Advanced Techniques In Power System Protective · PDF fileAdvanced Techniques In Power System...

Advanced TechniquesIn

Power SystemProtective Relaying

October 09 - 13, 2004Abu Dhabi, U.A.E

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Section 1 Power System Faults

Section 2 Components of Protection Schemes

Section 3 Current Transformers & VoltageTransformers

Section 4 Power System Neutral Grounding

Section 5 Ground – Potential – Rise During PowerSystem Ground Faults

Section 6 Feeder Overcurrent Protection

Section 7 Coordination of Protection Systems

Section 8 Bus Protection

Section 9 Motor Protection, Starting & Control

Section 10 Transformer Protection

Section 11 Generator Protection

Section 12 Cogeneration & Non-Utility Generation (NUG)

Section 13 High-Voltage Transmission Line Protection

Section 14 Static Capacitor Protection

Section 15 Recent Developments and Future Trends inProtective Relaying

Introduction

ELECTRICALPOWER SYSTEM PROTECTIVE RELAYING

Protective relaying is the Science or Artof detecting faults on power systems

and clearing those faults from the power system as quickly as possible.

SEMINAR OBJECTIVEST0 PROVIDE A PRACTICAL UNDERSTANDING OF:

1. The concepts, principles of operation, and application of power system protective relaying.

2. The analysis of relay operations for various power system faults.

3. The requirements of commissioning and maintenance testing of protection schemes.

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Power System Faults

1-1

Power System Faults

1-2

A power system fault is the breakdown of insulation (between conductors, or

between a phase conductor and ground) which results in

excess current flow.

1-3

TYPES OF FAULTS

On a three-phase power system the principal types of fault are:

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)

d) Three Phase, with or without ground

Sometimes these faults are accompanied by a broken conductor,

or may even take the form of a broken conductor without a ground

connection. This results in an open-circuit condition.

Because no `fault current' flows for this condition the open-circuit

fault is difficult to detect. The open-circuit does, of course, cause

severe unbalance on the power system, and can cause

overheating in generators. The generators must be equipped with

protection schemes to detect such unbalances (or negative phase

sequence) conditions. This will be covered later under `Generator

Protection'.

Generators, transformers and motors are subject to short-circuits

between turns of the same winding.

1-4

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

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, faults are often the result of contamination of the SF6

gas by solid particles.

1-5

INCIDENCE OF FAULTS ON POWER SYSTEM EQUIPMENT

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 Miles

For 44kV, 33kV and 25kV feeders the figures are proportionally higher. The relationship between the number of overhead power system faults and the voltage level can be explained as follows:

By far the most common type of power system fault is the flashover

of insulators on overhead transmission lines, due to lightning. The

number of faults per year is proportional to the length, and is

approximately inversely proportional to the voltage level.

1-6

100,000 A

100,000 A

If lightning strikes a skywire, or tower, and causes 100,000 amps 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 crossarm to a phase

conductor may then occur. It will most likely occur on the phase

with the highest voltage difference to the voltage transient

developed by the lightning strike.

1-7

1-8

The most common causes of faults on overhead lines are:

1) Lightning2) Contaminated Insulators3) Punctured or broken insulators4) Birds and animals5) Aircraft and cars hitting lines and structures6) Ice and snow loading7) Wind

In electrical machines, cables and transformers, faults are causedby:

1) Failure of insulation because of moisture.2) Mechanical damage.3) Flashover caused by overvoltage or abnormal loading.

On transformers with external bushings, the most common cause

of faults, particularly on the lower voltage levels of 33 kV and

below, is small animals such as raccoons. 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.

1-9

EFFECTS OF POWER SYSTEM FAULTS

About 90% of overhead line faults are transient in nature:

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

With such faults, the line can be restored to service immediately after the breakers have tripped. Hence,AUTO-RECLOSE schemes are normally used on the circuit breakers associated with overhead transmission lines or feeders. If the fault current is interrupted by the circuit breakers, the `flashover' arc is immediately extinguished and the ionized air dissipates. Auto-reclosewill normally be successful after a delay of only a few cycles.

On typical 44kV and 33kV overhead distribution systems there is

an intentional delay of 0.5 seconds before the breaker is auto-

reclosed after a feeder fault. 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 is to help

maintain system stability by not subjecting the power system to two

faults in quick succession.

1-10

Faults in generators, motors, transformers and cables etc. are normally permanent and auto-reclose is not used. Such faults require the equipment to be taken out of service for an assessment of the damage and repair.

When a fault occurs, a very large current normally flows. This fault

current, if allowed to persist, will cause damage to equipment. On

an interconnected H.V. transmission system, an uncleared fault

can cause instability and system collapse:

i.e. A `blackout' over a very large area.

Faults must therefore be cleared in the shortest time possible.

1-11

MAGNITUDE OF FAULT CURRENT

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 fault.

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 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.

The fault current on a distribution system feeder, fed from a

transformer station, is determined by the H.V. supply line

impedance, plus the transformer impedance, plus the impedance of

the feeder up to the fault.

1-12

NOTE: When calculating fault current, we always assume that the impedance of the actual fault is ZERO.

For almost all faults, flashover occurs. The resistance of the resulting arc is nearly always negligible in comparison to the impedance of the line conductors.

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.

The procedure for calculating the maximum fault current (short-

circuit calculation) is given at the end of this section, with a worked

example.

1-13

DETECTION OF FAULTS

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

1-14

REQUIREMENTS OF PROTECTIVE RELAYING SYSTEMS

SELECTIVE

PROTECTIVE RELAYING SCHEMES MUST BE ABLE TO 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 SERVICE.

This is particularly important on an interconnected 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 these adjacent elements trip "in sympathy" with

the faulted element, then major power interruptions will result.

1-15

DEPENDABLE

PROTECTIVE RELAYING SCHEMES MUST BE VERY DEPENDABLE AND RELIABLE. ALL POWER SYSTEM FAULTS MUST BE DETECTED AND CLEARED QUICKLY.

ON HIGH VOLTAGE INTERCONNECTED TRANSMISSION SYSTEMS, AN UNCLEARED 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.

