Modern Power System Protective Relay REV04

Contents

Section 1 Power System Faults

Section 2

Components of Protection

Schemes

Section 3 Current Transformers & Voltage

Sect o 3

Cu e t

a s o

e s & Vo tage

Transformers

Section 4

Power System Neutral Grounding

Section 4 Power System Neutral Grounding

Section 6 Coordination of Protection

Section 7 Bus Protection

Section 8 Motor Protection, Starting &

Control

Control

Section 9 Transformer Protection

S

i

10 G

P

i

Section 10 Generator Protection

Section 1

Section 1

Power System Faults

Section 1

Power System Faults

¾ Incidence of Faults on Power System ¾ Incidence of Faults on Power System

Equipment.

¾ Effects of Power System Faults. ¾ Magnitude of Fault Current.

¾ Detection of Faults.

¾ Requirements of Protective Relaying ¾ Requirements of Protective Relaying

Systems (Selectivity ,Dependability

,Reliability ,speed).

¾ Clearance of Faults.

Power System Faults

A

t

f lt i th b

kd

A power system fault is the breakdown

of insulation(between conductors or

b t

h

d t

d

between

a

phase

conductor

and

ground) which results in excess current

flflow.

Types of Faults

On a Three Phase power system the

On a Three-Phase power system the

principal types of faults are:

) Ph

G

d (

Si l Ph

)

a) Phase-to-Ground (or Single Phase)

b) Phase-to-Phase (or Two-Phase)

c)

Phase-to-Phase-to-Ground

(or

Two

Phase-to-Ground))

T

f F

lt

Types of Faults

Sometimes, these faults are accompanied by a broken conductor, or may even take the form of a broken conductor without a ground connection

connection.

This results in an open-circuit condition. Because no ‘fault current’ flows for this Because no fault current flows for this condition, the open-circuit fault is difficult to detect. The open-circuit does, of course,p , ,

cause severe unbalance on the power system, and can cause overheating in generators.

Types of Faults

The generatorsg must be equipped withq pp protection schemes to detect such unbalances (or negative phase sequence) conditions.

This will be covered later under ‘Generator Protection’.Generators, transformers and

t bj t t h t i it b t

motors are subject to short-circuits between turns of the same winding.

Types of Faults

On overhead transmission lines the insulation that breaks down is air.

When such a fault occurs there is a flashover or arc(often along the surface of an insulator string).

If th f lt i l d i kl t

If the fault is cleared quickly, no permanent damage results, and the transmission line can immediately be put back into service

Types of Faults

When faults occur in Transformers, Generators,, , Motors and Cables, permanent damage usually

results. Such faults are usually caused by mechanical failure of solid insulation, or in the case of transformers, contamination of the insulating oil For SF6 insulated equipment insulating oil. For SF6 insulated equipment, faults are often the result of contamination of the SF6 gas by solid particles

I

id

f F

lt

P

Incidence of Faults on Power

System Equipment:-

y

q p

i. 500kV Lines - 1.3 Faults per year per 100 Miles i. 500kV Lines 1.3 Faults per year per 100 Miles ii. 230kV Lines - 4 Faults per year per 100 Miles iii. 115kV Lines - 14 Faults per year per 100 Milesp y p

Incidence of Faults on Power System

Equipment:-For 44kV 33kV and 25kV feeders the figures

For 44kV, 33kV and 25kV feeders the figures

are proportionally higher. The relationship

between the number of overhead power

p

system faults and the voltage level can be

explained as follows:

By far the most common type of power

By far the most common type of power

system fault is the flashover of insulators on

overhead transmission lines, due to lightning.

Th

b

f f lt

i

ti

l

The number of faults per year is proportional

to the length, and is approximately inversely

proportional to the voltage level.

Incidence of Faults on Power System

Equipment:-I

id

f F

lt

P

S t

Incidence of Faults on Power System

Equipment:-If li ht i t ik th d d hi ldi If lightning strikes the grounded shielding

conductor, or tower, and causes 100,000 amps to flow to ground through a tower with a to flow to ground through a tower with a footing resistance of 1 OHM, then a voltage of 100,000 Volts to ground is developed.

A flashover of an insulator from the tower cross arm to a phase conductor may then occur It will most likely occur on the phase occur. It will most likely occur on the phase with the highest voltage difference to the voltage transient developed by the lightning strike.

Incidence of Faults on Power System

Equipment

Incidence of Faults on Power System

Equipment:

The most common causes of faults on overhead lines are:

1) Li ht i 1) Lightning

2) Contaminated Insulators

3) P t d b k i l t

3) Punctured or broken insulators 4) Birds and animals

5) Aircraft and cars hitting lines and structures 5) Aircraft and cars hitting lines and structures 6) Ice and snow loading

7) Wind 7) Wind

Incidence of Faults on Power System

Equipment:

In electrical machines, cables and transformers, In electrical machines, cables and transformers,

faults are caused by:

1) Failure of insulation because of moisture.) 2) Mechanical damage.

3) Flashover caused by overvoltage or 3) Flashover caused by overvoltage or

abnormal loading.g

Incidence of Faults on Power System

Equipment:

On transformers with external bushings, the most common cause of faults, particularly on the lowerp y voltage levels of 33 kV and below, is small animals. They contact the 33 kV connections and cause flashovers across the bushings, external to the transformer. Permanent faults within the transformer tanks occur approximately at the rate of one fault every 10 years per transformer.

Effects of Power System Faults:

t i t i t

transient in nature:

i.e. flashover of insulators which does not result in permanent damage

result in permanent damage.

With such faults, the line can be restored to service immediately after the breakers have service immediately after the breakers have tripped.

Effects of Power System Faults:

normally used on the circuit breakers normally used on the circuit breakers associated with overhead transmission lines or feeders. If the fault current is interrupted by the feeders. If the fault current is interrupted by the circuit breakers, the ‘flashover’ arc is

immediately extinguished and the ionized air

dissipates. Auto-reclose will normally be successful after a delay of only a few cycles.

