CONTENTS

Chapter No. Topic Page No.

Chapter 1

1.0

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

BASIC ASPECTS OF PROTECTION

Principles of Relays

Some Terms Associated with Protective

Relaying

Functions of Protective Relaying

The Requirements of Protective Relaying

Classification of Relays

Operating Principles of different types of

Relays

Testing and Maintenance of Protective Relays

Test Equipment

Static Relying Concepts

Chapter 2

2.1

2.2

PROTECTIVE RELAYS

Introduction

Characteristic Curve

Chapter 3

3.1

3.2

3.3

3.4

3.5

3.6

3.7

MOTOR PROTECTION

Overload Protection

Single Phasing Protection or Unbalance

Protection

Short Circuit Protection

Stalling Protection (Lock Rotor Protection)

Differential Protection

Earth Protection

Undervoltage Protection

Chapter 4

4.1

4.2

4.3

4.4

4.5

4.6

4.7

4.8

4.9

4.10

TRANSFORMER PROTECTIONS

Transformer Protections

Protection against Internal Faults

Principles of Protection System

Gas Detection

Over Heating Protection

Over Current & Earth Leakage Protection

Percentage Bias Differential Protection

Over Voltage Protection

Over Fluxing Protection

Over Differential Protection

CHAPTER 5

5.1

5.2

5.3

5.4

5.5

5.6

5.7

5.8

5.9

5.10

5.11

5.12

5.13

5.14

GENERATOR PROTECTION

Introduction

Stator Earth Faults

Rotor Earth Fault Protection

Generator Interturn Fault Protection

Generator Negative Phase Sequence Current

Protection

Generator Loss of Excitation Protection

Generator Minimum Impedance Protection

Generator Differential Protection

Generator Overall Differential Protection

Generator Reverse Power Protection

Generator Over Frequency Protection

Generator Under Frequency protection

Generator Thermal Overload Protection

Generator Overvoltage Protection

Chapter 6

6.1

6.2

6.3

6.4

6.5

BUS ZONE-PROTECTION AND LOCAL

BREAKER

BACKUP PROTECTION

Introduction

Bus Bar Protection – Requirements

Types of Busbar Protection

Low Impedance Scheme (Biased)

Local Breaker Back-up (LBB) Protection

Chapter 7

7.1

7.2

7.3

DISTRIBUTION FEEDER PROTECTION

Introduction

Unit Protection

IDMT Overcurrent & Earth Fault Protection

Chapter 8

8.1

8.2

8.3

8.4

8.5

8.6

LINE PROTECTION (DISTANCE SCHEMES)

Introduction

Measuring Characteristics

Zones of Protection

Phase Sequence Comparator for MHO

Characteristic

Additional features of Distance Relays

Carrier Aided Schemes

Chapter 9

9.1

9.2

9.3

CURRENT AND VOLTAGE TRANSFORMER

Introduction

Current Transformers

Voltages Transformers

Chapter 10

10.1

10.2

10.3

DIGITAL RELAYING

Introduction

PC Based Schemes for Testing Protective Relays

Testing of a Distance Relay

CHAPTER – 1

BASIC ASPECTS OF PROTECTION

1.0 Principles of Relays

Every electrical equipment is designed to work under specified normal

conditions. In case of short circuits, earth faults etc., an excessive current

will flow through the windings of the connected equipment and cause

abnormal temperature rise, which will damage the winding. In a power

station, non-availability of an auxiliary, at times, may cause total shut

down of the unit, which will result in heavy loss of revenue.

So, in modern power system, to minimise damage to equipment two

alternatives are open to the designer, one is to design the system so that

the faults cannot occur and other is to accept the possibility of faults and

take steps to guard against the effect f these faults. Although it is possible

to eliminate faults to a larger degree, by careful system design, careful

insulation coordination, efficient operation and maintenance, it is obviously

not possible to ensure cent percent reliability and therefore possibility of

faults must be accepted; and the equipment are to be protected against

the faults. To protect the equipment, it is necessary to detect the fault

condition, so that the equipment can be isolated from the fault without any

damage. This function is performed by a relay. In other words, protective

relays are devices that detect abnormal conditions in electrical circuits by

constantly measuring the electrical quantities, which are different under

normal and faulty conditions. The basic quantities which may change

during faulty conditions are voltage, current, frequency, phase angle etc.

Having detected the fault relay operates to complete the trip circuit which

results in the opening of the circuit breaker thereby isolating the

equipment from the fault. The basic relay circuit can be seen in Fig. No. 1.1

FIG. 1.1

1.1 Some Terms Associated with Protective Relaying

Circuit Breaker: It is an On-load switch, used to make or break an

electrical circuit when it is carrying current.

Current Transformer: These are used for measuring protection purpose

since it is not possible to measure very high currents directly, it will be

stepped down means of a current transformer to about 5A or 1A and the

secondary current will be measured and monitored.

Voltage Transformer: These are also used for measuring purpose and

protective relaying purpose. Since it is not practicable to measure and

monitor high and extra high voltages they are stepped down to 110V and

the secondary voltage is measured and monitored.

Relay time: It is the interval between the occurrence of the fault and

closure of relay contact.

Pick Up: The operation of relay is called relay pick up. Pick up value or the

level is the value of operating quantity at which the relay operates.

Back up Protection: A protective system intended to supplement the

main protection in case the latter should be ineffective, or to deal with

faults in those parts of the power system that are not readily included in

the operating zones of the main protection.

Protected Zone: It is the portion of a power system protected by a given

protective system.

Protective Gear: These are the apparatus, including protective relays,

current/voltage transformers and ancillary equipment for use in a

protective system.

Protective Relay: A relay is designed to initiate disconnection of a part of

an electrical installation or to operate a warning signal, in case of a fault or

other abnormal condition in the installation. A protective r3elay may

include more than one unit electrical relay and accessories.

Rating: It is the nominal value of an energizing quantity which appears in

the designation of a relay. The nominal value usually corresponds to the

CT & VT secondary rating.

Resetting Value: It is value of the characteristic quantity at which the

relay returns to its initial position.

Unrestricted Protection: It is a protection system which has no clearly

defined zone of operation and which achieves selective operation only by

time grading.

Basic Symbols: The equipments they represent are as given below:

Sr.

No.

Symbol Equipment Function

1. Circuit

Breaker

Switching during normal and

abnormal conditions, interrupt the

fault currents.

2. Isolator Disconnecting a part of the system

from live parts under no lad

conditions.

3. Earth switch Discharging the voltage on the

lines to the earth after

disconnection.

4. Lighting

Arrestor

Diverting the high voltage surges

to earth.

5. Current

Transformer

Stepping down the current for

measurement, protection, and

control.

6. Voltage

Transformer

Stopping down the voltage for the

purpose of protection,

measurement and control.

1.2 Functions of protective Relaying

To sound an alarm, so that the operator may take some corrective action

and/ or to close the trip circuit of circuit breaker so as to disconnect a

component during an abnormal fault condition such as overload, under

voltage, temperature rise etc.

To disconnect the faulty parts as quickly as possible so as to minimise the

damage to the faulty art. Ex: If a generator is disconnected immediately

after a winding fault only a few coils need replacement. If the fault is

sustained, it may be beyond repairable condition.

To localize the effect of fault by disconnecting the faulty part from the

healthy part, causing least disturbance to the healthy system.

To disconnect the faulty part as quickly as possible to improve the system

stability and service continuity.

1.3 The requirements of protective relaying

Speed: Protective relaying should disconnect a faulty element as quickly

as possible, in order to improve power system stability, decrease the

amount of damage and to increase the possibility of development of one

type of fault into other type. Modern high speed protective relaying has an

operating time of about 1 cycle.

Selectivity: It is the ability of the protective system to determine the

point at which the fault occurred and select the nearest of the circuit

breakers, tripping of which leads to clearing of fault with minimum or no

damage to the system.

Sensitivity: It is capability of the relaying to operate reliably under the

actual minimum fault condition. It is desirable to have the protection as

sensitive as possible in order that it shall operate for low value of actuating

quantity.

Reliability: Protective relaying should function correctly at all times under

any kind of fault and abnormal conditions of the power system for which it

has been designed. It should also not operate on healthy conditions of

system.

Simplicity: The relay should be as simple in construction as possible. As a

rule, the simple the protective scheme, less the number of relays, and

contacts it contains, the greater will be the reliability.

Economy: Cost of the protective system will increase directly with the

degree of protection required. Depending on the situation a designer

should strike a balance between with the degree of protection required

and economy.

1.4 Classification of Relays

1.4.1 Depending upon their principle of operation they are classified as:

Electromagnetic attraction type relays: These relays operate by the

virtue of a plunger being drawn into a solenoid or an armature being

attracted towards the poles of an electromagnet.

Induction type Relays: In his type of relay, a metal disc or cup is allowed

to rotate or move between two electro-magnets. The fields produced by

the two magnets are displaced in space and phase. The torque is

developed by interaction of the flux of one of the magnets and the eddy

current induced into the disc/up by the other.

Thermal Relay: They operate due to the action of heat generated by the

passage of current through the relay element. The strip consists of two

metals having different coefficients of expansions and firmly fixed together

throughout the length so that different rates of thermal expansion of two

layers of metal cause the strip to bend when current is passed through it.

Static Relays: It employs discrete electronic components like diodes,

transistors, zenners, resistors/capacitors or Integrated circuits and use

electronic measuring circuits like level detectors, comparators, integraters

etc. to obtain the required operating characteristics.

Moving Coil Relays: In this relay a coil is free to rotate in magnetic field

of a permanent magnet. The actuating current flows through the

FIG. 1.3

coil. The torque is produced by the interaction between the field of the

permanent magnet and the field of the coil.

1.4.2 Relays can be classified depending upon their application also.

Over voltage, over current and over over power relays, in which operation

takes place when the voltage, current or power rises above a specified

value.

Under voltage, under current under frequencies low power relays, in which

operation takes place when the voltage, current frequency or power fall

below a specified value.

Directional or reverse power relays: In which operation occurs when the

direction of the applied power changes.

Distance Relays: In this type, the relay operates when the ratio of the

voltage and current change beyond a specified limit.

Differential Relays: Operation takes place at some specific phase or

magnitude difference between two or more electrical quantities.

1.4.3 Relays can also be classified according to their time of operation

Instantaneous Relay: In which operation takes place after negligibly

small interval of time from the incidence of the current or other quantity

causing operation.

Definite time lag Relay: This operates after a set time lag, during which

the threshold quantity of the parameter is maintained.

Inverse time lag Relay: This operates after a set time Lab, during which

the operating quantity of the parameter is maintained above its operating

threshold.

1.5 Operating Principles of different types of Relays:

1.5.1 Introduction over current and earth fault relays:

These are quite commonly used relays. Schematic diagram of induction

disc type relay is shown in Fig. No. 1.2

The output of the current transformer is fed to a winding (1) on the center

limb of the E-shaped core, the second winding (2) on the limb

FIG. 1.4

FIG. 1.5

is connected to two windings on the poles of the E and U shaped cores.

The magnetic flux across he air gap induce currents in the disc, which in

conjunction with the flux produced by the lower magnet, produces a

rotational torque. A magnet (3), is used to control the speed of the disc.

The time of operation of the relay varies inversely with the current fed into

it by the current transformer of the protected circuit. The permanent

magnet used for breaking has a tendency to attract iron filings, which can

prevent operation. So care has to be taken while manufacturing this type

of relays. Time-current characteristics induction type relays has been given

in Fig. 1.3.

1.5.2 Balanced Beam Relays:

It consists of a horizontal beam pivoted centrally, with one armature

attached to either side. There are two coils one on each side. The current

in one coil gives operating torque. The beam is given a slight mechanical

bias by means of a spring so that under normal conditions trip contacts will

not make and the beam remains in horizontal position. When the operating

torque increases then the beam tilts and closes the trip contacts. In

current balance system both coils are energised by current derived from

CT’s. In impedance relays, one coil is energized by current and other by

voltage. In these relays the force is proportional to the square of the

current, so it is very difficult to design the relay. This type of relay is fast

and instantaneous. In modern relays electromagnets are used in place of

coils (See Fig. 1.4.).

1.5.3 Permanent – Magnet Moving – Coil Relays:

There are two general types of moving coil relays. One type is similar to

that of a moving coil indicating instrument, employing a coil rotating

between the poles of a permanent magnet. The other is, employing a coil

moving at right angles to the plane of the poles of a permanent magnet.

Only direct current measurement is possible with both the types.

FIG. 1.6

FIG. 1.7

The action of a rotating coil type is shown in the Fig. 1.5. A light

rectangular coil is pivoted so that its sides lie in the gap between the two

poles of a permanent magnet and a soft iron core. The passage of current

through the coil produces a deflecting torque by the reaction between the

permanent magnetic field and the field of the coil (See Fig. 1.5)

The moving contact is carried on an arm which is attached to the moving

coil assembly. A phosper bronze spiral spring provides the resetting

torque. Increasing the contact gap and thus increasing the tension of the

spring permits variation in the quantity required to close the contacts.

Time current characteristic of a typical moving coil permanent magnetic

relays is shown in Fig. 1.6.

1.5.4 Attracted armature relays:

It is required to clear the faults in power system as early as possible.

Hence, high-speed relay operation is essential. Attracted armature relays

heave a coil or an electromagnet energised by a coil. The coil is energised

by the operating quantity which may be proportional to circuit current or

voltage. A plunger or a rotating vane is subjected to the action of magnetic

field produced by the operating quantity. It is basically single actuating

quantity relay.

Attracted armature relays respond to both AC and DC quantities. They are

very fast in operation. Their operating time will not vary much with the

amount of current. Operating time of the relay is as low as 10-15 m

seconds and resetting time is as low as 30 m sec can be obtained in these

relays. These relays are non-directional and are simple type of relays.

Examples of attracted armature type relays are given in Fig. 1.7.

1.5.5 Time Lag Relays:

These are commonly used in protection schemes as a means of time

discrimination. They are also frequently used in control, delayed auto-

reclosing and alarm scheme to allow time for the required sequence of

operations to take place, and to measure the duration of the initial

condition to ensure that it is not merely transient.

Various methods are used to obtain a time lag between the initiation of the

relay and the operation of its contact mechanism. These includes gearing,

permanent magnet damping, friction, thermal means or R.C. circuits. In

some cases the time lag in operation of the contacts is achieved by a

separate mechanism released by a voltage operated elements. The

release mechanism may be an attracted armature or solenoid and plunger.

The operating time of such relay is independent of the voltage applied to

the relay coil. One of the simplest forms of time lag relay is provided by a

mercury switch in which the flow of mercury is impeded by a constriction

in the mercury bulb. The switch is tilted by a simple attracted armature

mechanism. The time setting of such a relay is fixed by the design of the

tube. Another method of obtaining short time delays is to delay operation

of a normally instantaneous relay by means of a device which delays the

build up or decay of the flux in the operating magnet. The device consists

of a copper ring (slug) around the magnet and can produce delay on

pickup as well as delay on reset.

1.6 Testing and Maintenance of Protective Relays:

Unlike other equipment, the protective relays remain without any

operation until a fault develops. However, for a reliable service and to

ensure that the relay is always vigilant, proper maintenance is a must.

Lack of proper maintenance may lead to failure to operate.

It is possible for dirt and dust created by operating conditions in the plant

to get accumulated around the moving parts of the relay and prevent it

from operating. To avoid this, relays are to be cleaned periodically.

In general, overload relays sense over load by means f thermal element.

Loose electrical connections can cause extra heat and may result in false

operation of the relay. To avoid this, all the relay connections are to be

tightened every now and then.