1-16

HIGH SPEED

HIGH SPEED FAULT CLEARANCE IS ESSENTIAL ON INTERCONNECTED TRANSMISSION SYSTEMS.

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.

CLEARANCE OF FAULTS

Faults on high-voltage power systems are detected by protectiverelaying systems, and cleared from the systems the opening or trippingof circuit breakers.

Fault detecting relays typically operate in about 1 cycle, or 20 milli-seconds, and circuit breakers operate in 3 cycles, or 60 milli-seconds.

On distribution systems, which are usually radial in nature, slower fault clearance times are permissible. TIME-GRADED overcurrent protectionis often used for fault clearance.

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

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

1-17

PROCEDURE FOR CALCULATING MAXIMUM FAULT CURRENT (SHORT CIRCUIT CALCULATION)

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

1. Draw a single-line diagram of the power system.2. Collect detailed impedance data for all of the components of

the power system. i.e Resistance R and Reactance X.

3. Although fault current can be calculated using the ohmicmethod, it is usually simpler to use the Per-Unit Method whereall of the impedances are referred to an arbitrarily chosen common BASE MVA.

4. Convert all of the various impedances to per-unit values with a common base MVA.

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

6. Calculate the total Impedance Z:

Z = R2 + X2

7. Calculate the THREE-PHASE (SYMMETRICAL) FAULT CURRENT:

I3phase =Vphase

ZCalculate the PHASE-TO PHASE FAULT CURRENT

I2phase =Vphase-phase

2Z= 3

2I3phase

Calculate the PHASE-TO-GROUND FAULT CURRENT

Iground = Vphase

Z + ZN

1-18

8. To determine the asymmetrical fault current, determine the X/R ratio and obtain the asymmetrical factor from graphs or tables

9. For low-voltage distribution systems where there is a significant motor load, the motor contribution to the fault can be approximated as:

Symmetrical Contribution = 4 times Motor Full Load Current

Asymmetrical Contribution = 5 times Motor Full Load Current

When using the PER-UNIT METHOD to calculate fault levels the following formulae are used to convert all impedances to per-unit values.

SOURCE P.U. IMPEDANCE ZPU = BASE MVASOURCE S.C. MVA

TRANSFORMER P.U. IMPEDANCE ZPU =ZT%100 *

BASE MVATRANSFORMER MVA

FEEDER P.U. IMPEDANCE ZPU = ZOHMS *BASE MVA

kV2

3-PHASE S.C. MVA AT FAULT =BASE MVATOTAL ZPU

RMS SYMM S.C. CURRENT AT FAULT = BASE MVA3 * kV

=

* ZPU

S.C. MVAkV*3

1-19

Short Circuit Calculations

FØ - Ø

3 – PHASE FAULT CURRENT I3 = VØ

ZØ

PHASE TO PHASE FAULT CURRENT VØ – ØI2 =2 ZØ

I3 PHASE=3 x

2

VØ - Ø

VØ ZØ

ZØ

ZØ

F3Ø

Phase To Ground Fault

VØ ZØ

ZØ

ZØ

FØ - G

ZN

PHASE TO GROUND FAULT CURRENT=ZØ +ZN

VØ

1-20

Example of Fault Current Calculation

Source S.C. MVA = 35044KV

Line Impedance

Z = 12.0

TransformerImpedanceZ = 7.7%

20MVA44KV / 13.8KV

Feeder ImpedanceZ = 5.0

13.8KV

Fault

Base = 100 MVA

Assume X/R ratios are HIGH, thusresistances are ignored

Source PU Z = 100 MVA

350 MVA= 0.286 pu

Transformer PU Z = 7.7 %100

x 100 MVA

20 MVA

= 0.385 pu

44KV Line PU Z = = 0.620 pu12 x 100 MVA

(44KV)2

13.8KV Feeder PU Z = 100MVA

13.8 KV5 x = 2.625 pu

Total impedance from source to fault = 3.916 pu

3.916 puThree Phase SC MVA =

100MVA= 25.54 MVA

RMS SYM SC Current = 25.54MVA

3 x13.8 KV = 1068A

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Components of Protection Schemes

2-1

Components of Protection Schemes

2-2

COMPONENTS OF PROTECTION SCHEMES

Each power system protection scheme is made up from the following components:1. Fault Detecting or Measuring Relays.2. Tripping and other Auxiliary Relays.3. Circuit Breakers.4. Current Transformers.5. Voltage transformers. (Voltage transformers are not required in all protection schemes).The function of these components is illustrated below for a simple overcurrent protection scheme:

TRIPPINGRELAY TRIP BREAKER

110V D.C. SUPPLY

OVERCURRENTRELAY

CIRCUITBREAKERC.T.

1200:5A

2-3

FAULT DETECTING RELAYS

Fault detecting, or Sensing relays monitor power system a.c. quantities such as current, voltage, and frequency.They are set to operate, and initiate tripping, when a fault condition is detected.

The most common fault detecting relays in use are overcurrent relays. There are two basic types of overcurrent relays.These are the Instantaneous Overcurrent Relay and the Timed Overcurrent Relay.

a. Instantaneous Overcurrent Relays.

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 overcurrent 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. The

movement of the armature causes the relay tripping contact to

close. In recent years, electronic versions of the instantaneous

overcurrent relay have been introduced. On these relays the pick-

up setting is usually adjusted by a dial or by setting DIP switches.

Both the electro-mechanical and the electronic versions are

functionally identical.

2-4

Timed Overcurrent Relays

The electro-mechanical version of this relay has an induction disc. The disc must rotate through a definite sector before the tripping contacts are closed. This type of relay is known as the Inverse Definite Minimum Time relay. The characteristic operating curve of an Inverse definite time relay is shown on the next page.

2-5

The relay characteristic is such that for very high fault currents therelay will operate in it's Minimum time of 0.2 seconds. For lowervalues of fault current the operate time is longer. For example, at a relay current of 16 Amps, the operating time is 0.4 seconds. The relayhas a definite minimum pick-up current of 4 Amps. This minimumpick-up current must, of course, be greater than the maximum load on the feeder. The induction disc relay normally has various currenttap settings, and an adjustable time dial. 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, onadjacent power system elements. As with the instantaneousovercurrent relays, there are now many electronic timed and Inverse Definite Minimum Time overcurrent relays on the market. Theircharacteristics are very similar to the electro-mechanical versions.Many overcurrent relays have an instantaneous element, and a timed element, both built into the same relay case.

