection in REM 545 Function Code=UPOW6ST_ (Three Phase Under Power or Reverse Power Protection) 1) Relay can be operative either in Operation Mode=Reverse Power or Operation Mode=Under Power) 2) This function is applicable for following types of Prime Mover a. Steam Turbines b. Francis & Kaplan Hydro Units c. Gas Turbine d. Diesel Turbine. 3) Parameters Setting a. For Reverse Power = 3%. b. Angle set=-90°. c. Wait time=

3)GENERATOR OVER/UNDER FREQUENCY PROTECTION. (14A/14T/81) The Generator are designed to give rated output voltage & frequency of 50Hz. The operation within the safe limit of +-5% (47.5 to 52.5)of rated frequency (50Hz)is recommended to protect various apparatus in a network , Generator , Turbine & Transformer. Over frequency condition occurs when excess generation or when load is thrown off. This situation can be corrected quickly by a reduction in power output via governor system. The Over Speed of a generator would result in Over Frequency operation of generator. Steam turbines being the key elements of such power plants, are running closer and closer to their mechanical limits and must be protected

efficiently against vital risks. Steam turbines normally run with constant rotor speed of 7059 rotations per minute (rpm) in a 50 Hz grid . Due to the large masses of rotors and blades over-speeding the turbine is very critical and lead to blade cracks, blade losses and heavy rotor and bearings defects. Under frequency caused by load in excess of generation. And mostly used for load shedding purpose. Protection is required for the following reasons. 1) With under frequency, Generator Stator & Rotor cooling effect reduces thus load carrying capability reduces. 2)

Steam Turbine blades are designed and tuned for operation at rated frequency rotation. Under frequency protection is used to prevent blade resonance & fatigue damage in the turbine.

3) The Electromagnetic flux ф is proportional to Terminal Voltage Vt & Inversely Proportional to Frequency. Ф α ….. Vt……….. Freq. Therefore, if the frequency decreases then Flux increases as a result field current would be on the higher side than at the rated freq. This will causes a Over Fluxing. The over fluxing will causes the over- heating of Stator & rotor circuit.

4)OVER EXCITATION PROTECTION V/Hz (24)

The over excitation protection system are used to protect Generator against the excessive Flux density and saturation of the magnetic core. The saturation leads to the stray flux which may cause eddy current and severe overheating in non-laminated parts of a generator. v/f ratio are commonly used to denote flux density. 1) This condition arises during abnormal operating conditioni.e heavy voltage fluctuation at lower frequency 2) Due to AVR malfunctioning.

The Electromagnetic flux (ф)is proportional to Terminal Voltage Vt & Inversely Proportional to Frequency. Ф (webers) α ….. Vt……….. Freq. The magnetic flux density B (Tesla)=ф (weber)/Area (m2). Since the area of Magnetic core is fixed quantity. hence, Increase in Flux ф will increase in Flux density (B). The Flux density is depends up on the type of material used for the constructions of Core in the Generator.

The properties of different materials are as follows:,

1.Standard sheet steel, annealed. 2) Silicon sheet steel, annealed, Si 2.5%. 3.Soft steel casting. 4. Tungsten steel . 5) Magnet Steel. 6) Cast Iron. 7. Nickel 99%. 8) Cast Cobalt. 9) Magnetite, Fe2O3.

The relationship between magnetic field strength (H) and magnetic flux density (B) is not linear in such materials. If the relationship between the two is plotted for increasing levels of field strength, it will follow a curve up to a point where further increases in magnetic

field strength will result in no further change in flux density. This condition is called magnetic saturation. If the magnetic field is now reduced linearly, the plotted relationship will follow a different curve back towards zero field strength at which point it will be offset from the original curve by an amount called the remanent flux density or remanence. If this relationship is plotted for all strengths of applied magnetic field the result is a sort of S- shaped loop. The 'thickness' of the middle bit of the S describes the amount of hysteresis, related to the coercivity of the material. Its practical effects might be, for example, to cause a relay to be slow to release due to the remaining magnetic field continuing to attract the armature when the applied electric current to the operating coil is removed.