Effects of Power System Faults:

On typical 44kV and 33kV overhead distribution systems there is an intentional delay of 0.5y y seconds before the breaker is auto-reclosed after a feeder fault.

O t i l 500kV d 230 kV t i i On typical 500kV and 230 kV transmission

systems there is a 10 second intentional time delay before auto-reclosing after a fault This time delay before auto reclosing after a fault. This time delay is to help maintain system stability by not subjecting the power system to two faults in quick succession.

Effects of Power System Faults:

Faults in generators, motors, transformers and cables etc. are normally permanent andy AUTO-RECLOSE is not used. Such faults require the equipment to be taken out of

i f t f th d d

service for an assessment of the damage and repair.

Effects of Power System Faults:

When a fault occurs, a very large current normally flows This fault current if allowed normally flows. This fault current, if allowed to persist, will cause damage to equipment. On an interconnected H.V. transmission system, an un-cleared fault can cause instability and system collapse:

i.e. A ‘blackout’ over a very large area. Faults must therefore be cleared in the

h t t ti ibl

Magnitude of Fault Current:

g

For a power system fault, the magnitude of the fault current is determined by the impedance of the power system between the source of generation and the location of the source of generation, and the location of the fault.

Magnitude of Fault Current:

On large interconnected H V power systems the On large interconnected H.V. power systems the buses of large switching stations can be considered as infinite buses. When calculating the fault current on a line or feeder supplied from an infinite bus, we assume that the voltage remains constant at the bus and the only factor to limit the constant at the bus, and the only factor to limit the fault current, for phase faults, is the impedance of the line between the fault and the bus. For Phase-to-ground faults it is the impedance of the line

from the bus to the fault, plus the impedance of the ground return

Magnitude of Fault Current

Magnitude of Fault Current

The fault current on a distribution system feeder, fed from a transformer station, is determined by the H V supply line determined by the H.V. supply line impedance, plus the transformer impedance, plus the impedance of the impedance, plus the impedance of the feeder up to the fault.

Magnitude of Fault Current

Magnitude of Fault Current

NOTE:

NOTE:

For almost all faults, flashover occurs. The resistance of the resulting arc is nearly

l li ibl i t th

always negligible comparison to the impedance of the line conductors.

Magnitude of Fault Current:

The star points of transformer windings are often grounded through a resistor or a reactor. This has the effect of limiting the ground fault current on the feeders

ground fault current on the feeders.

The procedure for calculating the maximum

fault current (short circuit calculation) is given fault current (short-circuit calculation) is given

at the end of this section, with a worked example.p

Detection of Faults

Detection of Faults

All power system elements are equipped withp y q pp one or more protection schemes. The purpose of these protection schemes is to detect faults on the system When the detect faults on the system. When the protective relays have detected a fault, they send trip signals to the circuit breaker orp g breakers, which in turn clear the fault from the system.

Requirements of Protective Relaying Systems: 1- SELECTIVE

Protective relaying schemes must be able to discriminate between faults on the protected

discriminate between faults on the protected system element, and those on adjacent elements.

Hence, only faulted elements are tripped from the power system and all healthy elements stay in power system, and all healthy elements stay in service.

This is particularly important on an interconnected transmission system If a faulted element is transmission system. If a faulted element is tripped, then the load carried by that element (transformer or line) is automatically transferred to a parallel element or elements If one or more of a parallel element or elements. If one or more of these adjacent elements trip “in sympathy” with the faulted element, then major power interruptions will result.

Requirements of Protective Relaying Systems: Requirements of Protective Relaying Systems:

2- DEPENDABILITY AND RELIABILITY

Protective relaying schemes must be very dependable and reliable. all power system faults must be detected and cleared quickly

and cleared quickly.

On high voltage interconnected transmission systems, an un cleared or slow clearing fault can easily lead to a power system collapse. Such power system collapses occurred in Ontario and the North Eastern U.S.A. in 1965, and again in August 2003., g g

3 HIGH SPEED

3-HIGH SPEED

Hi h d f lt l i ti l

High speed fault clearance is essential on interconnected transmission systems.

By high speed we mean less than 0 1 seconds By high speed we mean less than 0.1 seconds.

On 500 kV and 230 kV systems faults are normally cleared in 3 or 4 cycles, or 50 to 80 milli-seconds.y

Clearance of Faults

On distribution systems, which are usually radialy , y in nature, slower fault clearance times are permissible.

TIME GRADED over current protection is often TIME-GRADED over current protection is often

used for fault clearance.

i.e. For high fault currents, there is fast clearance. For lower fault currents, the fault clearance time is much slower.

The operating time of circuit breakers on The operating time of circuit breakers on distribution systems is typically 5 to 7 cycles, or 100 to 140 milliseconds.

Procedure For Calculating Maximum

Fault Current(Short Circuit

(

Calculation)

The general procedure for calculating the faultg p g current for a fault at a particular point on a power system is as follows:

1 D i l li di f th

1. Draw a single-line diagram of the power system.

2 Collect detailed impedance data for all of the 2. Collect detailed impedance data for all of the

components of the power system. i.e.

Resistance R & Reactance X

Resistance R & Reactance X.

3. Although fault current can be calculated using the

ohmic method, it is usually simpler to use the Per-Unit

M h d h ll f h i d f d

Method where all of the impedances are referred to an arbitrarily chosen common BASE MVA.

4 Convert all of the various impedances to per unit 4. Convert all of the various impedances to per-unit

values with a common base MVA.

5 Fi d th t t l R i t R d R t X f

5.Find the total Resistance R, and Reactance X, from the source to the fault.

Z Z √ R

_X

7. 

_:

FAULTCURRENT

_:

Calculate the PHASE-TO PHASE FAULT CURRENT

8.