The application of overcurrent relays to feeder protection will becovered later in this seminar.

2-6

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

1. OVERVOLTAGE AND UNDERVOLTAGE RELAYS

2. IMPEDANCE RELAYS

3. DIFFERENTIAL RELAYS

1. OVERVOLTAGE AND UNDERVOLTAGE RELAYS.These a.c. relays are normally supplied from voltagetransformers, and are set to operate for certain overvoltage orundervoltage conditions. For example, to protect capacitorbanks from overvoltage, or to detect undervoltage 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 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 the current entering andleaving the protected zone. If the unbalance is great enough, then a fault condition is detected, and tripping is initiated. Fortransformers, the differential relay must have some biasing toprovide relay restraint for through currents. This will beexplained later when we cover Transformer Protection.

2-7

Other Fault detecting relays include those used in Generator Protections, such as Negative Phase Sequence, Overexcitation,Loss of Field, Underfrequency, Out-of-step, etc.

The application of the various relays to power system protection schemes, will be discussed later in the seminar.

2-8

THE TRANSITION FROM ELECTRO-MECHANICALRELAYS TO ELECTRONIC AND MICROPROCESSOR BASED RELAYS

Until just a few years ago almost all protective relays were electro-mechanical, and many of these relays changed very little over a period of 50 years or more. A good example is the induction disc overcurrent relaywhich is still used extensively and has given many, many years of reliable service. In the early 1970's electronic relays were introduced. These relays used discreet solid state electronic components, and required external d.c. power supplies. 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 being

damaged by the spikes and transients that existed in the hostile

electrical environment of high-voltage sub-stations. 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 required a separate power supply, and

they could not match the reliability of electro-mechanical relays.

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 overcurrent relays which are used

extensively. However, electronic relays have still not gained

universal acceptance, even though they are cheaper and more

versatile than their electro-mechanical counterparts. Relay

manufacturers are still supplying thousands of induction-disc

overcurrent relays to customers who still prefer these robust relays

which have many, many years of proven reliability.

2-9

Since about 1992 there has been a revolution in protective relaying as microprocessor-based relays were introduced. As well as the basic protection function, these relays typically provide many additional features. They can be interfaced with computers and provide metering data, fault data (wave-form,maximum fault current, tripping time), sequence-of events, etc.

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.

2-10

TRIPPING AND OTHER AUXILIARY RELAYS

Power system faults are detected by the fault detectingrelays, which close their output contacts to initiate tripping. These output contacts are used to energise triprelays and other auxiliary relays which are normally supplied from the station battery d.c. supply.These auxiliary relays may perform a number of functions, such as:

• Trip the associated circuit breaker or breakers.• Send a trip signal to the remote terminal of the line.• Initiate Auto-reclosing of the circuit breaker.• Initiate Breaker Failure protection.• Send a TRIP alarm to the control room operator.

2-11

CIRCUIT BREAKERS

The circuit breaker is the device that actually interrupts the flow of fault current, and isolates the faulted element (feeder,transformer, etc.) from the remaining healthy components of the power system. The circuit breaker rating must be high enough for it to interrupt the maximum fault current that is possible to flow.

A typical 230kV circuit breaker rating is 70kA or 25GVA (25,000MVA). As stated earlier, circuit breakers must be capable of interrupting the fault current in very short periods oftime. Typical circuit breaker operating times are:

500 kV - 2 cycles or 40 milli-seconds. (50 Hz system)230 kV - 3 cycles or 60 milli-seconds. (50 Hz system)33 kV - 6 cycles or 120 milli-seconds. (50 Hz system)

These are the times from when the trip signal is sent to the breaker,

to when the fault current is interrupted.

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. Until recent years the

types of high-voltage circuit breakers that were being installed were

mainly AIR-BLAST BREAKERS or BULK-OIL BREAKERS.

2-12

Circuit Breaker Types

• Bulk Oil• Air• Minimum Oil• Air Blast• Sulphur Hexafluoride or SF6

• 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 more manageable values to supply relays. It is necessary for the C.T. to provide insulation 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 shown next.

2-13

1.25A1.25A

1200:5AC.T.

44kV300A

RELAY

Note that the C.T. polarity markings are shown as spots on theprimary and secondary sides of the C.T.

Also, it is important that the C.T. secondary circuit be grounded, and grounded at one point only.

2-14

IRON CORE

PRIMARYCONDUCTOR

SECONDARYWINDING

The most common type of C.T. construction is the 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, 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 or 0.5 AMP in many other

parts of the world. The various types of C.T. construction will be

described later.

2-15

TEN EQUAL CAPACITORS

VOLTAGE TRANSFORMERS

Voltage Transformers are used to step the 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 of up to about 100 kV are normally of the WOUND type. That is, a two winding transformer in an oil filled steel tank,with a turns ratio of say 417:1 or 275:1.

On higher voltage systems, such as 230kV and 500kV, CAPACITOR VOLTAGE TRANSFORMERS, (or CVT's) are normally used.

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

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

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Current Transformers & Voltage Transformers

3-1

Current Transformers & Voltage Transformers

3-2

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

Secondary Winding Primary Conductor

Iron Core

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 or 0.5 AMP in many other parts of the

world.

This type of `doughnut' C.T. is most commonly used in circuit

breakers and transformers. The C.T. fits into the bushing `turret',

and the porcelain bushing fits through the centre of the `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 following

diagram.

3-3

Moving Contact

Fixed Contact

Oil CircuitBreaker Bushings

Current Transformers

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

However, the C.T. must be insulated for the primary voltage level.

3-4

The Straight-Through type of construction is shown below:

The other principal type of C.T. construction is the Free Standing, or

Post type. These can be either 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 voltage insulation must, of course, be

provided, between the H.V. primary conductor, and the secondary

winding, which operates at essentially ground potential. Current

transformers of this type are often used at voltage levels of 44 kV,

33kV, and 13.8 kV.