Protection System 1) Normally Over Excitation protection inbuilt in the AVR system. 2) Back up Protection is provided by Generator Protection Relay.ie REM 545. The core of 30MW generator is made up of Silicon Sheet Steel, whose B value is 1.4 Approx.

Measuring mode:

1) Voltage And its frequency from Potential Transformer. 2) Phase to Phase or Phase to Line Voltage.

Calculation methods:Generator rated Voltage: 11000V Rated Frequency: 50Hz V/F ratio: 11000/50= 220 220 is Base value, PU=1.

Running Parameters: V: 11470V, F: 50.11 V/F ratio: 11470/50.11=228.89 PU: 228.89/220=1.04 Sampling Time of relay:- 10msec at 50Hz.

5)GENERATOR UNDER EXCITATION OR LOSS OF EXCITATION Under excitation means that the excitation of synchronous generator is less than required for stable operation at that particular power Out Put. The excitation limit determines the steady state stability characteristic of generator. If the excitation is not sufficient to provide power demand then this stability limits exceeds. As a result generator speed will increase above the synchronous speed and operate as an induction Generator taking its reactive power needs from the System. Loss of excitation results in 1)

Heavy overloading of armature winding.

2) Induce eddy current in the rotor surface and rotor windings at a slip frequency resulting in a heavy thermal heating in rotor body. 3) 4)

Large voltage drop in transmission line, loss of system stability. Loss of magnetic coupling between stator & Rotor.

Loss of excitation may occur as a result of 1) Under excitation or loss of excitation can be result of short circuit or open circuit in the excitation system. 2) Mal operation of AVR.

Generator Reactive Power OutPut. The reactive power output of a generator can be expressed QT=3[Eq.Vt cosδ –vt2]=QF+

Xd

QN

xd

Eq & Vt are generator Internal & Terminal Voltage respectively. Power angle δ is the angle between Eq & Vt. This equation shows that reactive power output consist of 2 components. Qf:- Internally generated reactive power, which is determined by the internal voltage (field current) and the load angle δ. Qn:- supplied to the generator from the external network. The equation “QT=3[Eq.Vt cosδ –

vt2] can be rearrange as QT=3 Vt [Eq. cosδ –

vt] Xd When

(Eq.

cosδ –

vt)>0

,

xd

Xd

reactive power is flowing from generator to system.

Operating under lagging power factor. In this mode generator is said to be over exited. When

(Eq. cosδ –vt)=0,

total reactive power measured at the machine erminal

will be zero. Operating at Unity PF & delivering only active power to the system. Operation is this mode is limited by allowed armature current. When

(Eq.

cosδ –

vt)<0,

reactive power is flowing from the system into the

generator. Operating at leading PF, In this mode generator is Under Excited. Operation in this mode will increase the load angle δ. This will bring the generator close to its stability limits.

The maximum reactive power taken from the external network following a loss of excitation condition can be calculated as Qmax=

- vt2 Xd

The amount of leading reactive power Qm allowed to operate without being damage is usually determined from the manufacturing data. But in general it is taken to be 0.95 leading PF. Principle of Operation:Y Axis - X AADiamet X axis-R Offset xd/2 Displacement

Diameter -xd

1) The operation is based on OFFset Mho Relay. a. During the normal steady state operation, the impedance “Z” seen from the stator terminal lies in first quardrant (I) . of R-X plane.(X axis horizontal coordinate is resistance (R), Y axis- vertical coordinate reactance (X). b. Partial or loss of excitation causes a reactive power intake from the network to a generator and the reactance of the system viewed from generator terminal turns negative. This drop of reactance is being detected by measuring the impedance of the system. The impedence (Z) enters Quardrant IV. c. OFFSET:- this is usually set equal to Xd’/2, Xd’ –transient reactance of the machine. The sign value setermines the location of the circle regarding X axis-(R). Usually the sign is negative. d. Diameter: equals to the Generator synchronous Determines the size of impedance circle.

reactance

Xd.

e. Displacement:- center of circle from the reactance y Axis –(X). this setting is used to adjust the sencitivity of underExcitation. Calculation: i. Base Impedance Zn= power.