To confirm that the relay operation at the particular setting under

particular conditions for which the relay is meant for operating, we should

perform number of tests on the relays. Quality control is given foremost

consideration in manufacturing of relay. Tests can be grouped into

following five classes:

1. Acceptance test

2. Commissioning test

3. Maintenance tests

4. Repair tests

5. Manufacturers tests

1.6.1 Acceptance test

Acceptance tests are generally performed in presence of the customer in

the laboratory or by the customer himself. These tests fall into two

categories:

1. Type tests such as High frequency disturbance, Impulse voltage test,

Fast transient test etc. on new relays. These tests are carried out to

prove the design and are not recommended for normal production

relays.

2. Routine Tests like operating value check, operating characteristic on

Relays which were used earlier and of proven design, requiring only

minimum necessary checks.

After receiving the relays package, it should be visually examined for the

damage in the transit. The following precautions are to be taken while

removing the relay –

Care to be taken not to bend the light parts

Avoid handling contact surface

Operating movement (disc, armature etc.) is to be checked for free

movement after removing the packing pieces.

Do not take steel screw drivers near the permanent magnet.

1.6.2 Commissioning Tests:

These are the field tests to prove the performance of the relay circuit in

actual service. These are repeated till correct operations are obtained.

These are performed by simulated tests with the secondary circuits

energised from a portable test source; or simulated tests using primary

load current or operating tests with primary energised at reduced voltage.

The following steps are involved in commissioning tests.

Checking wiring on the basis of the circuit diagram

Checking C.T. polarity connections

Measuring insulation resistance of circuits.

Checking C.T. Ratios

Checking P.T. ratio, polarity and phasing

Conducting secondary injection test on relays.

Conducting primary injection test

Checking tripping and alarm circuits.

Stability check for balanced protections like differential/REF.

1.6.3 Maintenance Tests

Maintenance tests are done in field periodically. The performance of a

relay is ensured by better maintenance. Basic requirements of sensitivity,

selectivity, reliability and stability can be satisfied only if the maintenance

is proper.

The relay does not deteriorate by normal use; but other adverse conditions

cause the deterioration. Continuous vibrations can damage the pivots or

beatings. Insulation strength is reduced because of absorption of moisture;

polluted atmosphere affects the relay contacts, rotating systems etc.,

Relays room, therefore, be maintained dust proof. Insects may cause mal-

operation of the relay. Relay maintenance generally consists of:

a) Inspection of contacts

b) Foreign matter removal

c) Checking adjustments

d) Checking of breaker operation by manual contact

closing of relays.

e) Cleaning of cover etc.

1.6.4 Maintenance Schedule:

1. Continuous Supervision: Trip circuit supervision, pilot supervision,

relay, auxiliary voltage supervision, Battery supervision, CT circuit

supervision.

2. Relay flags are to be checked and resetted in every shift.

3. Carrier current protection testing is to be carried out once in a week.

4. Six monthly inspections: Tripping tests, insulation resistance tests, etc.

Secondary injection tests are to be carried out at least once in a year.

The following tests are to be performed during routine maintenance:

Inspection: Before the relay cover is removed, a visual check of he cover

is necessary. Excessive dust, dirt, metallic material deposited on the cover

should be removed. Removing such material will prevent it from entering

the relay when the cover is removed. Fogging of the cover glass should be

noted and removed when the cover has been removed. Such fogging is

due to volatile material being driven out of coils and insulating materials.

However, if the fogging is excessive, cause is to be investigated. Since

most of the relays are designed to operate at 40oC, a check of the ambient

temperature is advisable. The voltage and current carried by the relay are

to be checked with that of the name plate details.

1.6.5 Mechanical adjustments and Inspection:

The relay connections are to be tight, otherwise it may cause overheating

at the connections. It will cause relay vibrations also. All gaskets should be

free from foreign matter. If any foreign matter is found gaskets are to be

checked and replaced if required.

Contact gaps and pressure are to be measured and compared with the

previous readings. Large variation in these measurements will indicate

excessive wear, in which case worn contacts are to be replaced. Contacts

alignment is to be checked for proper operation.

1.6.6 Electrical Tests and Adjustments

Contact function: Manually close or open the contacts and observe that

they perform their required function.

Pick up: Gradually apply actuating quantity (current or voltage) to see

that pickup is within limits.

Drop out or reset: Reduce the actuating quantity (current or voltage)

until the relay drops out or fully resets. This test will indicate excess

friction.

Repair tests involve recalibration, and are performed after major repairs.

Manufacturers tests include development tests, type and routine tests.

1.7 Test Equipment

1.7.1 Primary current injection test sets:

Generally protective gear is fed from a current transformer on the

equipments to be protected and primary current injection testing checks

all parts of the protection system by injecting the test current through the

primary circuit. The primary injection tests can be carried out by means of

primary injection test sets. The sets are comprising current supply unit,

control unit and other accessories. The test set can give variable output

current. The output current can be varied by means of built-in auto

transformer. The primary injection test set is connected to AC single phase

supply. The output is connected to primary circuit of CT. the primary

current of CT can be varied by means of the test set. By using this test one

can find at what value of current the relay is picking up and dropping out.

1.7.2 Secondary current injection test set:

It checks the operation of the protective gear but does not check the

overall system including the current transformer. Since it is a rare

FIG. 1.8

occasion for a fault to occur in CT, the secondary test is sufficient for most

routine maintenance. The primary test is essential when commissioning a

new installation, as it checks the entire system. A simple test circuit is

given in Fig. 1.8.

1.7.3 Test Benches:

Test benches comprise calibrated variable current and voltage supplies

and timing devices. These benches can be conveniently used for testing

relays and obtaining their characteristics.

1.8 Static Relaying Concepts

1.8.1 Introduction

Static Relay is a relay in which the comparison or measurement of

electrical quantities is done by stationary network which gives a tripping

signal when the threshold value is crossed. In simple language static relay

is one in which there are no moving parts except in the output device. The

static relay includes electronic devices, the output circuits of which may be

electric, semiconductor or even electromagnetic. But the output device

does not perform relay measurement, it is essentially a tripping device.

Static relay employs electronic circuits for the purpose of relaying. The

entity voltage, current etc. is rectified and measured. When the output

device is triggered, the current flows in the trip circuit of the circuit

breaker.

With the inventions of semiconductors devices like diodes, transistors,

thyristors, zener diodes etc., there has been a tremendous leap in the field

of static relays. The development of integrated circuits has made an

impact in static relays. The static relays and static protection has grown

into a special branch.

1.8.2 Advantages of Static Relays:

The static relays compared to the electromagnetic relays have many

advantages and a few limitations.

1.8.3 Low Power Consumption

Static relays provide less burden on CTs and PTs as compared to

conventional relays. In other words, the power consumption in the

measuring circuits of static relays is generally much lower than that for the

electromechanical versions. The consumption of one milli-VA is quite

common in static over current relay whereas as equivalent

electromechanical relay can have consumption of about 2-3 VA. Reduced

consumption has the following merits.

a) CTs and PTs of less ratings are sufficient

b) The accuracy of CTs and PTs are increased

c) Air gaped CTs can be used

d) Problems arising out of CT saturation are avoided

e) Overall reduction in cost

1.8.4 Operating time

The static relays do not have moving parts in their measuring circuits,

hence relay times of low values can be achieved. Such low relay times are

impossible with conventional electromagnetic relays.

By using special circuits the resetting times and the overshoot time can be

improved and also high value of drop off to pick up ratio can also be

achieved.

1.8.5 Compact

Static relays are compact. The use of integrated circuit have further

reduced their size. Complex protection schemes may be obtained by using

logic circuits or matrix. Static relays can be designed with good repeat

accuracies. Number of characteristics can be obtained in a single

execution, unlike in case of their Electro-mechanical counter parts.

Most of the components in static relays including the auxiliary relays in the

output stage are relatively immune to vibrations and shocks. The risk of

unwanted tripping is therefore less with static relays as compared to

electromagnetic relays. So, these can be applied in earthquake prone

areas, ships, vehicles, aeroplanes etc.

1.8.6 Transducers

Several non-electrical quantities can be converted into electrical quantities

and then fed to static relays. Amplifiers are used wherever necessary.

1.8.7 Limitations

Auxiliary voltage requirement: This disadvantage is not of any

importance as auxiliary voltage can be obtained from station battery

supply and conveniently stepped down to suit load requirements.

Static relays are sensitive to voltage spikes or voltage transients. Special

measures are taken to overcome this difficulty. These include use of surge

supressors and filter circuits in relays, use of screened cables in input

circuits, use of galvanically isolated auxiliary power supplies like d.c./d.c.

converters, use of isolating transformers with grounded screens for

C.T./P.T. input circuits etc.

1.8.8 Temperature Dependence of Static Relays

The characteristic of semiconductors are influenced by ambient

temperatures. For example, the amplification factor o a transistor, the

forward voltage drop of a diode etc., changes with temperature variation.

This was a serious limitation of static relays in the beginning. Accurate

measurement of relay should not be affected by temperature variation.

Relay should be accurate over a wide range of temperature.

(-20oC to +50oC) this difficulty is overcome by

a) Individual components in circuits are used in such a way that change in

characteristic of component does not affect the characteristic of the

complete relay.

b) Temperature compensation is provided by thermistor circuits. Extra

precaution for quality control of the components has to be taken. As

the failure rate is highest in early period of components life, artificial

ageing of the components is normally done by heat soaking.

FIG. 1.9

FIG. 1.10

1.8.9 Level Detectors

A relay operates when the measured quantity changes, either from its

normal value or in relation to another quantity. The operating quantity in

most protective relays is the current entering the protected circuit. The

relay may operate on current level against a standard bias or restrain, or it

may compare the current with another quantity of he circuit such as the

bus voltage or the current leaving the protected circuit (Fig. 1.9).

In a simple electromagnetic relay used as level detector, gravity or a

spring can provide the fixed bias or reference quantity, opposing the force

produced by the operating current in electromagnet. In static relays the

equivalent is a D.C. voltage bias.

E.g. In the semiconductor circuit (See Fig. 1.10) the transistor is reverse

biased in normal conditions. No current flows through the relay coil under

fault conditions capacitor will be charged to +ve potential at the base side.

If this potential exceeds that of the emitter, the B-E junction will be forward

biased and transistor will conduct there by tripping the relay. Thus the

comparison is made against the D.C. fixed bias.

1.8.10Comparators

In order to detect a fault or abnormal conditions of he power system,

electrical quantities or a group of electric quantities are compared in

magnitude or phase angle and the relay operates in response to an

abnormal relation of these quantities. The quantities to be compared are

fed into a comparators as two or more inputs; in complex relays each input

is the vectorial sum or difference of two currents or voltages of the

protected circuit, which may be shifted in phase or changed in magnitude

before being compared.

1.8.11Types of comparators;

Basically there are two types of comparators, viz.

FIG. 1.11

FIG. 1.12

FIG. 1.13

FIG. 1.14

a) Amplitude comparators, and

b) Phase comparator

The amplitude comparator compares the magnitudes of two inputs by

rectifying them and opposing them. If the inputs are A and B, the output of

the comparator is A-B and this is positive if A is greater than B i.e. if the

ratio of A/B is greater than one. Theoretically, the comparison should be

purely scalar, i.e. the phase relation of the inputs should have no effect on

the output, but this is usually so if at least one input is completely

smoothened as well as rectified.

The phase comparator achieves a similar operation with phase angle; its

output is positive if arg A-arg B is positive i.e. if arg A/B is less than λ

where λ is the angle determining the shape of the characteristic; λ = 90

for a circular characteristic.

Both types of comparators can be arranged either for direct comparison

(instantaneous) or to integrate their output over each half cycle.

Amplitude Comparators: Fig.1.11 shows how two currents can be

compared in magnitude only, using rectifiers and, in fig. 1.16 two voltages

are compared. In current comparator, the rectifiers providing a limiting

action so that the relay can be made more sensitive, the voltage across

the rectifier bridge remains substantially constant and hence the rectifiers

and the sensitive relay are protected at high currents. In voltage

comparator, the increase of resistance at low voltage makes the relay less

sensitive at low voltage and the rectifiers are not protected at high

currents.

1.8.12Circulating Current Comparator

Operation: Normally the restraining current flow in the winding of the

polarized relay in the blocking direction. If the restraining current is small

and operating current is zero the flow of resultant current will be as shown

in Fig. 1.12.

FIG. 1.15

FIG. 1.16

The voltage across the restraining coil is –V, across the relay serves as a

bias in the forward direction of bridge 1. if the restraining current I r is

further increased, the voltage drop the relay will rise to a value V t, the

threshold voltage of bridge 1 and I will then conduct, then the current

paths will be shown in Fig. 1.13. The current through the relay consists of

fairly flat topped half waves as shown in Fig. 1.14.

The reverse is true if Io flows alone: The voltage drop across relay will

now be V and this will bias the restraint rectifier in its forward direction.

When the voltage drop across the relay attains a value Vt, corresponding

to the threshold voltage of two rectifiers in the series, the surplus current

from bridge 1 is spilled through bridge 2. This corresponds to the case of io

is greater than ir in the Fig. 1.14.

When both bridges are energised simultaneously the relay is responsive to

small differences between io and ir without requiring a sensitive output

relay. The composite characteristic (ideal) for the relay is shown in

Fig.1.15.

Opposed Voltage Comparator: In this voltage comparator the voltage

drop in the resistance connected externally in the bridge circuits is

compared. The current directions are shown in Fig. 1.16. If the two drops

are equal no current will flow through the relay coil and the relay will not

operate. If he two voltages are not equal then unequal currents will flow

through the resistances and a current will flow through the relay coil in a

direction determined by the largest voltage drop in the resistor. That is, if

the drop in the resistance of the operating bridge is more than that of the

restraining bridge then a current will flow in the operating direction

through the relay. The reverse is true if the drop across the restraining

resistance is more than the operating resistance.

Phase Comparators: There are two main types of static phase

comparators:

FIG. 1.17

FIG. 1.18

a) Those whose output is a D.C. voltage proportional to the vector product

of the two A.C. input quantities:

b) Those which give an output whose polarity depends upon the phase

relation of the inputs. The later are sometimes called coincidence type

and can be direct acting or integrating.

1.8.13Operating Principles of Static Time Current Relays:

Fig. 1.17 shows the block diagram of a static time current relay. The

auxiliary C.T. has taps on the primary for selecting the desire pickup and

current range. Its rectified output is supplied to a fault detector and an RC

timing circuit. When the voltage of the timing capacitor has reached the

value for triggering the level detector, tripping occurs.

Operation of a typical static time current relay: The current from the

main C.T. is first rectified and smoothed by capacitor ‘Cs’ and then passed

through he tapped resistor ‘Rs’ so that the voltage across it is proportional

to the secondary current. The spike filter RC protects the rectifier bridge

against transient over voltages in the incoming current signal, Fig. 1.18.

1.8.14Timing Circuit

The rectified voltage across the ‘Rs’ charges the capacitor ‘Ct’ through

resistor ‘Rt’. When the capacitor voltage exceeds the base emitter voltage

‘Vt’ the transistor ‘T2’ in the Fig. 1.20 becomes conductive, triggering

transistor ‘T3’ and operating the tripping relay.

Resetting circuit: In order that the relay shall have an instantaneous

reset, the capacitor ‘Ct’ must be discharged as quickly as possible. This is

achieved by the detector as follows (Fig. 1.19).

The base of the transistor ‘T1’ is normally kept sufficiently positive relative

to emitter to keep it conductive and hence short circuiting the timing

capacitor ‘Ct’ at YY in Fig. 1.20. When a fault occurs the over current

through the resistor ‘Rs’ makes the base of ‘T1’ negative and cuts it off

leaving ‘Ct’ free to be charged. When the fault is cleared the

FIG. 1.19

FIG. 1.20

current falls to zero and the negative bias on ‘T1’ disappears so that ‘Ct’ is

again short circuited and discharged immediately.