9. For low-voltage distribution systems where there is a i ifi t t l d th t t ib ti t th significant motor load, the motor contribution to the fault can be approximated as:

Symmetrical Contribution

_{= 4 times Motor Full}

_{= 4 times Motor Full}

Load

5 ti

M t

Current Asymmetrical Contribution =

_{5 times Motor}

Section 2

C

Components

f

of

Protection Schemes

Protection Schemes

Section 2 Components of Protection Schemes

1. Fault Detecting or Measuring Relays 2. Tripping and other Auxiliary Relays 3. Circuit Breakers

4. Current Transformers 5. Voltage transformers

Components of Protection Schemes:

Each power system protection scheme is made up from

th f ll i t

the following components:

1. Fault Detecting or Measuring Relays 2 Tripping and other Auxiliary Relays 2. Tripping and other Auxiliary Relays 3. Circuit Breakers

4. Current Transformers 5. Voltage transformers

(Voltage transformers are not required in all protection

h )

schemes).

The function of these components is illustrated below for a simple overcurrent protection scheme:

Fault Detecting Relays:

Fault detecting, or Sensing relays monitor powerg, g y p system AC quantities such as current, voltage, and frequency.

They are set to operate, and initiate tripping, when a fault condition is detected.

Th t f lt d t ti l i

The most common fault detecting relays in use are over current relays. There are two basic types of over current relays. These are the instantaneousy over current relay and the timed over current relay.

Fault Detecting Relays

Fault Detecting Relays

A. Instantaneous Over current Relays

Th l t i k t ifi l f

These relays operate, or pick-up at a specific value of current, with no intentional time delay. The pick-up setting is usually adjustable by means of a dial, or by plug settings. Until a few years ago, all instantaneous Over current relays were of electro-mechanical construction.

They were attracted armature types, where the C.T. secondary current is passed through the relay coil, thus attracting the armature against spring tension thus attracting the armature against spring tension. The movement of the armature causes the relay tripping contact to close.

Fault Detecting Relays

In recent years, electronic versions of the

y

,

instantaneous Over current relay have

been introduced. On these relays the

y

pick-up setting is usually adjusted by a

dial or by setting DIP switches. Both the

y

g

electromechanical and the electronic

versions are functionally identical.

y

Timed Over current Relays

The electro-mechanical version of this

relay has an induction disc. The disc must

rotate through a definite sector before the

g

tripping contacts are closed. This type of

relay is known as the

y

definite time relay is

i

O

Timed Over current Relays:

The relay characteristic is such that for

very high fault currents the relay will

very high fault currents, the relay will

operate in it’s

.

For lower values of fault current the

t ti

i l

F

l

t

operate time is longer. For example, at a

relay current of 16 Amps, the operating

time is 0.4 seconds. The relay has a

y

definite minimum

than the maximum load on the

than the maximum load on the

feeder. The induction disc relay normally

has various current tap settings, and an

adjustable time dial

Timed Over current Relays:

This gives the relay a very wide range of setting This gives the relay a very wide range of setting characteristics, and allows the relay setting to be coordinated with other protection devices, such as fuses on adjacent power system such as fuses, on adjacent power system elements. As with the instantaneous over current relays, there are now many _electronic

timed and Inverse Definite Minimum Time Over timed and Inverse Definite Minimum Time Over current relays on the market.

Their characteristics are very similar to the electro mechanical versions. Many Over current relays have an instantaneous element, and a timed element, both built into the same relay case.

The application of over current relays to feeder protection will be covered later in this seminar. protection will be covered later in this seminar.

Timed Over current Relays

Other fault detecting relays that are commonly used in protection schemes are:

used in protection schemes are:

1. Overvoltage and undervoltage relays 2. Impedance relays

2. Impedance relays 3. Differential relays

1 Overvoltage and undervoltage relays 1. Overvoltage and undervoltage relays

These AC relays are normally supplied from These AC relays are normally supplied from voltage transformers, and are set to operate for certain overvoltage or under-voltage conditions. For example, to protect capacitor banks from overvoltage, or to detect under-voltage conditions on a feeder protection voltage conditions on a feeder protection with auto-reclose.

2. Impedance relays

Impedance relays are supplied from both the C.T. current and the V.T. voltage. They measure C cu e t a d t e o tage ey easu e the line impedance by utilizing the line current and voltage, to detect a fault condition. Impedance relays are used on transmission lines and feeders where there is an infeed from both ends

3. Differential relays

Differential relays are used in Bus Protection and Transformer Protection schemes. They compare

th t t i d l i th t t d the current entering and leaving the protected zone. If the unbalance is great enough, then a fault condition is detected and tripping is initiated fault condition is detected, and tripping is initiated. For transformers, the differential relay must have some biasingg to provide relay restraint forp y throughg currents

.

Timed Over current Relays

y

Other fault detecting relays include those used in Generator Protections, such as Negative in Generator Protections, such as Negative Phase Sequence, Over excitation, Loss of Field, Under frequency, Out-of step, etc.

The application of the various relays to power system protection schemes, will be discussed l t i th i

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays:

U til j t f l t ll t ti Until just a few years ago, almost all protective

relays were electro-mechanical, and many of these relays changed very little over a period ofy g y p 50 years or more. A good example is the

induction disc over current relay which is still used

extensively and has given many many years of extensively and has given many, many years of reliable service. In the early 1970’s electronic relays were introduced. These relays used di t lid t t l t i t d discreet solid state electronic components, and required external DC power supplies.

i i f i

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays:

Th f f th l l t i l

The performance of these early electronic relays was poor, as there was a high failure rate of electronic components.

It appeared that some of the electronic components were It appeared that some of the electronic components were being damaged by the spikes and transients that existed in the hostile electrical environment of high-voltage substations.