vt /P, 2

Vt=rated terminal voltage. P rated

Vt=11000V, P= 37500KVA. Zn(base)=3.226

Over current protection The main causes of over current are due to. 1) faults 2) overloads Faults:Fault is the term that uses to describe a problem with an electrical circuit that is not operating properly. The problem may be caused by physical damage to the system, faulty installation, faulty equipment, or any number of other factors. In most cases a very high current flows is associated with fault. When a fault condition is established many things begin to happen all at once— 1) The current flow instantly rises from the normal load. 2) The maximum amount of fault current that can be delivered to the circuit from the distribution system is called available fault current. 3) Due to Heavy fault current causes a huge Mechanical Stress over the Winding. 4) Magnitude of fault current is depend system impedance. 5) extreme current causes over heating, winding Insulation.

may Severe damage to the

Faults can be further classified as two types;_ Ground /Earth Fault.

Short circuit.

Ground /Earth Faults allows current to flow to ground using a pathway other than the grounded circuit conductor. Ground offers low impedance path. The low impedance allows the current in the circuit to instantly increase to tens of thousands of amperes.

Short Circuit The Short Circuit differ from ground faults they involve only the circuit conductors, and no current is escaping from the circuit. However, with short circuits, the load is byed, and the circuit conductors themselves represent the only impedance on the circuit. circuit will have a small enough impedance to produce a very high current

Over Load:- when the current flowing through the device is more than the rated current then the device is said to Over Loaded. Over Load Causes 1) Over loading may be due to mechanical problem like defective bearing , shaft misalignment. 2) Over Heating of Device, Increase in current, increases the I2R losses. 3) Temp rise above the insulation Class, may damage to the insulation of winding.

Three Phase Directional O/C Protection.(67) The directional over current systems are used for protecting distribution networks and subtransmission network and also applied for back up protection of the transmission system. Principle of Direction O/C can understood as below.

B

A 1

C 2

3

4

5

D 6

7

8

A Fa

Fb

Simple o/c relay operates on magnitude of fault current but can not sense the Direction of Fault. 1) Let us assume the occurrence of fault at Fa. Ideally fault should be isolated by CB 4 & 5. But if simple o/c relay were used then fault will be sense by CB 3,4,5 &6. And all will be tripped. Thus the desire zone is not protected. Desired zone protection can be achieved by Directional O/C relay. The table below show the tripping & restraining action Fault

Fa Fb

Direction of o/c relay at 5 fault power flow at bus C as seen from CB 5 Away from bus Trip C Towards Bus C Restrain

Direction of o/c relay at 6 fault power flow at bus C as seen from CB 6 Towards bus C Restrain Away from Bus Trip C

Therefore, whatever the fault current flow, 1) Relay must operate for forward fault. 2) Relay must restrain for reverse fault.

Three phase Non Directional O/C Protection. Instantaneous O/C (50) Inverse Time function (51). The Non Directional O/C relays are used for Device Protection. They can be further classified as 1) 2) 3) 4)

Instantaneous O/C Protection. Definite Time O/C Protection. Inverse Time O/C Protection. Inverse Definite Minimum Time (IDMT) Protection.

Instantaneous O/C Protection. Instantaneous means no intentional time delay. The operating time of Inst. Relay is of few milli Second. The operating characteristic of Inst. Definite Time O/C Protection. A definite time o/c can be adjusted to issue a trip output at a definite (adjustable) amount of time after pick-up. Thus it has a time setting and pick up adjustment. Inverse Time O/C Protection. Inverse Time O/C depends on pick-up value, more severe a fault, the faster it should be cleared to avoid damage to the generator. Inverse Definite Minimum Time (IDMT) Protection. Inverse Definite Minimum Time (IDMT) Protection is widely used. The characteristic is inverse in the initial part, & a definite minimum operating time as the current becomes ver high. The reason for operating time becoming definite minimum, at high values of current , in the electro mechanical flux saturated at high value of current. Relay operating torque is proportional to square of flux, due to saturation torque does not increase substantially. Therefore, operating time be inverse in nature through the operating range. Mathematical relationship between current & operating time for IDMT is given by.

top= 0.14 (TMS)

(PSM)0.02 - 1

TMS= time multiplier setting PSM= Plug Setting Multiplier (current setting).