A weakness of very fast instantaneous units is the tendency to over

sensitivity on off-set current waves. The instantaneous unit can be made

insensitive to the D.C. off set component by making the auxiliary C.T.

saturate jus above the pickup current value and connecting the capacitor

and a resistor across the rectified input to the level detector. This prevents

tripping until both halves of the current wave are above pickup valve. That

is, until the off set has gone, the short delay thus entailed is acceptable

with time current relaying.

-oOo-

CHAPTER – 2

INDUCTION DISC TYPE IDMT

OVER CURRENT RELAYS

2.1 Introduction

Induction types are most widely used for protective relaying purposes

involving A.C. quantities. Torque is produced in these relays when

alternating flux reacts with eddy currents induced in a disc by another

alternating flux of the same frequency but displaced in time and space.

These relays are used as over current or earth fault relay. In its simplest

form, such a relay consists of a metallic disc which is free to rotate

between the poles of two electromagnets (Fig. 2.1).

The spindle of this disc carries a moving contact which bridges two fixed

contacts when the disc rotates through an angle which is adjustable. By

adjusting this angle the travel of the moving contact can be adjusted so

that the relay can be given any desired time setting which is indicated by a

pointer on a time setting dial. The dial is calibrated from 0 to 1. These

figures do not represent the actual operating times but are multipliers to

be used to convert the time known from he relay name plate curve into the

actual operating time.

The upper electromagnet has a primary and a secondary winding. The

primary is connected to the secondary of a C.T. in the line to be protected

and is provided with tappings. These tappings are connected to a plug

setting bridge which is usually arranged to give seven selections of

tapping, the over current range being 50 per cent to 200 per cent in steps

of 25% and the earth fault 10% to 40% or 20% to 80% in steps of 5% &

10% respectively. These values are percentages of the current rating of

the relay. Thus a relay may have a current rating of 5A, indicating that it is

suitable for use on CT having secondary current rating of 5A but with a

setting of 50% the relay would start to operate at 2.5A. Similarly if set at

200% it would start to operate at 10A. Thus the relay can be set to pick-up

at any

FIG. 2.1: NON DIRECTIONAL INDUCTION RELAY

FIG.2.2: TIME CURRENT CHRACTERISTIC OF A NON DIRECTIONAL

INDUCTION DISC RELAY

Desired tapping and, therefore, current setting can be selected by

inserting a pin spring-loaded jaws of the bridge type soccer at the

appropriate tap value. When the pin is withdrawn for the purpose of

changing the setting while the relay is in service, the relay automatically

adopts a high setting, thus ensuring that the C.T. secondary is not open

circuited and that the relay remains operative for faults during the process

of changing the settings. The secondary winding surrounds the limbs of the

lower electromagnet as well. The torque exerted on the disc is due to the

interaction of eddy currents produced therein by means of the leakage flux

from the upper electromagnet and the flux from the lower electromagnet:

these two fluxed having a phase displacement between them.

2.2 Characteristic Curve

A set of typical time current characteristic curves of his type of relay is

shown in Fig. 2.2. The curve shows the relation between the operating

current in terms of current setting multiplier along the x-axis and operating

time in seconds along the y-axis. A current setting multiplier indicates the

number of times the relay current is in excess of the current setting. The

current setting multiplier is also referred to as plug setting multiplier

(P.S.M.). Thus

P.S.M=

=

Where, as is usually he case, the rated current of the relay is equal to the

rated secondary current of C.T. From the figure the operating time, when

current setting multiplier is 10 and he time multiplier is set at 1, is 3

seconds. This is sometimes called the basic 3/10 curve.

It is evident that at the same current setting but the time multiplier set at

0.8, the time of operation is 2.4 seconds. Thus o get the actual tie of

operation against any particular time multiplier setting, multiply the time

of operation of the basic curve by the multiplier

FIG. 2.3

Primary Current

Primary Setting Current Primary CurrentPrimary Setting Current

Primary CurrentPrimary Current Setting XC.T.Ratio

setting. Thus in this example the time of operation is 3 x 0.8 = 2.4 secs.

The time current characteristics of Fig. 2.2 are the inverse definite

minimum time (I.D.M.T.) type since the time of operation is approximately

inversely proportional to smaller values of current and tends to a definite

minimum time as the current increases above 10 times the setting current.

The D.M.T. characteristic is obtained by saturating the iron in the upper

magnet so that there is practically no increase in flux after current has

reached a certain value. This results in the flattening out of the current

time curve.

Example: An I.D.M.T. over current relay has a current setting of 150%

and had a time multiplier setting of 0.5. The relay is connected in the

circuit through a C.T. having ratio 500:5 amps. Calculate the time of

operation of the relay if the circuit carries a fault current of 6000 A. the

relay characteristic is shown in Fig. 2.3.

Solution: Sec fault current 6000 x = 60A

Plug Setting multiplier (P.S.M.) = = = 8

Time from graph against this multiplier of 8 = 3.15 sec.

Operating time = 3.15 x 0.5 = 1.575 sec.

-oOo-

5 500

Actual Current in Relay Setting Current

605 x 1.5

CHAPTER – 3

MOTOR PROTECTIONElectrical Motor is an important component of an industry. Squirrel cage induction

motor is most widely used in power stations and industries. To protect the motor

from different faults condition various protection are provided, which are as listed

below.

3.1 Overload Protection

A motor may get overloaded during its operation because of excessive

mechanical load; (b) Single phase; (c) Bearing fault. An overloaded motor

draws overcurrent resulting in overheating of the winding insulation. A

reasonable degree of overload protection can be provided by Bi-metallic

thermal overload relay with setting, 15% for continuously rated motor and

40% for large motors. Modern Motor Protection Relays provide a I2

sensitive Thermal overload protection having a range of exponential

current/time characteristics to match with the thermal withstand

characteristic of motor.

3.2 Single Phasing Protection or Unbalance Protection

When one of the supply fuse of a 3 phase motor blows off or a terminal

connection comes out, single phasing at the motor may occur. In such

case, motor may continue to rotate, but the two healthy phases may draw

high current leading to thermal stress on the insulation.

Besides, the Negative Phase sequence (I2) component of the unbalanced

current, produces a reverse reaction field which cuts the Rotor iron and

winding at approximately double the speed, thereby inducing double

frequency eddy currents, causing over heating of the rotor.

I2 based single phasing protection having Inverse or definite time delay is

used to protect he motor against his eventuality. For small L.T. Motors,

single phasing preventor (unbalanced voltage V2 or current I2 based) is

used to detect single phasing and isolate the defaulting Motor.

3.3 Short Circuit Protection

A short circuit in the winding or at the terminals of a motor, results in

overcurrent and thus overheating/damage to the winding insulation.

An instantaneous high set over current relay with a setting sufficiently

above the starting/locked Rotor current is used for this protection.

For contactor controlled motors (usually L.T.Motors of small ratings), the

short circuit protection is provided by the backup fuse in view of the

limited break rating of the contactor.

3.4 Stalling Protection (Lock Rotor Protection)

A motor may stall during its operation because of excessive mechanical

load resulting in overloading of the motor. A definite time over current

relay, with a setting of 1.5–2

times the Motor rated current, is used to protect the Motor against stalling

condition. The time delay set, is usually above the Acceleration time and

below the stall withstand time.

For high inertia motors, having safe stall withstand time less than the

starting time, the stalling protection is required to be controlled by a speed

switch, mounted on the Motor shaft. During normal acceleration, the speed

switch opens to disable the stalling protection, whereas during a genuine

condition the speed switch remains closed, thereby enabling he stalling

protection and disconnects the defaulting Motor within the safe stall

withstand time.

3.5 Differential Protection

To protect the motor against internal faults, differential protection based

on circulating current principle provided for large critical motors. The

differential protection requires C.Ts of identical ratio and ratings (Class PS)

on both line and neutral side of the Motor for each phase (i.e. 6 C.Ts in

total). The differential relay is usually of high impedance type.

3.6 Earth Fault Protection

A motor may suffer an earth fault because of damage to the winding

insulation. Earth fault may occur in the connecting cable also. Usually two

types of earth fault protections are in vogue.

a) Residually connected earth fault protection with a setting of 10% or above.

No time delay is required except on contactor controlled motors where it is

necessary to prevent earth fault element over riding the fuse, for infeeds

above the break rating of the contactor. The relay is, however, required to

be used with a series stabilising resistor which impedes any unbalance

current produced due to unequal errors in he CTs during starting

transients.

b) C.B.C.T. operated earth fault relay with a setting of typically 1%, where

low earth faults are expected, requiring very high sensitivity.

3.7 Undervoltage Protection

A reduced supply to a motor will increase motor losses and overloading of

he winding. An IDMT or definite time under voltage relay operated off Bus

P.T. is used to protect the motor, the under voltage relay trips the motors

connected to the Bus on upstream supply failure and eliminates possibility

of co-incident starting of all motors together, when the supply is

subsequently restored. Thus, prevents stressing of the supply source.

Composite Motors Protection Relays (Conventional analog types) provide

following protection functions.

a) Thermal overload (Alarm/Trip) – ITH

b) Short circuit (ISC)

c) Single Phasing (I2)

d) Earth Fault (Io)

e) Stalling (IIt)

Numerical versions are now available which offer following additional

protection functions, besides those given above.

f) Prolonged starting time

g) Too many start

h) Loss of load

The Numerical versions have data acquisition capabilities and provide

useful service Data (such as load currents, I2/Io content in load current,

thermal status etc.), historic data fault data on operation. These relays

have programmable settings, programmable output relays and continuous

self monitoring against any internal failures.

-oOo-

CHAPTER – 4

TRANSFORMER PROTECTIONS4.1 Transformer protections are provided -

a) Against effects of faults in the system to which the transformer is

connected.

b) Against effects of faults arising in the transformer itself.

4.1.2 Protections against faults in the System

a) Short Circuits

b) High Voltage, high frequency disturbance

c) Pure Earth Faults.

4.1.3 System Short Circuits

A short circuit may occur across any to phases (phase to phase) or

between any one line and earth neutral (phase to earth). The effect is

excessive over current and electro-magnetic stresses proportional to

square of short circuit current. For these type of faults additional reactance

and additional bracing of the transformer winding and end leads is

resorted to. This reactance may be incorporated in the design itself or

separate series reactance with primary of transformer is provided.

4.1.4 High Voltage High frequency surges:

These surges may be due to arching grounds, switching operation surges

or atmospheric disturbances. These surges have very high amplitudes,

steep wave front currents and high frequencies. Because of this, the

breakdowns of the transformer turns adjacent to line terminals occurs

causing short circuit between the turns.

To take care of this, the transformer winding is to be designed to withstand

the impulse surge voltages as specified below and then protect it by surge

divertors.

System Voltage KV

(RMS)

7.2 KV

12.5 KV

Impulse voltage withstand level (Peak

value)

60 KV

75 KV

33 KV

66 KV

145 KV

245 KV

400 KV

170 KV

250 KV

550 KV

900 KV

1350 KV

Surge divertors are provided from each line to earth. These consist of

several spark gaps in series with a non-linear resistance. This spark gap

breakdown when surge reaches the divertor and disturbance is discharged

to earth through nonlinear resistance since at high voltage divertors

resistance is low. These surge divertors should have rapid response, non-

linear characteristics, high thermal capacity, high system flow current

interrupting capacity and consistent characteristics under all conditions.

4.1.5 System Earth Faults

a) When neutral of the system is earthed: - It represents short circuit

across the phase. Hence, same protection as for short circuit can be

provided.

b) When neutral is not earthed: - Surge divertor gears in front of

transformer is used.

4.2 Protection against Internal Faults

a) Electrical faults which cause serious immediate damage but are detectable

by unbalance of current or voltage.

i) Phase to Earth Fault or phase to phase faults on HV and LV external

terminals

ii) Phase to earth faults or phase to phase faults on HV & LV

winding.

iii) Short circuit between turns on HV & LV winding (inter turn faults)

iv) Earth faults on tertiary winding or short circuit between turn of

tertiary winding.

v) Problem in tap changer gear.

b) Incipient faults: These are initially minor but subsequently develops

itself resulting into damage to the transformer. These may be due to –

i) Poor electrical connection of conductors due to breakdown of

insulation of laminations, core bolt faults, clampings, rings etc.

ii) Coolant failure

iii) Blocked oil flow causing local hot spot on winding.

iv) Continuous uneven load sharing between transformers in parallel

causing overheating due to circulating current.

4.3 Principles of Protection System

Principles used are –

i) Overheating

ii) Over current

iii) Un-restricted earth faults

iv) Restricted earth-faults

v) Percentage bias differential protection

vi) Gas detection due to incipient faults

vii) Over fluxing

viii) Tank earth current detection

ix) Over voltage

x) Tap changer problems.

4.4 Gas Detection

a) Buchholz relay protection

b) Pressure relief valves/switches (for heavy internal faults)

4.4.1 Buchholz Protection

This is for two types of faults inside the transformer.

a) For incipient faults because of –

i) Core bolt insulation failure

ii) Short circuit in laminations

iii) Local over heating because of clogging of oil

iv) Excess ingress of air in oil system

v) Loss of oil due to heavy leakage

vi) Uneven load sharing between two transformers in parallel causing

overheating due to circulating current.

These generate gases causing operation of upper float and energises

the alarm circuits.

b) For serious faults inside the transformer due to –

i) Short circuit between phases

ii) Winding earth faults

iii) Puncture on bushing

iv) Tap changer problems

These types of faults are of serious nature and operate both the floats

provided in the buchholz relay and trip out the transformer.

4.4.2 Principles of Buchholz Relay Operation (Fig. 4.1)

This relay is provided in the connecting pipe from transformer tank to

conservator. Two floats are provided inside the relay and are connected to

mercury switches. Normally the relay is full of oil and in case of gas

collection the floats due to their buyopancy rotate on their supports until

they engage their respective stops. Initially fault develops slowly and heat

is produced locally which begins to decompose solid or liquid insulating

material and thus produce inflammable gases. Gas bubbles are collected in

relay causing oil level to lower down. The upper float rotates as he oil level

in the relay goes down and when sufficient oil id displaced the mercury

switch contacts close and initiates alarm. For serious faults as described

above, gas generation is more violent and the oil displaced by gas bubbles

flows through connecting pipe to conservator. This abnormal flow of oil

causes deflection of both float and trip out the transformer. Recently the

dissolved gas analysis technique (gas chromatography) is in use for pre-

detection of type of slowly developing faults inside the transformer which

helps to decide whether the transformer maintenance/internal inspection

is required to be

FIG. 4.1 CIRCUIT DIAGRAM OF BUCHHOLZ RELAY

carried out or otherwise, and thus helps to predict transformer damage in

future.

4.4.3 Dissolved Gas Analysis

The inflammable gases dissolved in the transformer oil are mainly

hydrocarbon gases (methane CH4, Ethane C2H6, Ethylene C2H4. Acetylene

C2H2, Propane, hydrogen, carbon monoxide and carbon dioxide). With the

help of dissolved gas analysis equipment the concentration of these gases

in PPM can be known and can be cross checked with the IS standard. Also

with the help of Roger’s ratio method, the type of probable incipient fault

can be judged and corrective action can be taken in advance to prevent

failure of the transformer (Ref. Annex.1 &II).

4.5 Over Heating Protection

Protection is mainly required for continuous over load of the transformer.

a) Protection is based on measurement of winding temperature which is

measured by thermal image technique.

b) Thermal sensing element is placed in small pocket located near the top

transformer tank in the hot oil. A small heater fed fro a current

transformer (winding temp. C.T.) in the lower voltage terminal of one

phase, is also located in this pocket and produces a local temp. rise,

similar to that of main winding and proportional to copper losses,

above general temp. of oil.

c) Winding temperature high alarm/rip is provided through mercury

switches in the winding temp. indicators.

d) By thermo-meters, mercury switches heat sensing silicon resistance

are also used for sensing the temp. rise.

e) Thermisters are provided manly in the dry type transformers for

temperature sensing.