These early solid state relays offered few advantages over the electro-mechanical relays. They had essentially the same features, but had the disadvantages that they

i d t l d th ld t

required a separate power supply, and they could not match the reliability of electro-mechanical relays.

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays

Th f f lid l i l dil

The performance of solid state electronic relays steadily improved over the years, and by the end of the 1980’s they had gained wide acceptance, particularly overy g p , p y current relays which are used extensively. However, electronic relays have still not gained universal acceptance even though they are cheaper and more acceptance, even though they are cheaper and more versatile than their electro-mechanical counterparts. Relay manufacturers are still supplying thousands of

i d i di l h ill

induction-disc over current relays to customers who still prefer these robust relays which have many, many years of proven reliability.

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays Since about 1992 there has been a revolution

in protective relaying as microprocessor-based relays were introduced As well as the basic relays were introduced. As well as the basic protection function, these relays typically provide many additional features

provide many additional features.

They can be interfaced with computers and provide metering data, fault data (wave-form,

p g , ( ,

maximum fault current, tripping time), sequence-of events, etc.

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays

Microprocessor-based relays are gaining

very rapid acceptance by many electrical

utilities, and they are revolutionizing the

way

that

high-voltage

substation

protection, control and monitoring is

applied. We will discuss

microprocessor-based relays and their various features

later in the seminar.

Tripping and Other Auxiliary Relays

Power system faults are detected by the fault detecting relays, which close their output contacts to initiate tripping These o tp t contacts are sed to initiate tripping. These output contacts are used to energize trip relays and other auxiliary relays which are normally supplied from the station battery DC supply

supply.

These auxiliary relays may perform a number of functions, such as:

9 Trip the associated circuit breaker or breakers 9 Trip the associated circuit breaker or breakers

9 Send a trip signal to the remote terminal of the line 9 Initiate Auto-reclosing of the circuit breaker

9 I iti t B k F il t ti 9 Initiate Breaker Failure protection

Ci

it B

k

Circuit Breakers

The circuit breaker is the device that actually i t t th fl f f lt t d i l t interrupts the flow of fault current, and isolates the faulted element (feeder, transformer, etc.) from the remaining healthy components of theg y p power system. The circuit breaker rating must be high enough for it to interrupt the maximum f lt t th t i ibl t fl

Circuit Breakers

A typical 230kV circuit breaker rating is 70

kA or 25GVA (25,000MVA). As stated

li

i

it b

k

t b

bl

f

earlier, circuit breakers must be capable of

interrupting the fault current in very short

periods of time. Typical circuit breaker

p

yp

operating times are:

9

500 kV - 2 cycles or 40 milli-seconds (50

H

t

)

Hz system)

9

230 kV - 3 cycles or 60 milli-seconds (50

Hz system)

Hz system)

9

33 kV - 6 cycles or 120 milli-seconds (50

Hz system)

Circuit Breakers

Circuit Breakers

These are the times from when the trip signal is t t th b k t h th f lt t i sent to the breaker, to when the fault current is interrupted.

Almost all high voltage circuit breakers that are Almost all high-voltage circuit breakers that are being built today are either SF6 Breakers or Vacuum Breakers. SF6 circuit breakers may be Air-insulated for outdoor installations, or SF6 Gas-insulated for indoor installations.

Circuit Breakers

Circuit Breaker Types

B lk Oil

Bulk Oil

Air

Minimum Oil

Air Blast

Air Blast

Sulphur Hexafluoride or SF6

V

Vacuum

Current Transformers

Current Transformers, or C.T.’s, are used to step down the power system primary currents, from many hundreds or thousands of AMPS, to

bl l t l l It i

more manageable values to supply relays. It is necessary for the C.T. to provide insulation between the power system primary voltage between the power system primary voltage, and the relay circuit. A typical C.T. with a ratio of 1200 : 5A for a 44kV power system is shownp y next.

Current Transformers

Note that the C.T. polarity markings are shown as spots on the primary and secondary sides of the C.T. Also, it is important that the C.T. secondary

i it b d d d d d t i t

circuit be grounded, and grounded at one point only.

C

f

Current Transformers

The most common type of C.T. construction is the

(doughnut) type. It is constructed of an iron toroid, (doughnut) type. It is constructed of an iron toroid,

which forms the core of the transformer, and is wound with secondary turns.

The (doughnut) fits over the primary conductor

The (doughnut) fits over the primary conductor,

which constitutes one primary turn. If the toroid is wound with 240 secondary turns, then the ratio of the C.T. is 240: 1, or 1200 : 5A

the C.T. is 240: 1, or 1200 : 5A

The continuous rating of the secondary winding is normally 5 amps in North America, and 1 amp or 0 5 amp in many other parts of the world The 0.5 amp in many other parts of the world. The various types of C.T. construction will be described later.

Voltage Transformers

Voltage Transformers

Voltage Transformers are used to step the power system primary voltage from say 50 kV power system primary voltage from, say 50 kV or 25 kV to 120 volts phase-to-phase, or 69 volts phase-to-ground. It is this secondary voltage that is applied to the fault detecting relays, and meters.

The voltage transformers at primary voltages The voltage transformers at primary voltages of up to about 100 kV are normally of the wound type. That is, a two winding transformeryp g in an oil filled steel tank, with a turns ratio of say 417:1(50Kv/120V) or 275:1(33Kv/120V).

Voltage Transformers

On higher voltage systems, such as 230kV and g g y , 500kV, Capacitor Voltage Transformers, (or

CVTs) are normally used.

A CVT is comprised of a capacitor divider made up from 10 equal capacitors, connected in series ffrom the phase conductor to ground, with a

voltage transformer connected across the bottom capacitor

bottom capacitor.

This V.T. actually measures one-tenth of the line voltage as illustrated in the below diagram

End of this

Section

Section 3

Section 3

Current Transformers 

&

Section 3 Current Transformers & Voltage  Transformers Transformers

™Types of C.T. and V.T. Construction.