3-5

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

The HAIRPIN C.T. gets it's name from the shape of the primaryconductor within the porcelain. With this type, the tank housing thetoroid is at ground potential. 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 of 500kV and 230kV. Free standing current transformers are very expensive, and are only usedwhere it is not possible to install `Doughnut' C.T.'s in Oil Breakers or transformer bushing turrets. As an example, C.T.'s cannot easily beaccommodated in Air Blast circuit breakers, or some outdoor SF6breakers. Free Standing current transformers must therefore beused 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 providethe different turns ratios.

Later in this section we will discuss the characteristics and testing of C.T's.

3-6

3-7

TEN EQUAL CAPACIATORS


Voltage Transformers are used to step the power system primary voltage from, say 50 kV or 33 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 these primary voltages of 50 kV and 33kV are normally of the WOUND type. That is, a two windingtransformer in an oil filled steel tank, with a turns ratio of 416.6:1 or 275:1. On higher voltage systems, such as 230kV and 500kV,CAPACITOR VOLTAGE TRANSFORMERS, (or CVT's) arenormally used.

A CVT is comprised of a capacitor divider made up from typically 10 equal capacitors, connected in series from the phase conductorto ground, with a voltage transformer connected across the bottomcapacitor. This V.T. actually measures one-tenth of the line voltage, as illustrated in the diagram above:

3-8

CURRENT TRANSFORMER THEORY & CHARACTERISTICS

Current Transformers for protective relaying 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, 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 the C.T.

must accurately produce a secondary current of 50 Amps to flow

through the relay 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.

The C.T. must be designed such that the iron core does not saturate

for currents below the maximum fault current. A magnetizing, or

excitation curve for a typical C.T. is shown next.

3-9

KNEE POINT

For this C.T. to operate satisfactorily at maximum fault currents, it

must operate on the linear part of the magnetizing curve.

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

which a 10% increase in voltage produces a 50% increase in

magnetizing current.

The point on the magnetizing curve at which the C.T. operates is

dependent upon the resistance of the C.T. secondary circuit, as

shown next.

3-10

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

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

then the C.T. secondary 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 volts. For the C.T. to operate with

good accuracy, without saturating for the maximum fault current,

the knee point must be well above 250 volts.

3-11

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 seminar when we discuss Bus Protection and Transformer Protection.

3-12

When C.T.'s are used for metering purposes, they 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 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 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 a continuous

circuit connected across the secondary terminals. If the

C.T. secondary is òpen circuit' Whilst primary current is

flowing, dangerously high voltages will appear across

the C.T. secondary terminals. Extreme care must be

exercised when performing òn load' tests on C.T.

circuits, to ensure that a C.T. is not inadvertently òpen

circuited'.

3-13

A typical protective relaying C.T. has it's accuracy specified as:

2.5 L 800

2.5% RELAYING KNEE POINT VOLTAGE

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

C.T. ACCURACY

C.T & V.T. ACCURACY

CURRENT TRANSFORMERS

A typical current transformer for protective relaying purposes may

have an accuracy of 2.5%. The margins used in protection relay

setting criteria are usually quite large, and 2.5% accuracy is

adequate - provided the C.T. maintains this accuracy for all

fault currents up to the maximum possible fault current.

3-14

A current transformer for metering purposes may typically have an accuracy of 0.3%. The C.T. must maintain this accuracy for normal load currents, provided the rated burden on the C.T. is not exceeded. It is quite acceptable, and in fact desirable, for the C.T. to saturate when fault current flows. The accuracy for a typical metering C.T. is specified as:

0.3 M 0.9

O.3% METERING O.9 OHMS BURDEN

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


The accuracy for a typical voltage transformer is specified as:

0.6 Z

0.6% VA BURDEN

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

W = 12.5 VAX = 25 VA Y = 75 VAZ = 200 VA ZZ = 400 VA

3-15

FUTURE TRENDS IN C.T. DESIGN USING OPTICS

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

3-16

VARIABLE120v A.C. SUPPLY(VARIAC)

TESTING OF CURRENT TRANSFORMERS

During field commissioning, the following tests are required forCurrent Transformers:

C.T. Excitation Curves

The purpose of this test is to verify that the C.T. meets thespecifications, and will not saturate during maximum faultconditions. The C.T. characteristics will have been specified by thedesigner of the protection scheme.

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

The voltage applied to secondary terminals of the C.T. is varied insteps of, say 50 volts, and the C.T. magnetizing current ismeasured in milli-amps, up until the C.T. saturates. The resultsobtained should be similar to those specified in manufacturer's testdata, and also to the results for similar C.T.'s.

NOTE: The C.T. primary must be òpen circuit' whenperforming excitation tests.

3-17

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. 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-ammeter,say 50 mA. The C.T. ratio is then calculated as 12A : 50mA or 1200 : 5A.

The C.T.ratio can also be tested by using a RATIOMETER.

C.T. POLARITY TEST

The purpose of the C.T. polarity test is to ensure that direction of current flow in the secondary circuit is correct relative to the primary. This is extremely important where the secondary 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 Bus Protection.

3-18

The C.T. polarity can be verified by a very simple test, known as

the FLICK 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. 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 will deflect or `flick' in a positive direction. As

the connection from the `D' cell is removed, the milli-ammeter will

deflect in a negative direction.

If a ratiometer is used to check the C.T. ratio, then the correct

polarity will be indicated by that meter.

3-19

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 C.T. to saturate during fault conditions. The resistance of the secondary winding is measured, 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 be measured.

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.

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

3-20

TESTING OF VOLTAGE TRANSFORMERS

CAUTION:

Extreme care must be exercised when performing field tests on high voltage V.T.'s. Very high voltages can appear on the primary terminals.

One field test that is sometimes performed is to energise the V.T.

from the secondary terminals, and measure the magnetizing current

at the rated voltage of 67 volts. DURING THIS TEST THE

PRIMARY TERMINALS WILL BE AT FULL PRIMARY RATED

VOLTAGE. e.g. 44 kV, 33 kV or 25 kV etc.