Temperature of 55o above ambient of 50oC is generally provided for

tripping.

4.6 Over Current & Earth leakage protection

4.6.1 Earth Leakage Protection

In case of transformer earthed through resistance or earthed through

impedance.

Resistance Grounding: The earth fault current in faulty winding in

resistance grounded transformer depends on voltage between neutral and

fault point and is inversely proportional to neutral resistance.

Iy =

Where Iy is earth fault current; P= percentage of winding to be protected;

KV – line to line voltage and Rn = Neutral Grounding resistance. Suitable

earth fault relay can be provided across C.T. in the neutral of the

transformer depending upon the minimum earth fault current to be

detected.

Impedance Grounding; Transformer neutral is connected to the primary

of neutral grounding transformer. The suitable resistance is connected in

parallel with the secondary of this neutral grounding transformer. The

earth fault relay (neutral displacement relay) is connected across this

resistance. The earth fault relay can be set at about 2.5 percent of

maximum neutral voltage. The relay is time delayed for transient free

operation.

10kv x p Sq. root of 3.Rn

4.6.2 Over current protection

i) HRC fuses are provided for small distribution transformer.

ii) Over current relays are used for power transformers, considering the

following:

a) IDMT relays should be chosen

b) Discrimination with circuit protection of secondary side should

be provided;

c) Instantaneous trip facility for high speed clearance of terminals

short circuit should be provided.

d) Setting depends on transformer reactance or percentage

impedance, faults MVA, type of relay used.

e) Setting of over current relays can be slightly higher than rated –

full load current (say 120 percent of FL) with proper

discrimination.

4.6.3 Combined over current and un-restricted E/F Protection

(Ref. Fig. 4.2)

a) Typical over current/earth fault protection is shown for a Delta/ start

transformer in Fig. 4.2.

b) IDMT O/C elements on delta and star side, primarily serve as back up

protection against downstream short circuits and are time co-ordinated

with downstream O/C protections.

c) The high set instantaneous O/C elements on Delta side (connected to

source) are provided to detect severe terminal short circuits and

quickly isolate the transformer. These are set over and above the

maximum short circuit current infeeds of the transformer for star side

faults.

d) The start side earth fault protection (IDMT) serves as a backup against

downstream earth faults and is required to be suitably time graded.

This can either be residually connected across the phase C.Ts or

operated off a C.T. in the Neutral Earth connection (standby earth fault

relay). The latter is considered to be advantageous since it can detect

star winding earth faults, beside providing backup for downstream

earth faults. Since the neutral C.T. ratio is not tied up with the load

current, a lower C.T. ratio consistent with the maximum E/F current

limited by NGR can be provided. This renders good sensitivity for the

standby E/F protection.

e) The E/F protection on delta side is inherently restricted to delta winding

earth faults and does not respond to earth faults on the star side, due

to zero sequence isolation provided by the delta connection. The delta

side E/F protection, therefore, assumes the form of REF

FIG. 4.2: COMBINED 0/C AND E/F PROTECTION CKT

FIG. 4.3: RESTRICTED E/F PROTECTION CKT

protection, enabling sensitive setting and instantaneous operation. The

relay is connected in high impedance mode with a series stabilizing

resistor, as shown.

4.6.4 Restricted Earth Fault Protection: (Ref. Fig. 4.3)

a) REF protection is used to supplement the differential protection,

particularly here star neutral of the transformer is grounded through a

neutral rounding resistor to limit the earth fault current. REF protection

provides increased coverage to the star winding against earth faults.

b) The REF protection operates on the principle of Kirchoff’s law and

requires CTs of identical ratio and ratings as the phases and neutral

earth connection. The relay is connected across the parallel

combination of the CTs in High Impedance mode.

c) For external earth fault, the associated CTs have dissimilar polarities

forming a series connection. Thus, the resulting current through the

relay is negligible. For internal fault, however, the CTs have similar

polarities, forming a parallel connection, thus adding up the current in

the relay branch. This ensures positive operation of the relay.

4.7 Percentage Bias Differential Protection

a) In this protection, operating current is a function of differential current.

b) The value of restraining current depends on 2nd and 5th harmonic

component of differential current during magnetic inrush and over

excited operation.

c) Bias current is a function of through current (external fault current) and

stabilizes the relays against heavy external fault.

4.7.1 Basic Consideration for differential protection

a) Transformer ratio: the current transformers should match to the rated

currents of the primary windings.

b) Transformer Connection: In delta star connected transformer, the

phase shift of 30oC between primary and secondary side current exist.

Also zero sequence current flowing on the star side will not produce the

reflected current in the delta on the other side. To eliminate zero

sequence component on star side the current transformer must be

connected in delta and the current transformer of delta side must be

connected in start.

c) For star / star transformer CTs on both sides should be connected in

delta.

d) In order that secondary currents from two groups of CTs may have the

same magnitude (i.e. primary side CTs and secondary side CTs). The

ratio of star connected CTs if 5 Amp, then those of delta connected

group may be 5 / Sq. Root of 3 = 2.89 Amps.

e) The operating current is a appropriate percentage of reflected through

fault current in the restraining (bias) coils and the ratio is termed as

percentage slope.

f) Operating coil is provided with vectors sum of the currents in the

transformer windings and the bias coil sees the average scaler sum of

the reflected through fault current. Spill current required to operate the

relay is expressed as percentage of through current.

g) The relay is also provided with an unrestrained differential high set, to

protect against heavy faults which are enough to saturate the line

current transformers. The setting of this high set unit is kept above the

maximum in rush current magnitude. This will operate in typically one

cycle for heavy internal faults.

4.7.2 Operating Principles for Internal fault & external faults

During external fault condition (through fault) (Fig. 4.4):

Current in pilot wires would pass through whole of bias coils and only out

of balance current due to mis-match caused by OLTC and C.T. errors

FIG. 4.4

FIG. 4.5

Would flow through operating coil. Under this condition biasing effect pre-

dominates and prevents the relay operation.

During internal faults: (Fig. 4.5)

In this case, the reflected current flows through only one half of bias coil

and the operating coil and back to CT neutral connection. Here the

operating quantity pre-dominates resulting into operation of the relay.

4.8 Over Voltage Protection

a) Two stage protection is provided

b) The delayed trip is set at 110 percent of the rated voltage with two

second time delay (typical).

c) Instantaneous setting is kept at 115 – 120 percent of the rated voltage

d) During voltage fluctuations the AVR (Automatic Voltage Regulator) will

take care to avoid over voltage condition if fluctuations are within its

operating limits (for Generator step-up transformer).

4.9 Over Fluxing Protection

a) This protection is commonly used for Generator Transformers and

large inter connecting transformers in the Grid.

b) This condition arises during abnormal operating conditions i.e. heavy

voltage fluctuations at lower frequency conditions. This condition is

experienced by the transformer during heavy power swings, cascade

tripping of the generator sets and HT line in the Grid, interstate system

separation conditions and due to AVR malfunctioning during start-up or

shutting down in case of Generator Transformers.

c) The power frequency over voltage cause both stress on insulation and

proportionate increase in the magnetizing flux inside the transformer

due to which the iron losses area increased and the core bolts get

maximum component of flux, thereby rapidly heating and damaging its

own insulation and coil insulation. Reduction in frequency during high

voltage fluctuation has the same effect.

FIG. NO. 4.6

d) Transformer should be isolated within one or two minutes or as

recommended by the manufacturer.

e) The core flux φ α V/f where V – impressed voltage and f – frequency. He

index of over fluxing is, therefore, V/f. Over fluxing relays having

variable V/f setting and time delays are used for this protection.

4.10 Overall Differential Protection

a) This is provided for complete protection of generator and generator

transformer and as such is a compound overall differential protection.

b) In addition to normal differential protection of generator, overall biased

differential protection relay is connected to protect the unit as shown

in Fig. 4.6.

c) 20% pickup and 20% bias setting is provided. (The values are typical).

d) This is a supplementary protection for individual differential protection

of the generator.

e) Unit auxiliary transformers are provided with separate differential

protection

-oOo-

ANNEXURE – I

PERMISSIBLE CONCENTRATIONS OF

DISSOLVED

GASES IN THE OIL OF HEALTHY

TRANSFORMER

(TRANSFORMERS UNION AG)

Gas Less than four

Year in service

4-10 years in

service

More than 10

Years in service

Hydrogen 100/150 ppm 200/300 ppm 200/300 ppm

Methane 50/70 ppm 100/150 ppm 200/300 ppm

Acetylene 20/30 ppm 30/50 ppm 100/150 ppm

Ethylene 100/150 ppm 150/200 ppm 200/300 ppm

Ethane 30/40 ppm 100/150 ppm 800/1000 ppm

Carbon

monoxide

200/300 ppm 400/500 ppm 600/700 ppm

Carbon

dioxide

3000/3500 ppm 4000/5000 ppm 9000/12000

ppm

ANNEXURE – II

CODE FOR EXAMINING ANALYSIS OF GAS DISSOLVED IN

MINERAL OIL AS PER CBIP TECHNICAL REPORT 62.

Ratio of Characteristic gases

0.1

0.1-1

1-3

3

Code of Range ratio

C2H2

C2H4

CH4

H2

C2H4

C2H6

0

1

1

2

1

0

2

2

0

0

1

2

Case No. Characteristic fault Typical Example

0 No fault 0 0 0 Normal ageing

1 Partial discharge

of low energy

density

0

but not

signify-

cant

1 0 Discharge in gas-filled cavities

resulting from incomplete

impregnation, or super-saturation

or cavita-tion or high humidity.

2 Partial discharge of

high energy density

1 1 0 As above, but leading to cracking

or perforation of solid insulation

3 Discharge of low

energy

1-2 0 1-2 Continuous sparking in oil

between bad connections of

different potential. Breakdown of

oil between solid materials.

4 Discharges of high

energy

1 0 2 Discharges with power flow

through. Arcing-breakdown of oil

between winding or coils or

between coils to earth. Selector

breaking current.

5 Thermal fault of low

temperature

(150oC)

0 0 1 General insulated conductor

overheating

6 Thermal fault of low

temperature range

150o-300oC

0 2 0 Local overheating of the core due

to concentrations of flux,

increasing hot sot temperature

varying from small spots in core,

shorting links in core.

7 Thermal fault of

medium

temperature range

300o-700oC

0 2 1 Overheating of copper due to

eddy currents, bad contacts/

joints (pyrolitic carbon formation)

upto core and tank circulating

current.

8 Thermal fault of

high temperature

150o-300oC

0 2 2 - do -

CHAPTER – 5

GENERATOR PROTECTIONS5.1 Introduction

Generation are designed to run at a high load factor for a large number of

years and permit certain incidences of abnormal working conditions. The

machine and its auxiliaries are supervised by monitoring devices to keep

the incidences of abnormal working conditions down to a minimum.

Despite of this monitoring, electrical and mechanical faults may occur, and

the generators must be provided with protective relays, which in case of a

fault, quickly initiate a disconnection of the machine from the system and,

if necessary, initiate a complete shut-down of the machine.

The following are the various types of protections provided for a 200/210

MW Generator.

1. Stator ground (earth) fault protection

a) 95% stator ground fault protection

b) 100% stator ground fault protection

2. Rotor earth fault protection

a) First rotor earth fault protection

b) Second rotor earth fault protection

3. Generator Interturn fault protection

4. Generator Negative phase sequence protection

5. Generator Loss of excitation protection

6. Generator Minimum Impedance (MHO backup) protection

7. Generator Differential protection

8. Generator Overall differential protection

9. Generator Reverse power protection

10. Generator Over frequency protection

11. Generator Under frequency protection

12. Generator Thermal overload protection

13. Generator Over voltage protection

14. Generator out of sep (Pole slipping) protection

FIG. 5.1

FIG. 5.2

FIG. 5.3

5.2 Stator Earth Faults:

In most countries, it is a common practice to ground the generator neutral

through a Grounding Transformer having a loading resistor across its

secondary. This method of earthing is called High Impedance earthing

where the earth fault current is limited to 5–10 Amps. Tuned reactor which

limit the ground fault current to less than 1.0A are also used.

The generator grounding resistor normally limits the neutral voltage

transmitted from the high voltage side of the unit transformer in case of a

ground fault on the H.V. side to maximum 2-3% of rated generator phase

voltage.

Short circuits between the stator winding in the slots and the stator core

are the most common electrical fault in Generators. Interturn faults, which

normally are difficult to detect, will quickly develop into a ground fault and

will be tripped by the stator ground fault protection.

5.2.1 95% Stator Ground fault Relay for Generator (Fig.5.1)

For generators with unit transformer and with high impedance grounding

of the neutral, a neutral voltage relay with harmonic immunity and

independent time delay is used. The relay is normally set to operate at 5%

of maximum neutral voltage with a time delay of 0.3 – 0.5 second. With

this voltage setting, it protects approximately 95% of he Stator winding.

It also covers the generator bus, the low voltage winding of the unit

transformer and the high voltage winding of the unit aux. Transformer.

Relay details: 64 A / B - Neutral Displacement Relay having IDMT or

definite time characteristic.

5.2.2 100% Stator Ground fault protection for Generator

Ground faults caused by mechanical damage may occur close to the

generator neutral. Today there is a distinct trend towards providing ground

fault protection for the entire stator winding (100% stator ground fault

protection).

The principle diagram of the relay is shown in Fig. 5.2. The 100% stator

ground fault scheme includes a 95% unit (1), which covers the stator

winding from 5% of the neutral and a 3rd harmonic voltage measuring unit

(2) which protects the rest of the stator winding.

For generators with 3rd harmonic voltage less than 1%, a filter is available

with a damping factor of more than 100.

When the generator is running and here is no ground fault near the

neutral, the third harmonic voltage unit (2) and the voltage check unit (4)

are both activated and the relay contact used in alarm/trip circuit is open.

If a round fault occurs close to the generator neutral, the third harmonic

voltage unit will reset, operating relay contact will close and alarm or

tripping is obtained.

The voltage check unit is included to prevent faulty operation of the relay

at generator standstill or during the machine running up or running down

period.

Generators which produce more than 1% third harmonic voltage under all

service conditions, can have the entire stator winding up to and including

the neutral point protected by the 100% stator ground fault relay.

5.3 Rotor Earth Fault Protection (64R1/64R2):

The field circuit of generator (i.e. rotor winding) is a isolated D.C. circuit

and not earthed anywhere. The field circuit can be exposed to abnormal

mechanical or thermal stresses due to vibrations, excessive currents or

choked cooling medium flow. This may result in a breakdown of the

insulation between the field winding and the rotor iron at one point where

the stress has been too high.

A single earth fault in the field winding or its associated circuits, therefore,

gives rise to a negligible fault current and does not represent any

immediate danger. If, however a second ground fault should occur, heavy

fault current and severe mechanical unbalance may quickly arise and lead

to serious damage. It is essential therefore that any occurrence of

insulation failure is discovered and that the machine is taken out of service

as soon as possible. Normally the machine is tripped instantly on

occurrence of second rotor earth fault. Three methods are available to

detect this type of faults – (First Rotor earth fault protection) 64R1.

a) Potentiometer method

b) A.C. injection method

c) D.C. injection method

5.3.1 Potentiometer Method (Fig. 5.3)

In this scheme, a center tapped resistor is connected in parallel with the

main field winding as shown in Fig. 5.3. The center point of the resistor is

connected to earth through a voltage relay. An earth fault on the field

winding will produce a voltage across the relay. The maximum voltage

occurring for faults at the ends of the winding.