™Voltage Transformers.

™Current Transformer Theory & Characteristics.

™C.T. Accuracy.

™C.T & V.T. Accuracy.

™Testing of Current Transformers:‐

1 C T R ti T t

1-C.T. Ratio Test.

2-C.T. Polarity Test.

3 Secondary Winding Resistance

3- Secondary Winding Resistance.

4-Secondary Winding Insulation Resistance.

™Testing of Voltage Transformers

™Testing of Voltage Transformers

™

_{Same tests}

Current Transformers & Voltage Transformers Types of C.T. and V.T. Construction

The most common type of C.T. construction is the ‘doughnut’ type. It is constructed of an iron

َ

toroid (يقَلح), which forms the core of the transformer, and is wound with secondary turns

Current Transformers & Voltage Transformers

The ‘doughnut’ fits over the primary conductor, which constitutes one primary turn. If the toroid is wound with 240 secondary turns, then the

ratio of the C.T. is 240: 1 or 1200 : 5A

The continuous rating of the secondary winding is normally

_{5 AMPS in North America,}

_and

₁

AMP

0 5 AMP i

h

f h

AMP or 0.5 AMP in many other parts of the

world

.

Current Transformers & Voltage Transformers

This type of ‘doughnut’ C.T. is most commonly used in circuit breakers and transformers. The C.T. fits into the bushing ‘turret’(جرب), and the porcelain bushing fits through the centre of the

‘ ’ f C ’ f

‘doughnut’. Up to four C.T.’s of this type can be installed around each bushing of an oil circuit breaker This arrangement is shown in the breaker. This arrangement is shown in the following diagram

Current Transformers & Voltage Transformers

A similar type of C.T. can be fitted over low

yp

voltage Bus work. However, the C.T. must

be insulated for the primary voltage level.

Current Transformers & Voltage Transformers Current Transformers & Voltage Transformers

The straight-through type of construction is shown below:

The second kind of Free-Standing or Post type current transformer is the Hairpin construction as shown above.

Current Transformers & Voltage

Transformers

The other principal type of C.T. construction is the Free Standing, or Post type. These can be eitherg y Straight-Through or Hairpin construction.

The toroid, wound with secondary turns, is located in the live tank at the top of the C.T. High voltagep g g insulation must, of course, be provided, between the H.V. primary conductor, and the secondary winding, which operates at essentially groundg, p y g potential. Current transformers of this type are often used at voltage levels of 44 kV, 33kV, and 13.8 kV.

Current Transformers & Voltage Transformers

The HAIRPIN C T gets it’s name from the shape of the The HAIRPIN C.T. gets it s name from the shape of the primary conductor within the porcelain. With this type, the tank housing the toroid is at ground potential.

The primary conductor is insulated for the full line The primary conductor is insulated for the full line voltage as it passes into the tank and through the toroid. Current transformers of this type are commonly used on H.V. transmission systems at voltage levels ofy g 500kV and 230kV.

Free standing current transformers are very expensive, and are only used where it is not possiblep , y p to install ‘Doughnut’ C.T.’s in Oil Breakers or transformer bushing turrets.

Current Transformers & Voltage Transformers

As an example C T ’s cannot easily be As an example, C.T. s cannot easily be accommodated in Air Blast circuit breakers, or some outdoor SF6 breakers.

Free Standing current transformers must therefore be used with these types of switchgear.

Current transformers often have multiple ratios. This is achieved by having taps on various points of the secondary winding to provide the different of the secondary winding, to provide the different turns ratios. Later in this section we will discuss the characteristics and testing of C.T.’s.

V lt T f

Voltage Transformers

Voltage Transformers are used to step the power system primary voltage from say 50 kV or 33 kV system primary voltage from, say 50 kV or 33 kV to 120 volts phase, or 69 volts phase-to-ground. It is this secondary voltage that is applied t th f lt d t ti l d t

to the fault detecting relays, and meters.

The voltage transformers at these primary voltages of 50 kV and 33 kV are normally of the WOUND of 50 kV and 33 kV are normally of the WOUND type. That is, a two winding transformer in an oil filled steel tank, with a turns ratio of 416.6:1 or 275:1 On higher voltage systems such as 230kV 275:1. On higher voltage systems, such as 230kV and 500kV, CAPACITOR VOLTAGE TRANSFORMERS, (or CVT’s) are normally used.

Voltage Transformers

A CVT is comprised of a capacitor divider madep p up from typically 10 equal capacitors, connected in series from the phase conductor to ground, with a voltage transformer connected across the bottom capacitor. This V T act all meas res one tenth of the line V.T. actually measures one-tenth of the line voltage, as illustrated in the diagram above.

Current Transformer Theory & Characteristics Current Transformers for protective relaying

purposes must reproduce the primary current purposes must reproduce the primary current accurately for all expected fault currents.

If we have a 33 kV C.T. with a ratio of 1200:5A,

h d i di i i l d f

the secondary winding is continuously rated for 5 Amps. If the maximum fault current that can flow through the C.T. is 12,000 Amps, then theg , p , C.T. must accurately produce a secondary current of 50 Amps to flow through the relay during this fault condition. This current will, of during this fault condition. This current will, of course, flow for only about 0.2 seconds, until the fault current is interrupted by the tripping of the circuit breaker

Current Transformer Theory & Characteristics

The C.T. must be designed such that the irong core does not saturate for currents below the maximum fault current. A magnetizing, or

f C

Current Transformer Theory & Characteristics Current Transformer Theory & Characteristics

For this C.T. to operate satisfactorily at

For this C.T. to operate satisfactorily at

maximum fault currents, it must operate on

the linear part of the magnetizing curve.

i

B l

th

i t

t

hi h

t

ti

i.e. Below the point at which saturation

occurs, which is known as the KNEE POINT.