The purpose of this test is to record the magnetizing current, and

compare it with the manufacturer's test data, and to record it for

future reference. This test is of questionable value, and may not be

worth performing, in view of the risks associated with the very high

voltages.

3-21

V.T. RATIO AND POLARITY TEST

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

Alternatively, the V.T. primary winding can be energised at 120 volts a.c. and the secondary voltage measured.

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.can be checked by performing the `FLICK-TEST' described earlier for C.T.'s.

SECONDARY WINDING RESISTANCE

The secondary winding resistance should be measured with a digital OHM-METER.

3-22

C. INSULATION RESISTANCE OF WINDINGS

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

��

�Power System Neutral Grounding

4- 1

Power System Neutral Grounding

4- 2

• Ungrounded Systems• Solidly Grounded Systems• Resistance Grounded Systems• Reactance Grounded Systems• Typical Resistance Grounded

Systems in Industrial Plants• Ground Fault Detection on

Resistance Grounded Systems• Ground Fault Detection on

Ungrounded Systems

4- 3

During power system ground faults the magnitude of the current that flows in the ground is governed by the method adopted for grounding the power system star or neutral point.

For most power system elements (such as feeders, lines, buses &

transformers) it is usual for ground faults to result in an excessive

current flow. The protection relays or fuses respond to this overcurrent

condition to clear the fault from the system.

However, for some power system elements, notably generators, the

neutral point is normally grounded through a high impedance (usually a

distribution transformer with a resistor connected across the secondary

terminals) which limits the fault current to about 10 Amps.

4- 4

There are various reasons, both technical and economic, for grounding the neutral point of a power system. In the early days three phase power systems were operated with the neutral ungrounded.

However, these systems were found to be prone to failures due to

common mode transient overvoltages. For a ground fault on one phase,

the voltage of the unfaulted phases increases. Also, during system

ground faults the voltage of the neutral point of the transformer winding

increases.

In order to limit the magnitude of the overvoltages, solid grounding of

the neatral was adopted. The economic reason applies for High Voltage

systems 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 and above.

4- 5

Among the technical reasons are:

• Arcing faults to ground do not set up dangerously high voltages on the healthy phases.

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

• A high value of ground-fault current is normally available to operate the more usual types of protection schemes, such as overcurrent and impedance.

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

4- 6

UNGROUNDED SYSTEMS

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 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 ground fault detection equipment is low. The disadvantages are that they are subject to transient overvoltages, and the insulation strength of equipment connected to ungrounded systems must be greater than for grounded systems.

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

4- 7

SOLIDLY GROUNDED SYSTEMS

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

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

An EFFECTIVELY GROUNDED system is defined as "Grounded

through a sufficiently low impedance such that for all system conditions

the ratio of zero-sequence reactance to positive sequence reactance

is positive and less than three, and the ratio of zero-sequence

resistance to positive sequence resistance

is positive and less than one."

Another definition is "An Effectively-Grounded 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."

4- 8

Resistance Grounded SystemsA resistance grounded system is one where a the neutral point is connected to ground through a fixed resistor. This is also known as `non-effective' grounding. The effect of grounding the system neutral through a resistance is to reduce the fault current for ground-faults. The advantages are:

• Reduced damage from melting, burning and mechanical stress due to lower ground-fault current.

• Reduced flash hazard.• Reduction in the momentary voltage drops during

ground-faults.• Reduction of overvoltages.

A value sometimes chosen for the grounding resistor 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.

A typical value of neutral grounding resistor for utility power systems at

10 to 50 kV is about 1 OHM.

For a 4.16 kV system a 6 OHM neutral grounding resistor may be used

to limit the ground fault current to about 400 amps.

A high neutral grounding resistance of 69 OHMS limits the ground fault

current to about 5 amps on a 600 Volt system.

4- 9

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 amps as shown on the next page.

4- 10

Ground Fault Detection on Resistance-Grounded Systems

Ground faults can be detected on resistance-grounded systems by monitoring the current that flows through the neutral grounding resistor. In 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 overcurrent relay. On systems that are grounded through a high resistance, where the ground-fault current is low, the ground-fault detection overcurrent relay may initiate an alarm, rather than trip.

4- 11

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 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 OHM reactors on the neutrals of it's 44 kV system.

4- 12

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 of the capacitance to ground of two phases with the third phase connected solidly to ground. 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 the same path but is displaced in phase by 180 degrees from the capacitance current. This tuning of the grounding reactor with the system capacitance results in ground-fault 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 the U.S.A.

4- 13

Ground-Fault Detection on Ungrounded Systems

On ungrounded systems, a single ground-fault will not result in the flow of any fault-current

For a ground-fault on one of the phases, the voltage-to-ground on the two unfaulted phases will rise.

Voltage relays measuring the voltage-to-ground for each of the phases can be used to provide ground-fault detection for ungrounded systems.

It is usually a requirement that ground-fault detection be provided on ungrounded systems.

4- 14

GENERATOR NEUTRAL GROUNDING

4- 15

• Reasons for Limiting Generator Ground Fault Current

• Methods Used to Ground the Neutral of Generator Stator Windings

• Detecting Generator Stator Ground faults

4- 16

Generators are the most expensive pieces of equipment on our power systems. Reliable protective relaying schemes are therefore required to detect and clear generator faults quickly to minimise damage and reduce repair time to a minimum. One of the most likely fault conditions on generators is the stator ground fault

If the resulting stator ground fault current is high there will likely be considerable damage to the generator, resulting in a lengthy outage to repair the machine.

For small generators, of below about 3 MVA, it is normal practice to ground the star-point of the stator winding directly through a resistor.

4- 17

The value of the neutral grounding resistor determines the maximum ground-fault current that will flow for a ground-fault on the stator winding. Typically the neutral grounding resistor would be sized to limit the maximum ground-fault current to somewhere between 5 amps and 100 amps

With this arrangement stator ground faults are detected by the use of an overcurrent relay supplied from a current transformer measuring the neutral-grounding resistor current.

4- 18

For larger generators (over about 5 MVA), the normal practice is to ground the star point of the generator stator winding through a neutral grounding transformer, with a resistor connected across the secondary terminals. Usually a distribution transformer is used.