A ‘blind spot’ exists at the center of the field winding, this point being at a

potential equal to that of the tapping point on the potentiometer. To avoid

a fault at this location remaining undetected, the tapping point on the

potentiometer is varied by a push button or switch. It is essential that

station instructions be issued to make certain that the blind spot is

checked at least once per shift. The scheme is simple in that no auxiliary

supply is needed. A relay with a setting 5% of the exciter voltage is

adequate. The potentiometer will dissipate about 60 volts.

5.3.2 A.C. Injection Method (Fig. 5.4)

This scheme is shown in Fig. 5.4. It comprises of an auxiliary supply

transformer, the secondary of which is connected between earth and one

side of he field circuit through an interposed capacitor and a relay coil.

The field circuit is subjected to an alternating potential at the same level

through out, so that an earth fault anywhere in the field system will give

rise to a current which is detected by the relay. The capacitor limits the

magnitude of the current and blocks the normal field voltage, preventing

the discharge of a large direct current through the transformer.

FIG. 5.4

FIG. 5.5

This scheme has an advantage over the potentiometer method in that

there is no blind spot in the supervision of the field system. It has the

disadvantage that some current will flow to earth continuously through the

capacitance of the field winding. This current may flow through the

machine bearings, causing erosion of the bearing surface. It is a common

practice to insulate the bearings and to provide an earthing brush for the

shaft, and if this is done the capacitance current would be harmless.

5.3.3 D.C. Injection Method (Fig. 5.5)

The capacitance current objection to the a.c. injection scheme is overcome

by rectifying the injection voltage as shown in Fig. 5.5. The d.c. out put of a

transformer rectifier power unit is arranged to bias the positive side of the

field circuit to a negative voltage relative to earth. The negative side of the

field system is at a greater negative voltage to earth, so an earth fault at

any point in the field winding will cause current to flow through the power

unit. The current is limited by including a high resistance in the circuit and

a sensitive relay is used to detect the current.

The fault current varies with fault position, but this is not detrimental

provided the relay can detect the minimum fault current and withstand the

maximum.

The relay must have enough resistance to limit the fault current to a

harmless value and be sufficiently sensitive to respond to a fault which at

the low injection voltage may have a fairly high resistance. The relay must

not be so sensitive as to operate with the normal insulation leakage

current, taking into account of the high voltage to earth at the negative

end of the winding and any over voltage due to field forcing and so on.

5.3.4 (a) Second Rotor Earth Fault Protection 64R2 (Fig. 5.5 a)

In this test system is replaced by a replica field system in the form of

potential divider, two 1K potentiometers in parallel with station D.C. is

used as shown in Figure 5.5 (a) with SW1 at 1st rotor E/F position. Close

switch S1 check that 1st rotor E/F relay VAEM (64R1) operated.

FIG. 5.5 a

FIG. 5.5 b

Shift SW1 to Balance. Obtain balance on the mA meter (Galvanometers) by

coarse / fine adjustment of potentiometer. Shift SW1 on “Test” position,

check operation of relay 64R2 by closing switch S2 thus creating an

unbalance which simulates second E/F.

5.3.4 (b) Rotor Earth Fault (Fig. 5.5.b)

The Scheme to detect Rotor Earth Fault in case of Brushless excitation

system is shown in Fig. 5.5.(b). In this case, Rotor Earth Fault relay forms

the three arms of a bridge whose fourth arm is the field winding

capacitance o Rotor body. During Rotor earth fault, this capacitance gets

shorted and the bridge becomes unbalanced operating the relay. Main

exciter winding, rotating diodes and Generator field winding is protected

by this relay.

5.4 Generator Interturn Fault Protection (95A,B, C) (Fig. 5.6)

Interturn faults have commonly been disregarded on the basis that if they

occur they will quickly develop into earth faults. This is probably true if the

fault is in the slot portion but will take a little longer in the region of the

end connection. An approach of this kind is never attractive and may be

entirely unjustified. There is a possibility of the machine being very

seriously damaged before the fault evolves to a condition that can be

detected by the longitudinal system.

Modern medium size and large size turbo generators have the stator

winding designed with only one turn per phase per slot. For these machine

Interturn faults can only occur in case of double ground faults or as a result

of severe mechanical damage of the stator end winding. The latter is

considered rather unlikely to occur.

It is generally considered difficult to obtain a reliable protection against

short- circuiting of one turn if the stator winding has a large number of turn

per phase.

For generators with split neutrals, the conventional inter-turn fault

protective scheme comprises a time delayed low set over-current relay

which senses the current flowing in the connection between the neutrals of

the stator winding. The fault current can be extensively large in case of

Interturn fault, hence the time delay must be short,

FIG. 5.6

FIG. 5.7

0.2 to 0.4 sec and the over current relay must be set higher than the

maximum unbalanced current in case of external faults and the minimum

unbalanced current for single turn short circuit have to be obtained from

the manufacturer of the machine.

Due to the difficulties in obtaining a reliable and secure interturn

protection, it is in most cases omitted. It is assumed that the Interturn fault

will lead to a single phase ground fault at the faulty spot, and the machine

will then be ripped by the ground fault relay within 0.3 – 0.4 secs.

Relay is show for one phase only. Similar connections are for other two

phases. Time delay of 200 sec. is provided to avoid operation of relay in

system disturbance condition.

5.5 Generator Negative Phase sequence Current Protection (46) (FIG.

5.7)

When the generator is connected to a balanced load, the phase currents

are equal in magnitude and displaced electrically by 120o. The ampere turn

wave produced by the stator currents rotate synchronously with the rotor

and no eddy currents are induced in the rotor parts.

Unbalanced loading gives rise to a negative sequence component in the

stator current. The negative sequence current produces an additional

ampere turn wave which rotates backwards, hence it moves relatively to

the rotor at twice the synchronous seed. The double frequency eddy

currents induced in the rotor may cause excessive heating, primarily in the

surface of cylindrical rotors and in the damper winding of rotors with

salient poles.

The approximate heating effect on the rotor of a synchronous machine for

various unbalanced fault or severe load unbalance conditions is

determined by the product

2I2t = K, where

I2 = Negative sequence current expressed per unit of stator current

(PU)

t = Time in seconds

K = a constant depending on the heating characteristic of the machine

(rotor) i.e. type of machine and the method of cooling adopted for

rotor.

The capability of machine to withstand continuously unbalanced currents

is expressed as negative sequence current in percent of rated stator

current. Typical values for generators are given in table.

Type of generator Max. permitted

2I2.t

Max. permitted

continuous I2

(%)

A Cylindrical rotor

Indirectly cooled

Directly cooled

30

(5 – 10)

10

(5 – 8)

B Salient pole rotor with

Damper winding

Without damper winding

40

40

10

5

Single phase and specially two phase short circuits give rise to large

negative sequence currents. The faults are however, cleared by other

relays in a tie much shorter than the operate time of the negative

sequence relay.

A two phase short circuit with fault current equal to 3.46 (2 Sq.rt of 3) time

rated generator current implies a negative sequence current component

equal to twice the rate current (2 p.u.). Hence a negative sequence relay

with the setting.

2I2t = 10s would trip with a time delay of

10 = 2.5 sec.

22

Example on load dissymetries which give rise to negative sequence

currents in the generator are -

1. Unbalanced single phase loads-Traction loads and induction furnaces.

2. Transmission line dissymetries due to capacitors, non-transposed

phase wire or open conductors (C.B. pole failure)

An open conductor may give rise to a considerable negative sequence

current, as a maximum of more than 50% of rated machine current. The

combination of two or more of the above mentioned dissymetries case

give rise to harmful negative phase sequence current, even if each of them

gives rise to a relatively small unbalance. The Fig. 5.7 will illustrate the

C.T. and circuit.

5.6 Generator Loss of Excitation Protection (40G) (Fig. 5.8)

A complete loss of excitation may occur as a result of –

a. Unintentional opening of the field breaker

b. An open circuit or a short circuit of the main field

c. A fault in the automatic voltage regulator (AVR) with the result that the

field current is reduced to zero

When a generator with sufficient active load looses the field supply, it goes

out of synchronization and starts to run a synchronously at a speed higher

than the system, absorbing reactive power (VAR) for its excitation from the

system, operates as an induction generator.

The maximum active power that can be generated without loss of

synchronism when the generator losses its excitation depends on the

difference between the direct axis and quadrature axis synchronous

reactance. For generators with salient poles, the difference is normally

sufficiently large to keep the machine running synchronously; even with an

active load of 15=25% of rated load.

For cylindrical turbo generators, the direct ad quadrature axis reactance

are practically equal, and the machine falls out of synchronism even with a

very small active load. The slip speed increases with the active load.

The stator end regions and parts of the rotor will be overheated, if the

machine is permitted to run for a long time at higher slip seeds. The relay

used to detect field failure is an offset MHO Relay with 90o lead MTA (40G).

on field failure, the terminal impedance locus moves within the Relay

characteristics, causing operation. The relay is used with an external or

built-in time delay for its transient free operation.

FIG. 5.8

FIG. 5.9

5.6.1 Out of Step Protection of Generator

A generator may lose synchronism with the power system, without failure

of the excitation system. Because of a severe system fault disturbance or

operation at a high load with a leading power factor and hence a relatively

weak field. In this condition, which is quite different from the failure of field

system,. The machine is subject to violent oscillations of torque, with vide

variations in current, power and power factor. Synchronism can be

regained if the load is sufficiently reduced but if this does not occur within

a few seconds it is necessary to isolate the generator and then

resynchronize.

The impedance of the generator measured at the stator terminals changes

mostly when synchronism is lost by the machine. The terminal voltage will

begin to decrease and the current to increase, resulting in a decrease of

impedance and also a change in power factor.

A pole slipping protection comprising of two ohm relays is used to detect

out of step operation. The relay monitors the load impedance at the

machine terminals and operates when the terminal impedance locus

sequentially crosses both ohm relay characteristics which corresponds to

one pole slip between the defaulting machine and the system.

5.7 Generator Minimum Impedance (MHO Back) Protection

(21G1, G2, G3):

The generator minimum impedance protection (or Impedance back-up

protection) is primarily provided to protect the Generator against

uncleared external short circuits on the lines emanating from the station

bus bars. The relay has an impedance or offset MHO characteristic and is

set to cover he impedance of the longest line. The Generator transformer

being delta/star, introduces a 30o phase shift on the HV side. To ensure

correct impedance measurement of the lines, the machine voltage fed to

the relay (via Generator V.Ts), is phase corrected by using Interposing

voltage transformers (delta/star) connected in the same vector group as

that of the Gen. Transformer.

The relay operation is delayed by using external or built-in timer so as to

discriminate with line back-up protections.

Over current type of back-up protection is also used for Generator. This is

usually of voltage restraint or voltage controlled type where the voltage

input from the Generator V.T. is used to sensitise the over current

protection on fault. This ensures [positive operation even though the

sustained fault current is less than the full load current of the machine due

to the effect of armature reaction. The over current backup is also set with

adequate time delay to coordinate with down stream backup protections.

5.8 Generator Differential Protection (87A,B,C) (fig. 5.10)

5.8.1 Principle of Operation

Current transformers at each end of the protected zone are interconnected

by an auxiliary pilot circuit as shown in Fig. 5.10. Current transmitted

through the one causes secondary current to circulate round the pilot

circuit without producing any current in the relay. A fault within the

protected zone will cause secondary currents of opposite relative phase as

compared with the thorough fault condition. The summated value of these

currents will flow in the relay, thus energizes the relay. The relay voltage

setting is decided from the secondary load drop buy the following formula.

Vmax = I11 (RCT + RL) where

I11 = Secondary subtransient short circuit current.

RL = resistance of pilot wire between current transformer (CT) and relay.

RCT = resistance of the secondary winding of the saturated current

transformer.

The relay operating voltage is set higher than Vmax. The minimum

operating current depends mainly on the current setting of the relay, the

magnetizing characteristics current of the associated CTs and CT Ratio.

For internal faults, the fault current equal to or above the minimum

operating value of the relay, the voltage across the relay goes upto the

FIG. 5.10

Full saturation voltage of the CTs and the relay operates in 10-15 msec.

Non-linear Resistor (metrosils) across the differential relay limits the

voltage to a safe level. The primary operating current is normally between

1-5% of rated generator current. The relay requires separate CT cores.

The differential relay is usually high impedance relay. The current

transformers on the generator neutral and the line side shall have identical

turns ratio and similar magnetizing characteristics. Hence under normal

service conditions and external faults, with unsaturated current

transformers, the voltage across the relay is negligible.

Biased differential relays are also used for generator differential

protection. The operating principle is same as that for the biased

differential protection of transformers. However, a moderate bias (10 to

20%) is adequate for Generator since the mismatch is primarily due to CT

errors, unlike in case of transformers where OLTC produces maximum

mismatch on end taps. Besides, inrush immunity is not required incase of

Generator, unlike in case of transformers.

5.9 Generator Overall differential Protection (87GT) (Fig. 5.1)

This protection is used to protect the complete bus of generator, generator

transformer and high voltage bus side of unit auxiliary transformer. The

special features of the relay are –

1) Through current restraint for external faults

2) Magnetizing inrush restraint

3) Over excitation restraint to counteract operation at abnormal

magnetizing currents caused by high voltage/low frequency.

The magnetizing restraint is required to keep the relay stable when a

nearby fault on an adjacent feeder is cleared.

During the time of fault, the terminal voltage of the main transformer is

practically zero and after fault clearance i.e. when the circuit breaker of he

faulty feeder opens, the transformer terminal voltage quickly rises. This

may cause severe recovery inrush currents. The

FIG. 5.11

FIG. 5.12

inrush restraint is also required when the unit transformer is energized

from the HV bus.

The over excitation restraint is important since there is a possibility of over

voltage when load is suddenly disconnected in which the differential relay

may trip the generator and the voltage remains high until the automatic

voltage regulator (AVR) brought it back to the normal value.

The relay has an unrestrained differential high set unit. The unrestrained

operation must be set higher than the maximum inrush current of the

transformer. It gives fast tripping (10-20m sec.) The CT and relay

connections are shown in Fig. 5.11.

5.10 Generator Reverse Power Protection (32) (Fig. 5.12)

This is basically the protection provided for the prime mover i.e. turbine. If

the driving torque becomes less such as closure of main steam valves in

case of steam turbo generator, the generator starts to work as a

synchronous compensator, taking the necessary active power from the

network. The reduction of steam flow reduces the cooling effect on the

turbine blades and overheating may occur. The work done by the

entrapped steam in the turbine is then zero. As generator is not designed

to run as a motor it should be immediately tripped when the steam flow to

the turbine is stopped and to avoid damage to the turbine blades.

The generator currents remain balanced when the machine is working as a

motor. For large turbo-generator, where the reverse power may be

substantially less than 1%, reverse power protection is obtained by a

minimum power relay, which normally is set to trip the machine when the

active power out put is less than 1% of rated value.

The relay contains directional current relay which measures the product IX

cos Ø , where Ø is the angle between the polarizing voltage and the

current to the relay. The scale range used is 5-20mA for 1A and 30-120 mA

for 5A rated CT secondary currents. Time delay of 2 seconds is provided.

The detail connections of CT and relay are shown in Fig. 5.12.

5.11 Generator Over Frequency Protection

5.12 Generator Under Frequency Protection (14A/14T/81)

The Generators are designed to give rated output at rated terminal voltage

ad rated frequency. Hence an operation above certain limit i.e. +5% and –

5% of rated frequency is avoided to protect various apparatus in a network

and also the generator and turbine. Operation at low frequency must be

limited, in order to avoid damage to generators, generator transformers

and turbines, (over fluxing may occur if frequency is less than rated).

In practice, prolonged generator operation at low frequency can only occur

when a machine with its local load is separated from the rest of the

network. The necessity of under frequency protection has to be evaluated

from knowledge of the network and characteristics of the turbine

regulator. A time delay of about 2 seconds is introduced in the tripping

circuit to avoid transient tripping.