Generator Minimum/Under Impedance Protection (21)

Over Current protection is not sufficient to protect the apparatus under fault condition. So with O/c protection Under Impedance protection is also recommended for higher capacity devices. Under Impedance protection is generally applicable as Backup protection of Generator. Impedance relays have much better discriminatory abilities relative to over-current relays (magnitude or directional). By this, we mean that impedance relays are better able to discriminate (to distinguish) between conditions for which they should operate and conditions for which they should not. To understand the fundamental advantage gained from an impedance relay, consider a 3-phase fault:

• voltage drops and • current drops. Suppose ΔV=0.5(Vnormal) and ΔI=2(Inormal). Before fault:

After fault:

V Vnormal = = Z normal . I I normal

V 0.5(Vnormal ) 1 Vnormal = = = Z fault I 2( I normal ) 4 I normal

From this, we can see that: Z fault =

1 Z normal but I fault = 2 I normal . 4

Therefore, proportionally, a larger change is seen in impedance than current, and so faults are easier to correctly detect when measuring impedance relative to measuring current.

X Zf=Fault Impedance Zf

Zn-Normal operation Non-operating zone R

Operating zone

Operating characteristic

Example: Consider the network of Fig. 1. Plot the impedance as seen by the impedance relay looking into the circuit for (a) normal load conditions, (b) 3-phase fault F1, (c) 3phase fault F2. The values given are impedance in per-unit.

0.02+j0.1

F2

0.02+j0.1

F1

1.0+j0.1

Relay Fig. 1 Solution: The per-phase circuit is shown in Fig. 2.

0.02+j0.1

I

0.02+j0.1 F2

F1 1.0+j0.1

V

Fig. 2 The desired impedance is Z =

V I

(a) Under normal load, Zn =

V = 1.04 + j 0.3 I

(1)

(b) For a fault at F1, Z F1 =

V = 0.04 + j 0.2 I

(c) For a fault at F2, ZF 2 =

V = 0.02 + j 0.1 I

Let’s plot these on the Z-plane: 0.4

X

0.3

Zn ●

0.2

ZF1 ●

0.1

● ZF2 R 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1

The faulted conditions are located relatively near the origin in the Z-plane, whereas the normal load conditions are located far to the right on the Z-plane. We can use this to our advantage in deg relays to discriminate between faulted conditions and normal load conditions.

Out of Step Synchronism

Protection(Pole

Slipping)

/

Loss

of

When angular displacement of the rotor exceeds the stability limit then rotor slips a pole pitch or we can say rotor flux slips with respect to stator flux. This condition is called pole slipping. Pole Slipping causes.

1) Severe system fault. 2) Generator operating under high load with a leading power factor, hence a relatively weak field. 3) Imbalance between Mechanical input & electrical output power. 4) Insufficient Electro Mechanical torque to keep rotor in synchronism with stator. 5) Faulty Governor. 6) Faulty AVR. 7) Long fault clearance time. Pole Slipping Phenomena:- Pole slipping does not occur very often when faults are cleared very fast. When pole slipping occurs due to this synchronising power will start flowing in reverse direction twice for every slip cycle. On drawing this synchronising power on the impedance plane the flow of it characterised by cyclic change in the load impedance and load impedance locus es between +R and –R quadrants because real power flows in reverse direction. When the load impedance is very reactive in nature then two systems are 180 degree out of phase, this instant is when drawn on the jx axis the point corresponding to this instant is called transition point. At this stage only reactive power flows and system voltage reached to zero at the electrical mid point of the two systems. Mid point is that point where pole slipping take place and its location can be determined from the apparent load impedance to the point where the locus crosses the jx axis. Three parameters magnitude, direction and rate of change of load impedance with respect to the generator terminals tell us about the pole slipping, that is it taking place. Need of Pole Slipping Protection:- High currents and torques can Loosen or causes wear off stator windings. Damage shaft and coupling. Stator and rotor overheating. Excitation system damage. Under such condition generator is subject to high vibration due to violent oscillation of torque & with vide variation of Current, Power, Power Factor. Therefore, it is necessary to isolate the generator from the Grid system. Under such condition The Impedance measured at generator terminals changes. The terminal voltage begin to decrease and current to increase. Since Z= V/I, resulting in decrease in Impedance. Differential protection