4- 19

The value of the resistor is chosen to limit the ground-fault current, for phase-to-ground faults on the stator winding, and ground faults external to the generator, to about 5 amps. Consequently, if a stator ground fault does occur the fault current will not cause any further damage to either the winding or the core, and the generator may be allowed to continue running until alternative generation is brought into service.

The generator could run indefinitely with a single stator ground-fault, but if a second ground fault occurs there would be very high fault current and serious damage to the machine would result.

4- 20

Detecting Stator Ground Faults

The stator winding of a typical generator is grounded at the star point through a neutral grounding transformer, with a resistor connected across the secondary terminals, as shown in the above diagram.

The value of this resistor is chosen to limit the ground fault current, for phase-to-ground faults on the stator winding, to about 5 amps. A Voltage Relay is connected across the resistor to detect stator ground faults.

This type of stator ground-fault protection will detect ground faults on about 90 % of the stator winding. The lower 10 % of the winding is therefore left unprotected. This topic will be covered in more detail later when we deal with generator protection.

��

Ground–Potential-Rise During Power SystemFaults

5-1

GROUND-POTENTIAL-RISEDURING POWER SYSTEM

GROUND FAULTS

• Functions of Grounding Systems

• Source and Distribution of Ground Fault Current

• Maximum Ground Fault Current

• Hazards to Individuals Working in Substations

• Step Voltage, Touch Voltage, and Transferred Voltage

• Tolerable Limits of Body Currents During

• Calculation of Allowable Step and Touch Voltages

• Transferred Voltage and Protection of Communication Circuits

• Calculation of Ground-Potential-Rise

• Measurement of Soil Resistivity

• Measurement of Station Ground Grid Resistance

• Control of Excessive GPR

• Control of Voltage Gradient

• Substation Fence Grounding

5-2

The Functions of the Grounding System are:

• Safety of Personnel

• Equipment Protection

• System Operating Requirements

Safety of Personnel

The grounding system must ensure that accessible non-current-carryingmetal structures and equipment are maintained at the same voltage andthat hazardous step and touch voltages do not occur.

Equipment Protection

The grounding system must be designed to limit the level of transientvoltages on station equipment by providing a low impedance path forlightning surges, fault currents, and other system disturbances.

System Operating Requirements

The grounding must be designed to ensure that there is proper operation of the protective devices such as protective relaying andsurge arresters. The grounding system has an influence on the levels of power system overvoltages and fault current, and the choice of protective relaying.

5-3

WHAT IS GROUNDING?

Grounded is defined as being connected to earth through a permanent conductive path of sufficient ampacity to carry the maximum possiblefault current, and of sufficiently low impedance to prevent any current in the grounding conductor from causing a harmful voltage to exist.

5-4

WHAT IS BONDING?

Bonding is the permanent low impedance path obtained by joining all non-conducting metal, by conductors of sufficient ampacity, to safelyconduct the maximum possible current that it may carry during a fault

5-5

It is important that the grounding system performs as designed for the expected life of the installation. The design must therefore take into account future additions and the maximum fault current for the ultimate configuration.

Maximum Ground-Fault Current

Hazards to individuals working in electrical sub-stations result when ground-fault current flows in the vicinity of those sub-stations. Ground current results from ground faults, lightning and induced voltages.

The magnitude of fault current is determined by the impedance of thevarious power system elements, such as lines, transformers and grounding system between the source(s) of generation and the fault.

When a fault occurs in an electrical circuit the current returns to the source through as many parallel-conducting paths as exist at the time. For the design of a protective grounding system, it is important to know the maximum ground-fault current, and the portion of fault current that will flow through various ground resistances.

5-6

Hazards to Individuals Working in Substations

The flow of fault current to or from earth will result in voltage gradients within and around a station ground grid area.

This voltage gradient will mean that different points within the stationwill be at different voltages during the period of time that fault current is flowing. Hazards to persons working in the sub-station exist becausedifferent parts of the human body can bridge across points where avoltage difference exists during the flow of fault current.

The principle hazards in electrical substations are normally classified as Step Voltage, Touch Voltage, and Transferred Voltage.

It is these voltage conditions that determine the value of current that will pass through the human body during fault conditions.

5-7

Tolerable Limits of Body Currents During Faults

The design of a grounding system that meets safety requirements is one in which the current flowing through the heart region of the body is less than the threshold current for ventricular fibrillation.

An accepted value of this threshold current is given by Dalziel's

empirical equation for transient conditions:

for the range of 't' between 0.030 and 3.0 seconds, and a frequency of

50 and 60 Hz.

This equation applies for a person weighing 50 kg.

For a person weighing 70 kg the equation becomes:

AmpstI k

116.0=

AmpstI k

157.0=

5-8

If a person is exposed to hazardous voltages for much greater lengths of time, such as when they touch live equipment, the resulting currents passing through the body would have the following effects:

2 mA to 10 mA Mild sensation to painful shock.

10 mA to 20 mA Burns, blisters, muscular contraction, cannot let go.

20 mA to 70 mA Breathing difficulties and severe pain.

70 mA to 100 mA Ventricular fibrillation, breathing may stop, possibly fatal without first-aid.

5-9

Calculation of Allowable Step & Touch Voltages

Step Voltage

Step Voltage is the voltage difference shunted by the human body by a Step, or Foot-to-Foot contact. The maximum value of current that will flow in the human body is determined by the maximum voltage difference between two accessible points on the ground, separated by a distance of one pace, which is assumed to be 1 Metre.

5-10

Touch Voltage

Touch voltage is the voltage difference shunted by the human body for a touch or hand-to-foot contact. If the object touched were grounded immediately below it, the maximum ground potential-difference shunted would be the normal maximum horizontal reach, assumed to be 1Metre.

5-11

Transferred VoltageTransferred voltage contact is a special case of touch voltage. It occurswhen a person standing on the ground touches a conductor groundedonly at a remote point; or a person standing at a remote point touches a conductor connected only to the ground grid.