5.13 Generator Thermal Overload Protection (51A/51B) (Fig. 5.13)

A generator operating on a large system under continuous supervision is

not in much danger of accidental overloading. The power that can be

generated is limited by the steam production and hence can not rise un-

noticed or maintained for any appreciable period above the programmed

level. Overloads in terms of current or MVA as distinct from megawatts are

possible. Depending on the voltage regulator setting and type of control

relative to the rest of the system, a given generator may take a

disproportionate share of the MVAR load on the system. Overloads upto

1.4 times the rated current are not normally detected by the impedance or

overcurrent protection. Sustained overloads within this range are usually

supervised by temperature monitors (RTD/or thermocouples).

As an additional check of the stator winding temperature, an accurate

thermal overload relay may be used. With static relay it is possible to

obtain the short relay time constants required for adequate thermal

protection. The current overload relay are not expected to give exact

measurement of the winding temperature under all conditions.

FIG. 5.13

FIG. 5.14

5.14 Generator Overvoltage Protection (I/II (59A/59B) (Fig. 5.14)

During the starting up of a generator, prior to synchronization, he

Generator terminal voltage is obtained by the proper operation of the

automatic voltage regulator (AVR). After synchronization, the terminal

voltage of the machine will be dictated by its own AVR and also by the

voltage level of the system and the AVRS of nearby machines. It is not

possible for one machine to cause any appreciable rise in the terminal

voltage as long as it is connected to the system. Increasing the field

excitation, owing to a fault in the AVR, merely increases the reactive MVAR

output, which ay ultimately lead to tripping o the impedance relay or the

V/Hz. Relay. Maximum excitation limit prevents the rotor field current and

he reactive output power from exceeding the design limits.

This protection is used for the insulation level of the generator stator

windings. Severe over voltage will occur, if the generator circuit breaker is

tripped while the machine is running at fu load and rated power factor, the

subsequent increase in terminal voltage will normally be limited by a quick

acting AVR. However, if the AVR faulty or at this particular time switched

over to manual control, over voltage will occur. This voltage rise will be

further increased if simultaneous over speeding should occur, owing to a

slow acting turbine governor.

Modern unit transformers with high magnetic qualities have a relatively

sharp and well defined saturation level, with a knee point voltage between

1.2 and 1.25 times the rated voltage (Un). A suitable setting of the over

voltage relay is, therefore, between 1.15 and 1.2 times Un and with a

definite delay of 1 to 3 sec.

An instantaneous high set voltage relay can be included to trip the

generator quickly in case of excessive over voltage following a sudden loss

of load and generator over speeding.

GENERATOR PROTECTIONS AT A GLANCE

Protection Cause Effect Relay Setting

Stator Earth

Fault

Short circuit in slots between

core & winding.

Interturn short circuit Mech. or

thermal damage to corona

Insulation damage Voltage Relay 2-5% of normal

neutral voltage

t.d. 0.3 – 0.5 sec.

preventive paint

Rotor Earth

Fault

Abnormal mech. or thermal

stresses due to vibrations,

Overcurrent, overheating.

- do - - do - 1-5% of voltage

injected.

Interturn fault Interturn Short Circuit -do - Double Primary

CT &O/C relay

0.5 to 1.5A

200 ms. to 1 sec.

Negative Phase

Sequence

Unbalance loading Excessive rotor

heating

O/C Relay

(I2 based)

5-10% of full load current

or as recommended by

manufacturer.

Gen. Loss of

Exen.

1. Unintentional Opening of

field breaker.

2. An o/c or s/c in field. Winding

3. Fault in AVR

Induction Generator

Asynchronous

Operation

Overheating of rotor

and stator end zone

Impedance

Relay/Offset MHO

Relay

Dim = 0.5xXd pu

t.d. 2 sec.

Offset=0.75 Xd’pu

Gen. Min.

impedance

Phase to phase short circuit in

stator winding on Gen. Bus

LV side for GTR

HV side of UAT and uncleared

faults on the evacuation lines.

MHO Relay 70% of rated Gen.

Load imp.

1/0.7=1.4 times rated

current at rated voltage

1-1.5 msec.

Generator

Differential

Protection

Internal fault Differential Relay 1-5% of rated Gen.Current

10-15 msec.

Reverse Power

Protection

Failure of prime mover Motoring damage to

turbine blades

Directional power

relay

0.5% of rated power.

t.d. 2 sec.

Low Forward

Power

Upon an electrical tripping

prime mover fails to trip

Over speeding - do - - do -

Over Frequency Sudden loss of load.

C.B. Opens with turbine ON

Overspeed

(Mech. Device)

Frequency Relay +5%

t.d. 2 sec.

Under

Frequency

Increase in load Over fluxing (V/f)

Aux. Speed falls

- do - -5%

t.d. 2 sec.

Over fluxing Malfunctioning of AVR.

Load throw-off with Excitation.

On manual, under frequency

operation

Overheating of stator

iron and transformer

iron parts

Frequency

Dependent

Voltage relay

V = 1 to 1.3F

T = 3-5 sec.

Over Loading

Protection

Overloading in-terms of current or

MVA, Failure of coolant flow or

temp.

Temp. rise in stator

winding

Static thermal

over load relay

Set=Amb. Temp. +

Temp. rise given on name

plate

Over Voltage

Protection

Sudden loss of load at full load

and rated p.f. and AVR fails or

changeover to manual and

generator Overspeed

Insulation damage Voltage Relay 110%-2 sec. t.d.

115% - 120% Instt.

Local Breaker

Backup

GCB fails to trip External sources

feeding fault

LBB Protection in

conjunction with

Bus Bar

protection

5-8%. In Set at 5%

t.d. – 0-20 sec.

CHAPTER – 6

BUS ZONE – PROTECTION AND LOCAL

BREAKER

BACKUP PROTECTION6.1 Introduction

With ever increasing short circuit levels and growing complexities of the

supply system, Busbar protection is becoming increasingly relevant even

at medium voltage level in Industrial Distribution system. Besides, major

Industrial installations with high contract demand and growth potential,

often get utility supply at Extra High Voltage (EHV) level i.e. 132 KV and

above where high speed bus bar protection is considered essential from

the point of view of system stability.

Local breaker backup protection (against stuck breaker condition) though

more prevalent in utility systems can be applied in industrial distribution

system at an advantage. This protection gets well with Bus Bar protection

as it can share common tripping logic with bus bar protection.

6.2 Bus Bar Protection - Requirements

6.2.1 Stability

It should be stable under maximum through fault condition with fault level

approaching switchgear breaking capacity.

6.2.2 High Speed Operation

Typical operating time range between 10-30 msecs. Fast clearance

enables maintaining system stability, besides limiting equipment damage

and also enables localised isolation of the faulted Busbar avoiding wide

spread disruption in the system.

6.2.3 Selectivity

It should be selective in isolating the faulted busbar, particularly in case of

multi-bus installations.

6.2.4 The protection should operate positively for internal fault, despite long

intervening quiescent periods, the bus faults being fewer and far apart.

6.2.5 Sensitivity

The protection should be adequately sensitive to clear low in feed faults,

particularly during minimum generating conditions.

6.2.6 Suitable for use with moderate C.T. ratings

This is necessary since the CTs have to handle high fault currents, worst

case being faults approaching switchgear breaking capacity.

6.2.6 Configurable to different Busbar arrangements

The busbar arrangement may undergo changes such as sectionalisation

and additional circuits may be connected in future. The protection should

be extendable to such configuration changes.

6.3 Types of Bus Bar Protection

The most commonly used bus bar protection system are:

1) System Protection covering Busbar

2) Differential protection

6.3.1 System Protections Covering Busbar

These are primarily local or remote backup protection such as over

current/earth fault relay on feeders/transformers or distance protection

provided on lines.

The distance protection for example, provides backup protection to

remote busbars in time delayed zone 2 or backup to local busbars in time

delayed zone 3 with a small reverse reach. The IDMT overcurrent. Earth

fault relays also provide similar backup protection to the connected circuits

against bus faults. However, these cannot be considered as primary

protection for busbar, being time delayed and non-selective.

6.3.2 Differential Protection

The differential protection is the primary protection for bus bar against

both phase and earth faults. Practical bus differential schemes have all the

ingredient as spelled out under 6.2 above.

6.3.2.1 Operating Principle of Differential Protection

The protection uses a circulating current arrangement, with CTs of

identical ratio and ratings on all incoming and outgoing circuits having heir

secondaries connected in parallel (phase by phase) to form a replica of the

primary bus bar arrangement. The differential relay is connected across

the CT secondary bus wires.

For external faults, the summated inflow from healthy circuits is equal to

the outflowing current from faulted circuit and thus the currents are

balanced, with no differential current through the relay. For internal fault,

however, all CTs see inflow of current into the bus. The secondary

currents, therefore, add up into the relay branch. Typical current

distribution for external and internal fault is shown in Fig. 6.3.2.1.

The above illustration, considers ideal current transformers with no errors

which is too simplistic an assumption. In practice, CTs have errors and may

experience unequal saturation due to remnant flux in the core and

dissimilarities in their magnetizing characteristics, particularly if the fault

current is asymmetrical having a slowly decaying d.c. component. This

may produce transient unbalance, causing operation of the high speed

differential relay. The practical differential protection for busbars,

circumvent this problem either by making the relay branch high

impedance or providing a through current bias, thereby, automatically

increasing he pickup threshold of the differential relay, above the expected

unbalance current, on through faults. Two types of bus bar protection

schemes are in vogue:

1. High Impedance

2. Low Impedance (Biased)

6.3.2.2 High Impedance Scheme (Fig. 6.3.2.2)

1. The relay branch is made high impedance either by using a voltage

operated high impedance relay or by connecting an external series

resistor (stabilizing resistor) in case of current operated differential

relay.

FIG. 6.3.2.1: CURRENT DISTRIBUTION

FIG. 6.3.2.2: TYPICAL C.T. CONNECTION

FIG.6.3.2.3 : C.T. SUPERVISION

2. This type of protection requires special class PS CTs (with low turns

ratio errors) of identical ratio and ratings on al circuits. Exclusive CT

cores are required for high impedance schemes which cannot share

common CT cores with other protections.

3. High impedance schemes are primarily fundamental frequency

turned, over current or over voltage relays and hence simple in

design and execution.

6.3.2.3 Supervision

The differential protection has a fail safe design. Consequently, the relay

becomes potentially unstable for any open circuit or cross connection in

the CT secondary of he associated feeders. The maloperation of the Busbar

protection can be prevented on load under the above condition by setting

the pick up threshold of the differential element over and above the

maximum loaded circuit current. However, the relay may still maloperate

on a through fault, if the CT secondary open circuit goes undetected. A

maloperation of busbar protection could be catastrophic, particularly in

interconnected system and hence continuous supervision of CT secondary

is required as an additional safeguard.

The supervision relay is an AC voltage relay, connected across the

differential relay branch, having a sensitive setting range (usually 2 – 14

volts) and a fixed time delay to prevent transient operation on internal

faults. The relay is connected to sound an alarm and short CT secondary

Bus wires, on operation. Typical circuit arrangement for CT supervision

relay is shown in Fig. 6.3.2.3.

6.3.2.4 Check Feature

Since stability is a very critical parameter of busbar protection, additional

check feature is usually provided in high impedance schemes to enhance

security against possible maloperation.

The check feature is operated off a separate CT core on all incoming and

outgoing circuits connected to the bus and is a virtual duplication of the

main differential system. The contacts of the main and check

FIG. 6.3.2.4 (a): TWO ZONE CHECK FEATURE

differential relay are connected in series so that tripping is conditioned by

simultaneous operation of both for an internal fault the check zone

provides a two fold advantage.

1. It enhances security in Multi-Bus Installations where CT switching

becomes inevitable for zonal discrimination.

2. It enables sensitive setting to be adopted on differential relay without

the risk of maloperation with CT open circuiting under maximum load

condition.

A typical 2 zone scheme for sectionalized busbars with check feature is

illustrated in Fig. 6.3.2.4.

6.3.2.5 C.T. Switching

In case of multi bus arrangement (2 Bus/3 Bus arrangement), CT

secondaries of incoming/outgoing circuits are required to be switched to

form a secondary replica of the primary Bus arrangement to achieve zonal

discrimination. This is done either by using the bus isolator Auxiliary

contacts of individual circuits or by using separate contact multiplication

relay of Electrical reset type as shown in the Fig. 6.3.2.5.

6.4 LOW IMPEDANCE SCHEME (BIASED)

Typical CT connection for the scheme is shown in Fig. 6.4.0. Low

impedance Bus differential relay is primarily a biased differential relay

where the through current bias (restraint) increases the pickup threshold

of differential relay on external fault to ensure stability. The low impedance

relay is more tolerant to CT mismatch and can share common CT core with

other protections. Practical low impedance schemes provide CT saturation

detectors to enhance stability.

6.5 LOCAL BREAKER BACK-UP (LBB) PROTECTION

6.5.1 Introduction

In EHV substations, reliability of fault detection is enhanced by providing

duplicated protections (either Main 1/Main 2 or Main and Backup

Protection). At the upper end of the EHV levels, the D.C. sources for

protection are also duplicated for better redundancy.

FIG. 6.3.2.5(a): TYPICAL C.T. SWITCHIG ARRANGEMENT

FIG. 6.4.0: LOW IMPEDANCE SCHEME (BIASED)

Besides, the control breakers are provided with duplicated trip coils. All

these measures, undoubtedly improve the reliability of fault detection and

isolation. However, the possibility of mechanical failures of the switchgear

or interrupter flash overs can not be covered by these means for obvious

reasons. A failure of the breaker may therefore, result inspite of correct

operation of the protection and envergisation of trip coils. This situation

can be corrected by providing local breaker backup (LBB) or breaker fail

protection.

6.5.2 Operating Principle

LBB protection comes into operation, only if, the breaker fails to trip,

following energisation of its trip coi8l, through the circuit trip relays. The

main ingredient of LBB protection, is a current check relay initiated by the

circuit trip relays and a follower timer. The current check relay, on

initiation, check the presence of the current in the faulted circuit and if it

persists beyond a preset time, proceeds to trip all other circuits connected

to the Busbar to which the stuck breaker is connected, thereby, ensuring

local isolation. Tripping of remote breaker is also initiated through a

separate carrier channel, in case of line breakers to arrest infeeds from

remote end. A typical simplified LBB scheme is shown in Fig. 6.5.2 to

illustrate its operating principle.

The circuit protections (M1/M2/BU) on operation initiate CB tripping and

simultaneously trigger LBB current check relay by extending DC. The LBB

protection, therefore, gets initiated on operation of the circuit protection

and hence does not require any time co-ordination with the circuit

protections. Besides a much sensitive setting can be provided in the

current check relay, independent of the circuit loadings. Typical setting

range for the current check relay and follower timer and recommended

settings are give below.

Application Current check relay Follower Timer

Range Recommend

ed

Setting

Range Recommend

ed

Setting

Generator

Circuit

5 – 80% 5% 0.1 – 1 secs. 0.2 secs

All other circuits (TFRs/Lines/Bus Couplers etc.

20 – 320% 20% 0.1 – 1 secs. 0.2 secs.

FIG. 6.5.2(a): TYPICAL LBB SCHEM AC/DC CIRCUITS

FIG. 6.5.2(b):

FIG. 6.5.3: COMBAINED BUS BAR PROTECTION/LBB

A more sensitive setting is generally adopted for Generator application, in

view of the fact that a stuck breaker situation for certain abnormal

conditions like motoring, may involve very low current infeeds.

6.5.3 Combined Tripping Logic for LBB/Bus Bar Protection

Where Busbar protection is contemplated, the LBB scheme can share

common trip logic/tripping relays with Busbar protection. A typical

combined Busbar protection/ LBB scheme is shown in Fig. 6.5.3 of 2 Bus

Installation.