Differential protection is a strict selective Zone protection and is based on the current measuring principle at the either side of the object. Unbiased differential protection. This is the simplest arrangement of a balance current system in which two CT per phase are required to balance together. The fault setting required from the differential protection is determined by the value of the Neutral earthing resistor and also by the amount of winding to be protected. If

Generator Winding R x Y 1.0 B

If

R Stabilizing Resistance

Relay

Fig.- Differential protection If=(1-x) E/R, which must be equal to the primary fault setting of the differential protection. Thus, Is= (1-x)E/R & IR=E/R. Is= Generator Rated Current. E=Generator voltage. =>, x= (1-Is/I R). If Is/I R =10 With a resistor design to the rated current of the machine on a fault at machine terminal. Differential protection setting of 10% will protect 90% of the winding. And 10% of the winding is being unprotected. Biased / Percentage differential Protection. Biased differential protection has bias feature. The effect of biased feature is to reduce the impedance of relay operating coil for the through fault stability. The bias feature is obtained by circulating the through (external) fault current through an additional winding (restraining coil). Restraining coil exerts a

restraining forces on the relay. Normally no current flows in operating coil under through fault conditions. but there are some splii current due following reason: 1) Imperfect matching of CT. 2) Current imbalance due Tap changer. 3) Zero sequence current. 4) Inrush magnetizing current. This spill current will flow through the relay operating coil but will not cause a operation still relay bias setting is increase. If

Generator Winding

I

I

R

x I2

I1

Y

1.0 B If

R

I1-I2

Restraining /Stabilizing Coil Operating Coil

Fig.- Biased Differential protection Relay operating force Id (differential Current) = K(I1-I2)No. Relay Restraining force Ir (Stabilizing Current)= K(I1+I2)Nr. 2 Where No & Nr are no of turns in operating coil & restraining coil. Under normal condition operating forces = restraining forces. =>, (I1-I2) No= K(I1+I2)Nr. 2 =>, (I1-I2) =Nr/No (I1+I2) /2 Under normal condition differential current must be Id=0, in practical Id slightly deviate from zero due deviation in CT’s accuracies. The bias characteristic is determined by the ratio of Nr/No. the required value of stabilizing resistance is very low, thus giving a lower relay voltage than Unbiased relay.

The setting parameters are 1) Basic Setting ie. Minimum Id (differential current) required for tripping. a. Id= 5% of In 2) The Starting Ratio or the Slope. a. The Starting ratio is define as turning point T1 & T2. 3) Differential Over Current Protection Id>>.

Id /In Id>>

Trip zone T2 Restraining/ Safe zone

T1 Id Ib/In=1

Ib/In=3

The differential protection relay characteristic.

Ib/In (Stabilizing current)

Relay Operates Case 1) If Ib/In < T1 Id= Basic Setting. Case 2) if T1 T2. Id= Basic setting + (T1-T2)x Starting Ratio + (Ib-T2). The biased differential protection can protect 90% of winding. Further decrease in Id setting will leads to the Mal-operation of relay due deviation in CT’s accuracies. If the fault is near the Neutral then there is no enough voltage to drive the relay operating current. As shown in fig.

Vt=0%

Vt=100%

Therefore, additional protection scheme are used to protect 100% winding of generator/ Transformer.

100% Stator Earth Fault Protection (code-64) Stator earth fault occurs mainly due to Insulation Failure for stator winding. The insulation failure may be due aging effect, mechanical damage, etc. The faults may by: 1) Phase to earth faults. 2) Phase to Phase Faults. 3) Inter-turn Faults. The Protection schemes are 1) Third Harmonics analysis at neutral & Terminal. 2) Sub-Harmonics voltage injection method. In this section we discuss only the third Harmonics analysis at Neutral & terminal of the generator. As we all know that the output of generator is not a pure sinusoidal wave. It has harmonics voltage of multiple of three, like 3rd, 9th ,15th…. But 3rd harmonics voltage is predominant usually the largest of all these harmonics. Magnitude of third harmonics voltage depends up: 1) Location of fault. 2) Generator Loading (ie no load, full load). The 3rd harmonics voltage under normal condition is shown in fig. Generator winding

3rd har. Volt. Neutral 0%

100% Terminal

3rd harmonics voltage under normal condition, is higher at the neutral & terminal side. The value is zero at some point within the winding.