Here the touch voltage may be essentially equal to the full voltage rise of the ground grid under fault conditions, and not the fraction of this total that is encountered in the usual `step' or `touch' contacts. Thistransferred voltage condition is extremely hazardous and care must be taken to ensure that this situation is avoided.

An example of transferred voltage is where communication cables runbetween a sub-station and a telephone company office. This hazard is controlled by routing all telephone company circuits through a neutralizing transformer, or optic isolation equipment, as they enter the high voltage sub-station for sites where the ground potential rise is high.

5-12

Approximating the shoe by a metallic disc of radius 0.083 Metres

where:K = 1.0 for soil immediately beneath the feetwhich is homogeneous for more than 500 mm.K = 0.74 for 150 mm of crushed stone.K = 0.57 for 80 mm of crushed stone

Crushed stone may be assumed to have ñs = 3,000 Ù.m when wet.

ρSF

KR 3=

5-13

Tolerable Limits of Step & Touch Voltages

The maximum permissible step voltage is calculated from the threshold current constraint, and the body circuit resistance through both feet in series.

Where Rk is the electrical resistance of the human body, and normally taken as 1,000 Ù.

Volts)R2+R(I=V FKKS

The equation for step voltage limit becomes:

Similarly the touch voltage limit is given by the body circuit resistance with both feet in parallel:

Voltst

0.7K+116=V S

Sρ

⎟⎠⎞

⎜⎝⎛

2R+RI=V F

KKT

t0.17K+116

=V ST

ρ

5-14

Calculation of Ground-Potential-Rise

Ground Potential Rise, or GPR, is the maximum voltage, during a power system fault, that a station ground grid may attain relative to a distant grounding point assumed to be at the potential of remote earth.

The ground potential rise for a station is calculated as the product of the station ground resistance, and the ultimate ground- fault current I. This value should be less than 3 kV.

If considerable cost is involved in achieving this requirement, a station ground potential rise of up to 5 kV is acceptable but may increase the difficulty of controlling the hazard from any transferred voltages or high local voltage gradients. A higher ground potential rise also increases the cost of the neutralizing transformers or other protective devices required for communication cables.

The following data are required for calculating the station ground potential rise:• Station ground-fault current for the ultimate configuration of the station.

• Station ground grid area, A

• Soil resistivity test data

• An estimate of the total length, L, of buried conductor, including ground rods.

• The number of distributed ground rods, N, their radius, a, and length below frost depth, l.

5-15

The following data are required for calculating the

station ground potential rise:

• Station ground-fault current for the ultimate configuration of the station.

• Station ground grid area, A• Soil resistivity test data• An estimate of the total length, L, of buried

conductor, including ground rods.• The number of distributed ground rods, N,

their radius, a, and length below frost depth, l.

5-16

Measurement of Soil Resistivity

Soil Resistivity ρ = 2 π x R x S

where:R = measured soil resistance in Ohms

S = probe spacing in metres

5-17

The following steps are followed in the design of the station ground grid:

First determine the radius r of a circle having the same area A as the ground grid.

πA=r s

Calculate the station ground resistance (for unfrozen soil).

Ohms

where R = Station ground resistance.ñe = Average soil resistivity.L = Total length of buried conductor,

including ground rods.

Calculate the ground potential rise from the product of maximum ground-fault current and station ground resistance.

It should be remembered that the ground-fault current will split between the various parallel paths to ground, such as transmission line shieldingor sky-wires, cable sheaths, etc. This should be taken into account when determining the fault current that flows to ground through thestation ground grid.

L+

4r=R ee ρρ

5-18

Measurement of Station Ground Grid Resistance

A test that is commonly used to measure the resistance of the ground electrode is known as the 'Fall of Potential Method. A sector of at least 120 degrees that is free of conductive anomalies such as metal pipes and cables is selected. This angle ensures that the test probes are closer to the ground grid under test than to pipes or cables. Two test probes are used, and the connections from the measuring instrument are as shown.

The current probe is driven into the ground at a distance as far as practical from the ground grid. This distance should be greater than the diagonal dimension of theground grid to get results with an acceptable level of accuracy. The instrument injects a fixed current through the earth, from the current probe to the ground grid. The potential probe is driven into the ground at a number of locations between the current probe and the ground grid.

For each location of the potential probe, the resistance measurement is read from the instrument, recorded, and plotted on a graph against distance from the ground grid. From the sample graph shown, the point of inflection of the curve is taken as the ground grid resistance. When tests are performed with greater distances between the current probe and the ground grid, the curve usually becomes almost horizontal, and it is this flat part of the curve that indicates the resistance of the ground grid.

5-19

5-20

Control of Excessive Ground-Potential-Rise

In cases where the calculated station potential rise exceeds 5,000 Volts, one or more of the following measures may be taken:

Additional buried conductors encompassing a greater area may be installed.

The number of squares making up the main ground grid may be increased.

The ground impedance of the lines terminated at the station may be decreased by using high-conductivity material for the overhead transmission line ground wires. This decreases the portion of the fault current flowing through the station ground grid.

A remote grounding electrode may be used to supplement the station groundingsystem.

Longer ground rods may be driven.

Burying more ground electrodes and by bonding water pipes, gas pipes, piles,structural steelwork and the foundations of buildings to the ground grid. Water piping and gas piping, being in direct contact with the soil will substantially reduce the station ground resistance.

However the outgoing pipes may transfer some of the ground-grid voltage outside the station. To avoid these undesirable transferred voltage hazards, all pipes should be fitted with insulating joints at the point of entry to the station.

5-21

Control of Voltage-Gradient

Gradient control ground mats are installed at the operating handle of manually operated isolating and ground-switches. These mats should be connected to the structure supporting the switches, and to the ground grid by means of copper conductors of suitable size. See Rule 36-310 of the Electrical Safety Code

High voltage sub-station sites are covered with a layer of crushed stone to a depth of about 6 inches. This has the effect of reducing the step and touch voltage hazards because of the relatively high resistivity ofthe stone.

Substation Fence

Electrical regulations usually require that the substation fence belocated at least one metre inside the perimeter of the station groundgrid. The fence must be connected to the ground grid at various places

This reduces the touch voltage for a person standing outside, andtouching the fence.