6.5.4 Setting Criteria for LBB Timer

The LBB time delay is primarily influenced by the tripping time of the

breaker and the reset time of the current check relay on correct tripping of

the breaker. Besides, adequate safety margin is also to be allowed. The

timing criteria is explained on a time scale below.

TLLB = TCB + TDO + TM - TPU

Where TLLB - LBB Follower timer setting

TCB - Breaker Tripping time

TDO - Drop off time of current check relay

TPU - Pick up time of current check relay

TM - Safety Margin

Usually a time delay of 200 msecs. Is adopted which allows sufficient time

co-ordination with remote back up protection.

- oOo -

7. DISTRIBUTION FEEDER PROTECTION

7.1 Introduction

Industrial Power Distribution systems make extensive use of cable feeders

for example, between captive generation Bus or ‘Grid Supply Bus’, to load

centers/Power control centers. These feeders are often radial or some

times form part of a ring main systems. While IDMT over current/earth

fault protection is mostly used for radial distribution feeders particularly in

the tail end unit type protections, such as pilot wire protection are also

sometimes used on critical feeders.

The unit protections are highly selective, sensitive and fast in operation,

but do not have any back up capabilities. The IDMT protection on the

contrary, are simple and economical but slower in operation to necessitate

time coordination between adjacent sections for selective trippings. IDMT

relays, however, provide excellent backup protection to the down stream

system.

7.2 Unit Protection

The principle of unit systems was first established by Merz and Price. This

fundamental differential system have formed the bases of may highly

developed protective arrangements for feeders and many other plant

equipments. Two forms of different schemes are available.

a) Circulating Current System

b) Balanced voltage system

7.2.1 Circulating Current System

In this arrangement current transformers of identical ratio and ratings are

provided at each end of the protected zone and are interconnected by

secondary pilots as shown in Fig. 7.2.1(a).

For external faults, the two end CTs see equal inflow and outflow

producing a circulating current between the C.T. secondary and pilots,

with no differential current through the relay. For an in-zone fault,

however, the secondary currents have a additive polarity and, hence the

summated current flows through the relay, causing operation.

FIG. 7.2.1(a): CIRCULATING CURREN SYSTEM

FIG.7.2.2 (a): BALANCED VOLTAGE SYSTEM

FIG. 7.2.3(a): TYPICAL SUMMATION C.T.

In practice, unequal saturation of the CTs can cause increased spill current

through the relay on external faults, producing instability. The problem is

normally overcome by making the relay branch “high impedance” by

adding series stabilizing resistor.

7.2.2 Balanced Voltage System

In balance voltage system, the CT secondary outputs are opposed for

through fault so that no current flows in the series connected relay. An in-

zone fault however, produce a circulating current causing operation. The

arrangement is shown in Fig. 7.2.2.(a).

In the above arrangement, external fault would ineffect cause a CT open

circuit condition as no secondary current would flow. To avoid excessive

saturation of the core, the core is provided with non-magnetic gaps to

absorb the maximum primary m.m.f. The secondary winding therefore

would produce an e.m.f. and can be regarded a voltage source.

The inherent CT errors and pilot capacitance would produce substantial

spill current through the relay on through fault, causing instability. The

problem is overcome by providing a through current bias (restraint) which

increases the differential pickup approximately proportional to the through

fault current, thereby ensuring stability.

7.2.3 Summation Arrangement

In 3 phase systems, independent protection can be provided for each

phase, using phase comparison of the two end currents. This would

however, require a minimum 4 core pilot adding up to the cost. An

alternative is to combine the separate phase currents into a single

quantity for comparison over a pair of pilots. This is achieved by using

summation current transformers.

A typical summation C.T. is shown in Fig. 7.2.3 (a)

The interphase section of the summation winding (i.e. A-B & B-C) usually

have equal number of turns and the neutral end winding (C-N) having

greater number of turns.

The above summation arrangement would produce output for both

balanced as well as unbalanced faults. Moreover, the relay offers different

sensitivities for different types of faults depending upon the phases

involved. In the summation arrangement illustrated, the associated relay

will have highest sensitivity for A-C and A-N faults.

7.2.4 Supervision of Pilots

The pilot circuits are subjected to various hazards which can cause open

circuit or short circuit of the pilot cores. While overhead pilots are

vulnerable to storms, buried pilots may be damaged during excavation.

The pilot failure may lead to either mal-operation or non-operation of the

protection and hence continuous supervision of the healthiness of he pilots

become necessary.

This is achieved by injecting a small d.c. current though the pilot from one

end and monitoring its presence at the other end by energizing an

auxiliary relay. The auxiliary relay resets in the event of any discrepancy

in the pilots and sounds an alarm. A small time delay is introduced to

prevent transient operation due to primary system faults, causing

momentary dip in the auxiliary supply.

Overcurrent check feature may also be incorporated to prevent tripping on

load in the event of a pilot open circuit condition as it may lead to

instability.

7.3 IDMT Overcurrent & Earth Fault Protection

While at the lower end of the distribution system (particularly at low

Voltage Levels), fuses or series connected trip coils operating on Switching

devices, are used for short circuit protection. IDMT over current/earth fault

relay find wide application at medium voltage levels.

As the name implies, IDMT relays have an Inverse time/current

characteristic (i.e. The operating time is inversely proportional to the

current) and a Definite Minimum Time (DMT) for high multiples of setting

current. The time/current characteristic is usually represented on a

logarithmic scale and gives the operating time at different multiples of

setting current for the maximum “Time Multiplier Setting” (TMS). The TMS

is continuously adjustable giving a range of time/current characteristic.

7.3.1 IDMT Characteristic Variations and their Applications

There are different variations of IDMT Characteristics. These are

i) Standard Inverse t = 0.14/(10.02-1)

ii) Very inverse t = 13.5/(I-1)

iii) Extremely Inverse t = 80/(I2-1)

iv) Long inverse t = 120/(I-1)

Where t = Relay operating time (seconds)

And I = Current (as multiple of Plug setting)

Fig. 7.3.1(a) shows the above characteristic at the max. time multiplier

setting of I.O

While standard Inverse Characteristic covers majority of he applications,

very invese characteristic is particularly useful here there is a substantial

reduction in the fault current as the distance from the power source

increases. Extremely Inverse characteristic is particularly suitable in

grading with fuses (the operating time being inversely proportional to the

square of the current, the characteristic eminently matches with the fuse

characteristic). Long Inverse characteristic is primarily used for overload

protection or earth fault protection in resistance grounded systems.

The IDMT relays provide both time and current grading to achieve

discrimination between successive stages in the distribution system.

7.3.2 Grading Margin

The time interval (grading margin) between adjacent relay for selective

operation depends upon following factors.

i) Circuit Breaker tripping time

ii) Over shoot time of the relay

iii) Relay timing errors

iv) Safety Margin

The table below gives typical allowance to be made for the above factors.

FIG. 7.3.1(a).:IDMT CHARACTERISTICS

FIG.7.3.3.1 (a)

EM Relay Static Relay

Timing Error (%) 7.5 5.0

Over Shoot (Sec) 0.05 0.03

Safety Margin (Sec) 0.1 0.05

A suitable grading margin can be calculated as follows:

T2 = (2ER/100) x t + TCB + To + TSM

Where t2 = time interval between adjacent relays

t = Relay nominal operating time

ER = % Timing error as given by manufacturer

TCB = Circuit Breaker tripping time (seconds)

Te = Relay over shoot (seconds)

TSM = Safety Margin (seconds)

Typically a grading margin of 0.3 o 0.4 second is considered adequate.

7.3.3.1 IDMT relays supplemented by High set Instantaneous over

current elements

Particularly on transformer feeders or long distribution feeders connected

to strong sources here there is a substantial reduction in the fault infeed

for faults beyond the protected section, high set instantaneous over

current element is often incorporated with the IDMT over current relay. The

high set element is set over and above the infeeds for fault beyond the

protected equipment/section such that it remains stable for such faults,

while at the same time, offers high speed clearance for close up faults

within the section.

A typical example for High set over current application is given in Fig.

7.3.3.1(a).

H.S. o/c setting at A = 1.3 x 3000

= 3900 Amp (primary)

= 6.5 Amp (secondary)

The relay thus remains stable for faults beyond station, “B”, but would

offer instantaneous clearance for close up faults in section A-B.

The initial fault current may be asymmetrical with slowly decaying d.c.

offset. To enable close setting above the steady sate through fault current,

the highest element should immune to the d.c offset. Such immunity is

defined in terms of transient over reach which should be low. Relays with

less than 5% transient over-reach are available.

The high set unit also improves overall grading as the IDMT relays are now

required to be time coordinated up to highest setting current and not upto

the maximum short circuit current close to relaying point.

7.3.3.2 Directional IDMT Relays

When fault current can flow in both direction at the relay location,

directional IDMT over current/earth fault can be used at an advantage to

ensure selective tripping. Usually a separate directional element is

provided which controls the operation of the IDMT over current relay. The

directional unit is basically a power measuring device in which the relative

direction or phase of the fault current is checked with reference to the

system voltage.

Typical CT/VT input connection and Vector diagram for directional over

current and earth fault relay is shown in Fig. 7.3.3.2 a/b and Fig. 7.3.3.2

c/d.

Referring to A phase element, the voltage coil flux lags the input volts “Vac”

by 45o, whereas the current coil flux is in phase with current IA. Since the

torque is function of Øv x Ø1 sin a, where Øv = voltage coil flux, Ø1 =

current coil flux and a = Angle between the two interacting fluxes,

maximum torque will be produced when a = 90o. The maximum torque

will, therefore be realized when IA lags VA by 45o (IA’). The operational

range of the directional element will be 45o lead to 135o lag as shown in he

vector diagram.

7.3.3.3 Typical Applications of Directional IDMT Relay

Following are the typical application of directional IDMT Relays.

1) Parallel Feeders: Directional relays are used at the receiving end

of he parallel feeders to ensure selective tripping as shown in Fig.

7.3.3.3.1 (a).

FIG. 7.3.3.2(a): Directional O/C relay Quadrature Connection

FIG. 7.3.3.2(b): VECTOR DIG. FOR 45 O LEAD MTA FOR

QUADRATURE

CONNECTION FOR “A” PHASE RELAY.

FIG. 7.3.3.2(c): DIRECTIONAL EARTH FAULT RELAY CONNECTION

FIG. 7.3.3.2(d): VECTOR DIG. FOR DIRECTIOAL E/F RELAY

FIG.7.3.3.3.1 (a): PARALLEL FEEDER PROTECTION.

FIG.7.3.3.3.2 (a)

Referring to the figure above, for a fault on CKT2, while the relay at

Receiving End (B) on CKT2, sees an infeed in its looking direction and

operates, the relay on CKT 1 sees a current flow inn the reverse direction

and restrains. By time coordinating the relays at, A and B, a selective

tripping can be obtained. Besides the directional relays at End “B” are non

responsive to downstream faults and hence do not require any time

coordination with downstream backup, thereby enabling a relatively faster

clearance.

2) Ring Main System: Directional relays are used for Ring Mains. A

typical example is shown in Fig. 7.3.3.2 (a). While the source end station

(A), can have non-directional relays (in view of no possibility of infeed

reversal), the intermediate stations should have directional relays looking

into the feeders.

The time grading can be worked out by considering the rid open at one

side of the supply point, reducing it to radial system and grade from the

tail end. The same procedure can be repeated by opening the grid on the

other side, at the supply point.

Directional IDMT relays are also used on the feeders between Grid supply

and captive supply Bus for selective tripping and improved coordination.

-oOo-

CHAPTER – 8

LINE PROTECTION (DISTANCE SCHEMES)8.1 Introduction

Distance Protection is one of the most extensively used form of protection

for transmission and sub-transmission lines. Distance relay, primarily

measures the impedance of the line between the relaying point and fault

point and compares it with the setting impedance to ascertain whether the

fault is within the zone or outside. Practical distance relays have normally

3 zones of operation – an instantaneous first zone and time delayed

backup zone 2 and 3.

When applied in conjunction with a signaling channel, it provides selective,

high speed protection for he line in question, and also a time delayed

backup to the adjoining lines through its second and third zone, thereby

combining the advantages of a unit as well as non-unit protection.

The heart of a distance protection is a comparator which carries out the

impedance measurement. Several impedance measuring characteristics

are available covering both short and long lines, which are discussed

below.

8.2 Measuring Characteristics

The various measuring characteristics and heir applications are described

below:

8.2.1 Impedance Characteristic (Fig. 8.2.1)

An impedance characteristic is represented by a circle with its center at

the origin on the R-X diagram, and its radius equal to its reach setting.

The characteristic is produced by using an amplitude comparator and does

not take into account the phase relationship between the voltage and

current.

The impedance characteristic is non-directional and is highly susceptible

to power swings and load encroachment because of its larger coverage on

FIG. 8.2.1: IMPEDANCE CHARACTERISTIC

FIG. 8.2.2.1(a): SELF POLARISED MHO CHARACTERISTIC

FIG. 8.2.2.2(a): CROSS POL MHO CHARACTERISTIC

the R-X plane. This characteristic is normally used for fault detection or as

a time delayed backup zone.

8.2.2. MHO Characteristic (Or Directional Impedance Characteristic)

There are three principle variations of MHO characteristic.

a) Self Polarised MHO

b) Cross Polarised MHO

c) Offset MHO

8.2.2.1 Self Polarised MHO (Fig. 8.2.2.1.a)

The self Polarised Mho characteristic is a circle whose circumference

passes through the origin and diameter represents the setting impedance

or Replica Impedance (ZR) at an angle θ.

MHO Characteristic has an angle dependant reach (being maximum along

the setting Impedance angle) and is directional. It is less prone to power

swings/load encroachment due to its restricted coverage on the R-X plane,

particularly along the Resistive Axis.

8.2.2.2 Cross Polarised MHO (Fig. 8.2.2.2a)

The cross polarised Mho characteristic is produced by deriving the

polarizing voltage reference from healthy phase(s). While the

characteristic is directional and has an angle dependant reach, it provides

increased tolerance to fault resistance since the characteristic expands

along the resistive axis for forward, unbalanced faults. This happens due to

the healthy phase polarization.

This characteristic is eminently suitable for short lines tied up to weak

sources where the fault arc resistance may be comparable to line

impedance. The degree of expansion depends upon the source to line

Impedance (ZS/ZL) ratio, being more at higher ZS/ZL ratio. The relay, thus

provides enhanced resistive coverage hen the source is weak or the source

impedance is high.

8.2.2.3 Offset MHO Characteristic

The offset MHO characteristic encloses the origin providing a small

coverage for faults behind the relaying point as shown in Fig. 8.2.2.2(a).

The relay is then said to be having a reverse offset. A forward offset, on

the contrary sets the characteristic away from the origin.

The offset MHO characteristic is used for zone 3 (when provided with

reverse offset) primarily as a back up against Busbar faults. Forward offset

is used for producing certain specially shaped characteristics as indicated

in Fig. 8 described later.

8.2.3 Reactance Characteristic (Fig. 8.2.3.a)

The reactance characteristic is represented by a line parallel to the

Resistive Axis while ZLLØ represents the line impedance, XR represents the

setting Reactance.

The reactance characteristic is ideally suitable for short lines because of

its high resistive coverage. The characteristic is however, non-directional

and requires to be monitored by some directional characteristic, as shown

by he dotted MHO circle in Fig.8.2.3a) when used for distance protection.

Besides the above standard characteristics, there are some shaped

characteristics to cover special applications. These are described below.

8.2.4 Lenticular Characteristic (Fig. 8.2.4a)

The characteristic is called lenticular because of its lens shape. While it

provides the required coverage along the line impedance angle, the

resistive coverage is restricted.