Ground fault occurs at generator neutral end as shown in fig. Generator winding

Vt= all 3rd harmonics voltage Neutral 0% Vn=0

100% Terminal

3rd harmonics voltage at the neutral decrease to zero & 3rd harmonics voltage at the terminal increases to equal the 3rd harmonics voltage produce by the generator.

Ground fault occurs at generator Terminal as shown in fig. Generator winding

Neutral 0% Vt=0 100% Terminal Vn= all 3rd harmonics voltage

3rd harmonics voltage at the terminal decrease to zero & 3rd harmonics voltage at the neutral increases equal to the 3rd harmonics voltage produce by the generator. These 3rd harmonics voltage is being detected by voltage relay tuned to 3rd harmonics voltage (150Hz).

Rotor Earth Fault Protection (64R). The

excitation field is isolated during normal operating condition. Due to vibration, over current & choked cooling medium, the field winding can be exposed to mechanical & thermal Stress. This may result in the break down of insulation between the field winding. The rotor winding fault causes severe magnetic imbalance and heavy rotor vibrations leads to severe damage.

There are three types methods to detect rotor earth fault 1) Potentiometer method. 2) AC injection method.

3) DC injection method.

The method used in our 30MW power plant is AC injection method. The circuit diagram as shown in fig.

Stator Winding

Main Field Winding

Full Wave Rectifier

Excitation from AVR

Brush Less Excitation

Rotor Shaft

Rv

Rv

UH Voltage source , 0.5Hz, +/-24V

RE

CE

Rm

Um

This is an Insulation resistance measurement system used for Brush / Brush less Generator. Uh- Low frequency alternating voltage source (0.5Hz, +/-24V). the voltage source is connected to Main Excitor winding via Slip Ring & to the Rotor Earth. The frequency voltage is used to avoid malfunction due to field to earth capacitance (CE). Where RE & CE being the Rotor Insulation Resistance & Capacitance. RV = Current limiting resistance. Rm= Shunt Resistor.

Operating Principle: The low frequency voltage is fed via current limiting resistance Rv to both end of the field winding. The Earth current is measured via shunt resistance Rm. The insulation measurement is based on measurement of shunt resistor voltage Um of two consecutive half cycle Positive & Negative. Um=IxRm.

Negative Phase Sequence Protection (Code 46 ) Under balance condition all three phases are equal in magnitude and displaced by electrically 120°. The ampere turns (Flux) produce by stator current rotates synchronously with the rotor. Thus the relative speed is zero between the rotor & stator flux. Thus no eddy current are induced in rotor. Unbalanced loading on Generator causes a negative phase sequence component in Stator current. The Ampere turns (flux) due to negative phase sequence rotates opposite to the rotor. Therefore, the relative speed of NPS flux with respect to rotor is twice the synchronous speed. This double frequency eddy current induced in rotor causes excessive heating.

Rate of change of Frequency Df/Dt Power system frequency drops when power supply in the system becomes insufficient due to loss of generation or due to over loading. Due to load fluctuation electric power changes. Generator’s governor system simultaneously change the P (mechanical)i/p . Thus P mechanical & P electrical change in time, altering frequency f, and its rate of change of df/dt. Lower frequency indicates power deficiency; its rate of change of frequency is an instantaneous indicator of power deficiency.

Operating Principle of Differential Protection relay. The operating principle employed by transformer differential protection is the Merz-Price circulating current system as shown below. Under normal conditions I1and I2 are equal and

opposite such that the resultant current through the relay is zero. An internal fault produces an unbalance or 'spill' current that is detected by the relay, leading to operation.