The KNEE POINT is defined as the point at

p

which a

.

The point on the magnetizing curve at which

The point on the magnetizing curve at which

the C.T. operates is dependent upon the

resistance of the C.T. secondary circuit, as

y

shown next

Current Transformer Theory & Characteristics

In this example the resistance of the C.T. secondary circuit, or C.T. burden is:

C.T. Secondary Winding Resistance = 1 OHM Resistance of Cable from C.T. to Relay = 2 OHMS Resistance of Relay Coil = 2 OHMS Total Resistance of C.T. Secondary Circuit = 5 OHMS

Current Transformer Theory & Characteristics

If the fault current is 12,000 Amps, and the C.T. ratio is 1200:5A, then the C.T. secondary

t i 50 A At thi d t

current is 50 Amps. At this secondary current and the above C.T. burden of 5 OHMS, the C T must produce a terminal voltage of 250 C.T. must produce a terminal voltage of 250 volts. For the C.T. to operate with good accuracy, without saturating for the maximum accuracy, without saturating for the maximum fault current, the knee point must be well above 250 volts.

C f & C i i Current Transformer Theory & Characteristics

It is usual practice to select a C.T. with a magnetizingg g characteristic such that the maximum terminal voltage under steady state conditions, does not exceed 50% of the knee point voltage. This allows an adequate margin for

p g q g

remnant flux in the core, and for transient conditions.

The importance of the C T maintaining good The importance of the C.T. maintaining good accuracy, and not saturating at the maximum fault current, is most critical on differential protection This will be covered later in the protection. This will be covered later in the course when we discuss Bus Protection and Transformer Protection.

Current Transformer Theory & Characteristics

When C.T.’s are used for metering purposes, they must have a high degree of accuracy only at must have a high degree of accuracy only at LOAD currents. i.e. 0 to 5 Amps secondary. There is no need for a high degree of accuracy for fault

t d it i it t bl f t i currents, and it is quite acceptable for a metering C.T. to saturate when fault current flows through it. A C T for protective relaying purposes may typically A C.T for protective relaying purposes may typically have a KNEE POINT at 500 volts, whereas a metering C.T may saturate at well below 100 volts.

CAUTION:

When C T ’s are in service they MUST have

When C.T. s are in service they MUST have

a continuous circuit connected across the

secondary terminals. If the C.T. secondary

i

‘

i

i ’

hil

i

i

is ‘open circuit’ whilst primary current is

flowing, dangerously high voltages will

appear across the C.T secondary terminals.

appear across the C.T secondary terminals.

Extreme care must be exercised when

performing ‘on load’ tests on C.T. circuits, to

ensure that a C T is not inadvertently ‘open

ensure that a C.T. is not inadvertently open

circuited’.

C.T. Accuracy

A typical protective relaying C.T. has it’s accuracy ifi d

specified as:

Thi t ti l i C T h f

This protective relaying C.T. has an accuracy of 2.5% and the excitation curve knee-point voltage is 800 Volts.

C.T & V.T. Accuracy

CURRENT TRANSFORMERS

A typical current transformer for protective relaying purposes on high voltage transmission systems may have an accuracy rating of 2 5% For industrial may have an accuracy rating of 2.5%. For industrial protective relaying systems accuracy ratings of up to 10% are common.

Th i d i t ti l tti it i

The margins used in protection relay setting criteria are usually quite large, and 2.5% to 10% accuracy is adequate - provided the C.T. maintains thisq p accuracy for all fault currents up to the maximum possible fault current.

C & A

C.T & V.T. Accuracy

A current transformer for metering purposes may typically have an accuracy of 0.3%. The C.T. mustyp ca y a e a accu acy o 0 3% e C us maintain this accuracy for normal load currents, provided the rated burden on the C.T. is not exceeded. It is quite acceptable, and in factq p , desirable, for the C.T. to saturate when fault current flows. The accuracy for a typical metering C.T. is specified as:p

This metering C.T. has an accuracy of 0.3% when the connected burden does not exceed 0.9 OHMS.

Voltage Transformers

The accuracy for a typical voltage transformer is specified as:

This voltage transformer has an accuracy of 0.6% with a connected burden that does not exceed 200 VA The connected burden that does not exceed 200 VA. The various burden ratings are represented by letters as follows:

Future Trends in C.T. Design Using Optics

Free-standing C T ’s for high-voltage power Free-standing C.T. s for high-voltage power systems, such as 230 kV and 500 kV, are huge structures and are very expensive. Many manufacturers are developing optical current manufacturers are developing optical current transducers, or optical current transformers.

These units clamp around the primary conductors and supply the output signals to the relays etc and supply the output signals to the relays, etc. through fibre optic cables. Some proto-type optical current transducers are in-service at various locations and it is expected that this development locations, and it is expected that this development will lead to considerable decrease in costs for high-voltage C.T.’s.

Testing of Current Transformers

During field commissioning, the following tests are required for Current Transformers:

1- CT Excitation Curves

The purpose of this test is to verify that the C.T.p p y meets the specifications, and will not saturate during maximum fault conditions. The C.T. characteristics

ill h b ifi d b th d i f th will have been specified by the designer of the protection scheme.

T ti

f C

t T

f

Testing of Current Transformers

The C.T. excitation test is performed as follows:

Th lt li d t d t i l f th The voltage applied to secondary terminals of the

C.T. is varied in steps of, say 50 volts, and the C.T. magnetizing current is measured in milliamps, up until the C.T. saturates.

The results obtained should be similar to those specified in manufacturer’s test data and also to the specified in manufacturer s test data, and also to the results for similar C.T.’s.

NOTE:

The C.T. primary must be ‘open circuit’ when performing excitation tests.

2- C.T. Ratio Test

The purpose of this test is to verify that the C.T. ratio is correct for the various taps on the secondary winding.