The characteristic is suitable for long over loaded lines and is often used

for Zone 3 where load encroachment problem may be encountered. The

lenticular characteristic invariably has a small reverse coverage.

8.2.5 Figure 8 Characteristic (Fig. 8.2.5a)

The characteristic is produced by two offset MHO circles, the lower one

having a small reverse offset where as the upper circle having a forward

offset. The composite characteristic looks like the figure of 8 and hence

the name. Here again the characteristic limits coverage along the resistive

axis.

FIG. 8.2.2.3(a): OFFSET MHO CHARACTERISTIC

FIG. 8.2.3(a): REACTANCE CHARACTERISTIC

FIG. 8.2.4(a): LENTIC CHARACTERISITC

FIG. 8.2.5(a): FIG.8: CHARACTERISTIC

FIG. 8.2.6(a): QUADRILATERAL CHARACTERISTIC

FIG. 8.3.0(a): TIME DISTANCE CHARACTERISTIC OF A

3 ZONE DISTANCE SCHEME

The characteristic is thus less prone to load encroachment and hence

applied for long lines, evacuating bulk power.

8.2.6 Quadrilateral characteristic (Fig. 8.2.6a)

The characteristic is of the shape of a quadrilateral and fully directional.

Both the resistive and reactive reaches are independently adjustable.

The characteristic is, therefore, ideally suitable for very short lines,

requiring high fault resistance coverage.

8.3 Zones of Protection

Conventional distance relays have normally 3 zones of protection – namely

an instantaneous zone 1 and time delayed zone 2/zone 3. Correct

coordination between distance relays on adjacent lines in a power system,

is achieved by judiciously selecting the reach and time settings of the

various zones. Typical reach and time settings for a 3 zone scheme is

shown in Fig. 8.3.0(a).

Associated time delays Zt – Inst, Z2-t2, Z3-t3.

The settings criteria for various zones is given below:

Zone 1 - 80 – 85% of the protected Section

Zone 2 - Protected section + 50% of shortest adjoining

Section or 120% of the protected section whichever

is greater.

Zone 3 - Protected section + Longest adjoining section.

The zone 1, being instantaneous, is set under-reaching with a margin of

about 15 – 20% to account for possible relay/CT/PT errors and inaccuracies

in the line impedance parameters. The zone 2 is primarily intended to

cover he last 15-20% of the protected section, and hence is set to over-

reach the remote busbars bars with similar margin, to account for possible

under-reaching due to relay/CT/PT errors. The Zone 2 covers up to 50% of

the shortest adjoining section and ensures that it does not overlap with

the zone 2 of adjoining section, thus avoiding coordination problem.

However, if the shortest adjoining section is too short, compared to the

protected section, the margin against possible under-reaching may not be

adequate. In such an eventuality, the zone 2 can be set to cover 120% of

the protected section.

Zone 3 protection is intended as a backup against uncleared external

faults and hence set to cover the longest adjoining line. The zone 3 setting

should, however, be checked against possible load encroachment,

particularly in case of long heavily loaded lines.

8.4 Phase Sequence comparator for MHO characteristic

The MHO characteristic as shown in Fig. 8.2.2.1(a) can be produced by

using a sequence comparator with inputs derived from the current and

voltages from the transmission line. The input for the measuring circuit for

a plain MHO characteristic are V (fault voltage) from the line V.T., and IZ,

from the replica impedance “Z” fed with line current “I” through the

current transformer. The above inputs referred to a single phase system

are shown in Fig. 8.4.0(a).

The voltage IZ is a replica of voltage which would be resented to the relay

for a fault at a location equivalent to its reach point. The reach of the relay

is set by adjusting the relative magnitudes of V and I.Z. and the

characteristic angle is set by adjusting the phase angle of the Replica

Impedance “Z”. The measuring circuit operated by deriving the signals V-

IZ and V-90 o and feeding these to the sequence comparator. If inputs V-

IZ lags V -90o, the fault lies inside the characteristic whereas if V-IZ leads

V -90o the comparator restrains since the fault is external. Signal V -90o

is known as the polarizing signal which provides a reference for comparing

the lag or lead relationship of the other input V-IZ. The MHO characteristic

with the input signals is illustrated in Fig.8.4.0 (b).

8.4.1 Principle of comparator

The above inputs V-IZ and V-90o are sinusoidal quantities of power

frequency denomination. Since the sequence comparator compares only

the lag or lead relationship of the input signals, only phase angle

information and not amplitude of inputs is important. The inputs are,

FIG. 8.4.0(a)

FIG. 8.4.0(b): SEQUENCE COMPARATOR VOLTAGES

FOR MHO CHARACTERISTIC

Therefore, filtered to remove the unwanted frequency components and

then squared, so that they retain the phase angle information of the

original sinusoidal inputs.

To understand the operation of the comparator, the input square wave A

and B, which have either a high or low value can be regarded as logic

variables. If the high and low state of the input signals is represented as A

B and A B respectively, there are four possible combinations of their state

i.e. A B, A B, A B, and A B. if both signals have unity mark space ratio and

equal time periods, the four combinations will occur in a cyclic manner,

with only two possible variations.

If A leads B, the sequence would be A B, A B, A B and A B and if ‘A’ lags

B, the sequence would be A B, A B, A Band A B.

The comparator has a logic circuit which examines the input signals at

every change of state to see which of the two sequence are being followed

and determines whether the same is progressing in a tri or restraint

condition. The circuit can identify a trip or restraint condition from a single

change of state and from any starting point from the cycle. However, a

single change of state may be deceptive, if the input signals are laden

with noise, since noise signals may alter the zero crossings and reverse

the sequence momentarily. Greater security is therefore obtained, if

tripping is conditioned by a number of status changes corresponding to a

trip sequence. The comparator has a counter to determine the number of

status changes. Every acceptable change corresponding to a tri sequence

increments the counter while a change corresponding to restraint

condition decrements the counter to a minimum of zero. The criteria for

operation is usually a count of 3 or 4.

Referring to the figure 8.4.2(a) and (b), the noise signals introduces an

extra pair of zero crossing one adding to the total count and the other

subtracting. After each such interference, the counter is in the same

FIG. 8.4.1: RESTRAI LOGIC SEQUENCES

(a) FOR COMPARATOR

FIG. 8.4.1: OPERATE LOGIC

(b)SEQUENCES FOR COMPARATOR

FIG. 8.4.2(a): BASIC NOISE IMMUNITY

FIG 8.4.2(b) : BASIC NOISE IMMUNITY

Position as before. The comparator, therefore, renders inherent noise

rejection.

8.4.2 Polarising input to the Comparator

The polarising input provides a reference for comparison for the other

input. It is, therefore, imperative that the polarising voltage is always

available irrespective of the location of the fault (close up) and the number

of phases involved.

This is achieved by supplementing the faulted phase input, with either the

healthy phase voltage or memory voltage. While healthy phase voltage

would maintain polarising reference for close up unbalanced faults,

memory polarization caters for symmetrical (3 phase) faults.

The healthy phase or memory polarization eventually produced resistive

expansion of the characteristic, thereby enhancing fault resistance

coverage. The memory signal is usually extended for a substantial length

of time to enable positive operation of the relay on close u three phase

faults.

8.5.0 Additional Features of Distance Relays

The practical distance protection has several standard/optional features,

these are:-

i) Power Swing Blocking

ii) V.T. Supervision and

iii) Switch on to fault.

8.5.1 Power Swing Blocking

Power Swing characterized by cyclic changes in current, voltage and

power, are produced when the induced voltage of generators at different

locations in an interconnected system, slip relative to each other to adjust

to the changes in power transfers (in magnitude and direction) following

system faults. The tandem variations in voltage and current during a

swing, presents a changing impedance to a distance relay, with the

impedance locus moving away from the load area towards the relay

characteristic. The distance relay, is therefore, prone for operation

During a swing and is required to be blocked, to allow the power system,

to return to stable conditions, during recoverable swings.

The principle of power swing blocking is illustrated in Fig. 8.5.1(a).

Considering a Generator (represented by EG, XG) connected to a system

(represented by ES, XS) through a transmission line (Impedance ZL), when

the angle of displacement between EG & ES widens, the impedance moves

towards he relay characteristic. The impedance locus is a perpendicular

bisector of the total impedance line (i.e. XG + ZL + ZS) when EG = ES or

takes a curvilinear path when EG is either greater of less than ES and

shown in Fig. 8.5.1(b).

The detection of power swing is achieved by monitoring the rate of change

of impedance or conversely the time required for the impedance locus to

traverse the impedance gap between the PSB characteristic and the

outermost tripping zone i.e., zone 3. if the time measured is less than the

set time on timer “T”, it is considered as a power swing and blocking is

applied to the selected zones (Fig. 8.5.1c).

Since power swing is a balanced 3 phase phenomena there is no residual

current during a power swing. However, if a residual current is detected,

as would happen during earth faults, following a power swing, power swing

blocking is inhibited, using a neutral current level detector (NCD) as shown

in the logic diagram, (Fig. 8.5.1d). the blocking is effective as long as the

impedance locus stays within the “PSB” characteristic or until a set time

delay, as required.

8.5.2 Voltage Transformer Supervision

Distance relays are primarily voltage restraint relays and would tend to

operate in the event of loss of V.T. supply due to say a blown off

secondary fuse. The condition is therefore, required to be guarded against,

to prevent undesirable operation on load. The V.T. supervision logic used

in practical distance schemes is explained below (Ref. Fig. 8.5.2).

FIG. 8.5.1(a)

FIG. 8.5.1(b)

FIG.8.5.1(c ) IMPEDANCE DIAG

FIG.8.5.1: PSB LOGIC

FIG.8.5.2: VOLTAGE TRANSFORMER SUPERVISION

The VTs logic monitors either Zero Sequence of Negative sequence current

and voltage at the terminal of the relay. Discrimination between a primary

system fault and a blown off P.T. fuse or secondary wiring discrepancy is

obtained by blocking the distance protection only when zero or negative

sequence voltage is detected without the appearance of zero or negative

current, as shown in the logic diagram.

When MCBs are used for controlling the VT supply, an auxiliary contact of

the same is used to block the protection on operation of the MCB. This is

normally done by cutting off the scheme d.c. supply through a normally

open contact of the MCB.

8.5.3 Switch on to fault (SOFT) Feature

As explained before, the polarizing voltage signal is required for the

distance relay under all fault conditions for correct measurement and

directional measurement and directional discrimination. However, the

polarizing voltage signal may completely vanish for a close-up 3 phase

fault. The memory polarization where provided, will certainly help to

maintain the polarizing signal provided he relay has seen a prefault

voltage before. However, when a dead line is energized with its earthling

clamps left inadvertently in position, after a maintenance shutdown and if

the associated distance protection is fed from line voltage transformers,

the memory polarization also will not help for obvious reasons. To guard

against such eventuality, parallel switch-on to fault (SOFT) trip logic is

provided in all distance relays as standard feature, using voltage and

current level detectors, as illustrated in Fig.8.5.3 (a).

The SOFT logic is enabled only after the voltage and current level

detectors of all the 3 phases are in a de-energized status for a preset time

interval, signifying that the line is initially dead. When the line is energized

subsequently with a close-up 3 phase fault already existing the current

level detectors picking up simultaneously. The SOFT trip is thus activated

after a short time delay of about 20 msec. The time delay is provided to

swamp possible difference in the response time of the current

FIG. 8.5.3(a): SIMPLIFIED SOTF TRIP LOGIC

FIG. 8.6.0(a): 3 STEP DISTANCE CHARACTERISTIC

(c) SIMPLIFIED SOLID STATE LOGIC

And voltage level detector (the formal being faster) to permit healthy

switching. Besides, current/voltage level detector, any zone comparator

operation during the initial period of charging, activates SOFT trip,

bypassing time delays associated with the zone 2/zone 3 comparators.

8.6 Carrier Aided Schemes

The distance protection covers about 80-85% of the line in its

instantaneous first zone, the faults in the last. 15-20% being referred to

the delayed zone 2. Thus for end section faults, the clearance is delayed

from the farthest end. This situation cannot be tolerated in an

interconnected system for two reasons.

1. A delayed clearance from one end may cause instability in the

system.

2. When the lines are equipped with high speed auto reclosing, a non-

simultaneous tripping would defeat auto reclosing, since there is no

effective dead time to ensure de-energisation of the fault arc.

The practical distance relays are therefore, interlocked with a signalizing

channel transmit information about the system conditions from one end to

other end to accelerate tripping. The information transmitted can either be

arranged to initiate tripping (on internal fault) of the remote circuit breaker

on block tripping on external fault. The former arrangement is called as

‘transfer trip’ scheme where as latter is termed as ‘blocking’ scheme.

A typical transfer trip (under-reach) scheme logic is illustrated in Fig. 8.6.0

(a & b).

Referring to Fig.8.6.0, for fault close to end ‘B’ the relay at end B will trip in

zone 1 and simultaneously initiate an inter trip signal to end ‘A’. When the

signal is received at end ‘A’ and if the over-reaching zone 2 measuring

element has also operated, end ‘A’ will trip in ‘Carrier Aided Trip’ mode,

resulting a near simultaneous clearance of the fault from both ends.

The different variations of carrier schemes are:

Permissive under-reach transfer trip (PUR)

Permissive over-reach transfer trip (POR)

Acceleration

Blocking

While inter-trip schemes (PUR, POR, Acceleration) are fast in operation,

blocking scheme has an international delay to allow for the blocking signal

to be received for an external fault. However, blocking scheme does not

suffer from signal attenuation since the signal is transmitted over a healthy

line unlike in case of a transfer trip scheme where the signal is transmitted

on a faulty line.

-000-

CHAPTER –9

CURRENT AND VOLTAGE TRANSFORMER

9.1 Introduction

The magnitude of current and voltage in a power circuits are

usually too high to be handled by the secondary equipments like

measuring instruments and relays. The instrument transformers are

therefore, used as input devices which produce a scaled down

replica of the primary input quantities within the required accuracy,

for connecting the secondary equipments.

While the instrument transformers used for measurement purpose

handle steady state quantities close to the rated values, those used

for protection, handle fault quantities which are affected by d.c.

transients, harmonic distortions etc. the performance requirements

of the instrument transformers are therefore at variance depending

upon their applications.

9.2 Current Transformers

9.2.1 Equivalent Circuit and vector Diagram

a) Ratio Error

It is defined as the difference in magnitude of the primary

and secondary current expressed as percentage of the

primary current.

Thus % Ratio Error = X 100

b) Phase Angle

This is the phase angle difference between the primary

current and the reversed secondary current vector.

c) Composite Error

This is defined as the R.M.S value of the difference (Kn Is-Ip)

integrated over one cycle under steady state conditions

expressed as a percentage of RMS primary current. Thus,

FIG. 9.2.1

Composite error Eo -= : :’ (Kn Is – Ip)2 .dt

Where T = Duration of 1 cycle.

Ip, Is – Instantaneous values of primary and sec. Currents.

Kn – Rated transformation ratio

Ip – Primary current 9RMS)

9.2.3 Magnetizing Characteristic of CT

The magnetizing characteristic of a C.T. is a plot between the secondary

applied voltage and the corresponding magnetizing current taken by the

C.T. as shown in Fig. 9.2.3.

The excitation curve can be divided into 4 regions. Ankle point, Linear

region, knee point and saturation. The knee point is defined as a point on

the excitation curve where a 10% increase in secondary EMF would cause

50% increase in the exciting current.

9.2.4 Effect of Secondary Open Circuiting

The primary current of a C.T. is independent of its secondary loading. With

the secondary shorted (directly or through the connected burden) the

counter flux produced by the secondary keeps the core flux below the

saturation level. However, if the secondary gets open circuited with the

primary carrying current, the entire primary m.m.f. (ampere turns) is spent

Knxls – Ip

Ip

100 Ip

IT