Design Objectives An ideal scheme is required to be:

1. Extremely stable under through fault conditions. 2. Very fast to operate for an internal fault.

Factor Affecting Protection.

the

Performance

of

Differential

A number of factors have to be taken into in deg a scheme to meet these objectives. These include: 1. 2. 3. 4. 5.

The matching of CT ratios Current imbalance produced by tap changing Dealing with zero sequence currents Phase shift through the transformer Magnetising inrush current

The Matching of CT Ratios The CTs used for the Protection Scheme will normally be selected from a range of current transformers with standard ratios such as 1600/1, 1000/5, 200/1 etc. This could mean that the currents fed into the relay from the two sides of the power transformer may not balance perfectly. Any imbalance must be compensated for and methods used include the application of biased relays (see below) and/or the use of the interposing CTs (see below).

Current Imbalance Produced by Tap Changing A transformer equipped with an on-load tap changer (OLTC) will by definition experience a change in voltage ratio as it moves over its tapping range. This in turn changes the ratio of primary to secondary current and produces out-of-balance (or spill) current in the relay. As the transformer taps further from the balance position, so the magnitude of the spill current increases. To make the situation worse, as the load on the transformer increases the magnitude of the spill current increases yet again. And finally through faults could produce

spill currents that exceed the setting of the relay. However, none of these conditions is 'in zone' and therefore the protection must remain stable ie. it must not operate. Biased relays provide the solution (see below).

Dealing with Zero Sequence Currents Earth faults down stream of the transformer may give rise to zero sequence current, depending upon winding connections and earthing arrangements. Since zero sequence current does not through a transformer, it will be seen on one side only producing spill current and possible relay operation for an out-of-zone fault. To prevent such occurrence, zero sequence current must be eliminated from the differential scheme. This is achieved by using delta connections on the secondary side of any CTs that are associated with main transformer windings connected in star. Where CT secondaries are connected in star on one side of a transformer and delta on the other, allowance must be made for the fact that the secondary currents outside the delta will only be 1/√3 of the star equivalent.

Phase Shift Through the Transformer Having eliminated the problem of zero sequence currents (see above) through faults will still produce positive and negative sequence currents that will be seen by the protection CTs. These currents may experience a phase shift as they through the transformer depending upon the transformer vector group. CT secondary connections must compensate to avoid imbalance and a possible mal-operation.

Magnetising Inrush Current When a transformer is first energised, magnetising inrush has the effect of producing a high magnitude current for a short period of time. This will be seen by the supply side CTs only and could be interpreted as an internal fault. Precautions must therefore be taken to prevent a protection operation. Solutions include building a time delay feature into the relay and the use of harmonic restraint driven, typically, by the high level of second harmonic associated with inrush current.

Biased Relays The use of a bias feature within a differential relay permits low settings and fast operating times even when a transformer is fitted with an on-load tapchanger (see above). The effect of the bias is to progressively increase the amount of spill current required for operation as the magnitude of through current increases. Biased relays are given a specific characteristic by the manufacturer.

Interposing CTs The main function of an interposing CT is to balance the currents supplied to the relay where there would otherwise be an imbalance due to the ratios of the main CTs. Interposing CTs are equipped with a wide range of taps that can be selected by the to achieve the balance required.

As the name suggests, an interposing CT is installed between the secondary winding of the main CT and the relay. They can be used on the primary side or secondary side of the power transformer being protected, or both. Interposing CTs also provide a convenient method of establishing a delta connection for the elimination of zero sequence currents where this is necessary.

Over Load Protection. (for motor protection) Over current protection should not be confused with over load protection, which is related to the thermal capability of device or apparatus. Principle of the thermal model application. The basic formula in calculating the temperature rise in degree Celsius above the ambient temperature is presented as below. ∆t=[px(I/In)2x∆θn]x (1-e-t/TC1) + [(1-p)x(I/In)2x∆θn)x(1-e-t/TC2) ∆t = temp. rise. P = weight factor for the short time constant I = measured current In = Rated current ∆θn= temp rise with the rated current ie. When I=In. TC1 = short heating /Cooling time constant TC2 long heating / cooling time constant.