Th i l t t t f C T ti i t t The simplest test for C.T. ratio is to pass a current,

of say 12 Amps, through the primary of the C.T., and measure the secondary current with a milli-and measure the secondary current with a milli ammeter, say 50 mA. The C.T. ratio is then calculated as 12A: 5OmA or 1200 : 5A. The C.T.

ti l b t t d b i RATIOMETER ratio can also be tested by using a RATIOMETER.

3- C.T. Polarity Test

The purpose of the C.T. polarity test is to ensure that direction of current flow in the secondary

i it i t l ti t th i Thi i circuit is correct relative to the primary. This is extremely important where the secondary windings of a number of C.T.’s are connected windings of a number of C.T. s are connected together, such as in a differential protection scheme. We will discuss this later when we cover B P t ti

C.T. Polarity Test

The C.T. polarity can be verified by a very simple

p

y

y

y

p

test, known as the Flick Test.

C.T. Polarity Test

An analogue meter, on the d.c. milli-amp range, is connected across the C.T. secondary terminals, with the positive lead to ‘spot’ or X1. A 1.5 volt ‘D’ cell is then used to pass a current through the C T cell is then used to pass a current through the C.T. primary. As the connection is made to the ‘D’ cell, to pass current from the cell positive, to the C.T. primary ‘spot’ or H1 then the d c milli ammeter primary spot or H1, then the d.c. milli-ammeter will deflect or ‘flick’ in a positive direction. As the connection from the ‘D’ cell is removed, the

milli-t ill d fl t i ti di ti If ammeter will deflect in a negative direction. If a ratio meter is used to check the C.T. ratio, then the correct polarity will be indicated by that meter.p y y

4-Secondary Winding Resistance

The purpose of this test is to verify that the total burden on the C.T. is not high enough to cause the burden on the C.T. is not high enough to cause the C.T. to saturate during fault conditions. The resistance of the secondary winding is measured, ll ith di it l h t Th i t f usually with a digital ohmmeter. The resistance of the other components of the secondary circuit, such as the C.T. cable, and the relays, should also such as the C.T. cable, and the relays, should also be measured.

5-Secondary Winding Insulation Resistance 5 Secondary Winding Insulation Resistance

The purpose of this test is to verify that the C.T. secondary winding insulation is in good condition. The entire secondary circuit of the C.T. must be tested with a MEGGER and a result in excess of 10 MEG OHMS, at 500 volts is normal.

10 MEG OHMS, at 500 volts is normal.

It is very important that the C.T. secondary circuit is GROUNDED AT ONE POINT ONLY, normally

t th l l If th di i d

at the relay panel. If the grounding is done through a link, then this provides a convenient point to disconnect the ground to ‘Megger’ the entire C.T.secondary circuit during routine maintenance tests.

Testing of Voltage Transformers

The purpose of this test is to record the

magnetizing current and compare it with

magnetizing current, and compare it with

the manufacturer’s test data, and to

record it for future reference This test is

record it for future reference. This test is

of questionable value, and may not be

worth performing in view of the risks

worth performing, in view of the risks

associated with the very high voltages.

V.T. Ratio and Polarity Test

The V.T. ratio and polarity can be tested with

ti

t

a ratio meter.

Alternatively, the V.T. primary winding can

be energized at 120 volts A C and the

be energized at 120 volts A.C. and the

secondary voltage measured.

With the V T in-service the secondary

With the V.T. in-service, the secondary

voltage and phase angle should be checked

against a known V.T. The polarity of the V.T.

g

p

y

can be checked by performing the

‘Flick-Test’ described earlier for C.T.’s.

Secondary Winding Resistance

y

g

Th

d

i di

i t

h ld b

The secondary winding resistance should be

measured with a digital ohm-meter.

Insulation Resistance of Windings

The insulation resistance of the secondary and primary windings should be measured.

p y g

A reading in excess of 50 Meg-Ohms is normal.

The V.T. secondary circuit is to be grounded at one point only. This is normally at the relay panel

.

End of this

End of this

Section

Section

Section 4

Power System Neutral 

y

Section 4   

Power System Neutral Grounding

¾ Ungrounded Systems

¾ Solidly Grounded Systems

¾ Solidly Grounded Systems

¾ Resistance Grounded Systems

¾ R

t

G

d d S t

¾ Reactance Grounded Systems

¾ Typical Resistance Grounded Systems in 

Industrial Plants

Industrial Plants

¾ Ground Fault Detection on Resistance 

Grounded Systems

Grounded Systems

¾ Ground Fault Detection on Ungrounded 

Systems

Systems

Power System Neutral Grounding

During power system ground faults the magnitudeg p y g g of the current that flows in the ground is governed by the method adopted for grounding the power

t t t l i t

system star or neutral point.

For most power system elements (such as feeders, lines buses & transformers) it is usual for ground lines, buses & transformers) it is usual for ground faults to result in an excessive current flow. The protection relays or fuses respond to this over current condition to clear the fault from the system.

Power System Neutral Grounding

However, for some power system elements, notably(صاخ لكشب) generators, the neutral point is

normally grounded through a high impedance (usually a distribution transformer with a resistor (usually a distribution transformer with a resistor connected across the secondary terminals) which limits the fault current to less than about 5 Amps. There are various reasons, both technical and

economic, for grounding the neutral point of a t I th l d th h

power system. In the early days three phase power systems were operated with the neutral ungrounded.

Power System Neutral Grounding

However, these systems were found to be prone(ضّرعّت) to failures due to common mode transient over voltages. For a ground fault on one phase, the voltage

f h f l d h i Al d i

of the un faulted phases increases. Also, during system ground faults the voltage of the neutral point of the transformer winding increases.

I d t li it th it d f th lt

In order to limit the magnitude of the over voltages, solid grounding of the neutral was adopted.

The economic reason applies for High Voltage systems here b solidl gro nding the ne tral point of a where, by solidly grounding the neutral point of a transformer it is permissible to grade the thickness of the winding insulation downwards towards the neutral point This is almost universal at voltages of 100 kV point. This is almost universal at voltages of 100 kV and above.

A

th t h i l

Among the technical reasons are:

The floating potential on the lower voltage (secondary and tertiary) windings is held to a (secondary and tertiary) windings is held to a harmless value.

Arcing faults to ground do not set up dangerously hi h lt th h lth h

high voltages on the healthy phases.

By controlling the magnitude of the ground-fault current inductive interference between power and current, inductive interference between power and communication circuits can be controlled.

A high value of ground-fault current is normally

il bl t t th l t f

available to operate the more usual types of protection schemes, such as over current and impedance.p

P

S t

N

t

l G

di

Power System Neutral Grounding

UNGROUNDED SYSTEMS

Ungrounded systems are those with no ground Ungrounded systems are those with no ground connection, other than through high impedance devices such as voltage transformers. There is also the capacitance-to-ground of each of the phase the capacitance to ground of each of the phase conductors to be considered. The advantages of ungrounded systems are that a single ground fault does not result in a system outage and the cost of does not result in a system outage, and the cost of ground fault detection equipment is low. The disadvantages are that they are subject to transient over voltages, and the insulation strength of over voltages, and the insulation strength of equipment connected to ungrounded systems must be greater than for grounded systems.

Power System Neutral Grounding

The methods most commonly used to ground power system neutrals are as follows:

system neutrals are as follows:

¾

SOLIDLY GROUNDED SYSTEMS

S lidl d d di t ti ith

Solidly grounded means a direct connection with a conductor of adequate size, from the neutral to the ground grid. There is no intentional impedance

g g p

introduced, other than the resistance of the grounding conductor itself. The term EFFECTIVELY GROUNDED is often used to define this type of grounding

is often used to define this type of grounding.

The term EFFECTIVELY GROUNDED is often used to define this type of grounding

Power System Neutral Grounding

An EFFECTIVELY GROUNDED system is

defined as

“Grounded through a sufficiently low impedanceGrounded through a sufficiently low impedance

such that for all system conditions the ratio of

zero-sequence reactance to positive zero-sequence reactance is positive and Less than three, and the ratio of

is positive and Less than three, and the ratio of zero-sequence resistance to positive sequence

i t i iti d l th ”

Power System Neutral Grounding

Another definition is “An Effectively-Grounded

System is one in which during a phase-to-System is one in which during a phase to

ground fault, the voltage to ground of any of the

healthy phases does not exceed 80% of the voltage between phases of the system.”

Resistance Grounded Systems Resistance Grounded Systems

A resistance grounded system is one where a the neutral point is connected to ground through a fixed

i t resistor.

This is also known as ‘non-effective’ grounding. The effect of grounding the system neutral through a g g y g

resistance is to reduce the fault current for ground faults. The advantages are:

Reduced damage from melting, burning and Reduced damage from melting, burning and

mechanical stress due to lower ground-fault current. Reduced flash hazard.

Reduction in the momentary voltage drops during Reduction in the momentary voltage drops during ground-faults.

R i t G d d S t

Resistance Grounded Systems

A value sometimes chosen for the grounding resistor is one that limits the ground-fault current for a fault is one that limits the ground fault current, for a fault at full phase-to-neutral voltage, to a value equal to the rated current of the transformer winding whose neutral it grounds

neutral it grounds.

A typical value of neutral grounding resistor for utility power systems at 10 to 50 kV is about 1 OHM. For a

p y

4.16 kV system a 6 OHM neutral grounding resistor may be used to limit the ground fault current to about 400 amps

about 400 amps.

A high neutral grounding resistance of 69 OHMS limits the ground fault current to about 5 amps on a 600 V lt t

d d

Resistance Grounded Systems

In a typical 600 volt distribution system in an industrial plant the transformer may be grounded through a 15 Ohm resistor as shown above. In this example the maximum ground fault current is 23 1 example the maximum ground fault current is 23.1 amps as shown on the next page.

Ground Fault Detection on Resistance‐Grounded Systems

Ground faults can be detected on Ground faults can be detected on resistance-grounded systems by monitoring the current that flows through the neutral grounding resistor. In

h b l f i fi d

the above example a current transformer is fitted around the conductor from the resistor to ground, and the secondary current of the C.T. supplies an and the secondary current of the C.T. supplies an over current relay. On systems that are grounded through a high resistance, where the ground fault current is low the ground fault detection over current is low, the ground-fault detection over current relay may initiate an alarm, rather than trip.

Reactance Grounded Systems

A reactance grounded system is one where the neutral point is connected to ground through a fixed reactor.

Again, this is ‘non-effective’ grounding. The advantages of reactance grounding are similar

t th f i t di A t i l

to those for resistance grounding. A typical distribution utility uses 2 OHM reactors to ground the neutral on it’s 25 kV system and 5 ground the neutral on it s 25 kV system, and 5 OHM reactors on the neutrals of it’s 44 kV system.y

ARC Suppression Coil Grounded Systems

Arc-suppression coil grounding (or resonant or ground fault neutralizer grounding) uses a reactor with a value chosen to match the value

f th it t d f t h ith

of the capacitance to ground of two phases with the third phase connected solidly to ground.

I thi th ti t f th

In this way the reactive component of the capacitive current flowing to ground at the fault is neutralized by the coil current which flows in is neutralized by the coil current which flows in the same path but is displaced in phase by 180 degrees from the capacitance current.g p

ARC Suppression Coil Grounded Systems

This tuning of the grounding reactor with the system capacitance results in ground-faulty p g current that is resistive and of low value, and ideally the fault arc is self-extinguished.

This method of system grounding is fairly popular in Europe and is gaining acceptance in th U S A