Fence grounding is very important because the outside of the fence is usually accessible to the general public, and fences located near the edge of a grounding grid straddle high potential gradients.

This reduces the touch voltage for a person standing outside, andtouching the fence.

5-22

Some utilities choose to have substation fencesisolated from the station grounding system since touch voltages on the exterior side may be reduced.

However, if the station fence:

-is located within 2 metres of any grounded equipment

-crosses a grounded railway siding

-has devices such as exterior telephones, card readers, or electric gate locks which are wired to the station then the fence should be connectedto the station ground grid.

In situations where the substation fence joins a private metallic fence, transferred voltage problems may arise. Installing wooden or masonrypanels to provide isolation between the two fences can resolve thisproblem. These panels should be at least 2 metres wide to avoid thetouch hazard between outstretched hands.

5-23

Precautions to be Taken When Working in High-Voltage Substations

Measures that may be taken by persons working in High-Voltage Substations to reduce the hazards of possible injury from step and touch voltages are:

Wear electrically resistive footwear (with an `Ù' label on them) to reduce the effects of step and touch voltages.

Wear electrically insulating rubber gloves when manually operating isolating or disconnect switches and grounding switches.

Stand on a voltage gradient control mat when manually operating high-voltage switches.

5-24

GPR and Transferred Voltages

• GPR and Transferred Voltages

• Hazards of Communications cables Entering High-VoltageSubstations

• Control of Transferred Voltage Hazards

• Neutralizing Transformers

• Optical Isolation Equipment

5-25

GPR and Transferred Voltages

As discussed earlier transferred voltage contact is a special case of touch voltage. It occurs when a person standing on the ground touches a conductor grounded only at a remote point; or a person standing at a remote point touches a conductor connected only to the ground grid.

Here the touch voltage may be essentially equal to the full voltage rise of the ground grid under fault conditions, and not the fraction of this total that is encountered in the usual `step' or `touch' contacts.

This transferred voltage condition is extremely hazardous and care must be taken to ensure that this situation is avoided.

5-26

A common example of a transferred voltage hazard is where communication cables run between a high-voltage sub-station and a telephone company office.

If we take a simple single-pair telephone circuit as an example, one end of the cable pair is terminated at the high-voltage substation, and the other end at the telephone company central office remote from thesubstation. Under normal conditions the ground potential of both of the sites is the same.

However, when a ground fault occurs at the substation the voltage of the ground grid at the substation rises, possibly by as much as 5,000volts relative to the remote ground at the other end of the telephonecircuit. This can cause serious damage to the communications equipment, and poses a serious hazard to any personnel who may beusing or working on the circuit.

5-27

Two devices that are commonly used to control this hazard are neutralizing transformers and teleline optical isolators.

Neutralizing TransformersThe diagram above shows a neutralizing transformer for a single pair telephone circuit.

5-28

Optical Isolation Equipment

The Positron Teleline Isolator shown above provides 10 kV of optical isolation for each communication circuit that is routed through theequipment.

5-29

5-30

��

Feeder Overcurrent Protection

6-1

Feeder Overcurrent Protection

6-2

F E E D E R O V E R C U R R E N T P R O T E C T I O N

By far the most common type of protect ion for radial distr ibution feeders is Overcurrent protect ion.Typicaldistr ibut ion system voltages are 44 kV, 33 kV & 25 kV.

The point of supply is normal ly a few k i lometres from the load.

The ideal way of protecting any piece of power system equipment

is to compare the current entering that piece of equipment, with the

current leaving it. Under normal healthy conditions the two are

equal. If the two currents are not equal, then a fault must exist. This

`Differential Protection' principal will be covered later when we

discuss bus protection, and transformer protection, etc. It is not

economic or practical to provide a communication channel between

the ends of a feeder to enable the currents entering and leaving the

feeder to be compared.

6-3

With Radia l feeders there is only one possible point of supply, and the f low of fault current is in one direct ion only .Overcurrent protect ion can therefore be used to provide adequate protect ion.

The current entering the feeder at the circuit breaker is measured by means of a Current Transformer located at the base of the breaker bushing. The C.T. secondary current is supplied to theovercurrent relays. These overcurrentrelays must then operate and initiate tripping if a fault condition is detected on the feeder.

6-4

FUSES

CIRCUITBREAKER

TRIP

OVERCURRENTRELAY

800:5A

A B

The overcurrent protection at the supply end of the feeder must

operate for all faults on the feeder, but should not operate for

faults beyond the remote station `B'. If we first consider an

instantaneous overcurrent relay, then the setting is determined by

the magnitude of the fault current at the end of the feeder.

Let us assume that the fault current at that point is 4800 amps.

Ideally the relay will be set for 4800 primary amps, (or x 5

amps = 30 secondary amps) and it should not operate for any

fault beyond the bus at the remote station.

However, in practice it is not possible to be so precise for the

following reasons:

4800

800

6-5

a. It is not possible for the relay to differentiate between faults which are very close to, but which are on each side the Bus `B', since the difference in the currents would be extremely small.

b. Inaccuracies in the C.T's and relays, and theeffects of distortion of the current waveform under transient conditions produce errors in the response of the protection scheme.

c. The magnitude of the fault current cannot be accurately established since all of the parameters may not be known, and the source impedance of the power system changes as generators are put in and out of service.

One solution to this problem is to set the instantaneous overcurrentrelay to òverreach' the remote terminal, (i.e. a setting less than4800 primary amps), and introduce a definite time delay in thetripping. This time delay will allow the fuses or overcurrent relays at the remote station to operate to clear faults beyond bus `B' beforethe time delayed tripping can take place at the supply station A'.This type of time delay has the major disadvantage that all faultswill be slow clearing, even very `close-in' faults, which have thehighest magnitude of fault current.

This time-delayed clearing of high fault currents is usuallyunacceptable, and the most common feeder protection scheme,which overcomes the problem utilizes an inverse time overcurrentrelay in conjunction with the instantaneous overcurrent relay. Theapplication of this feeder protection scheme, utilizing bothinstantaneous and inverse time overcurrent relays is describednext:

6-6

In order to ensure that the instantaneous overcurrent relay wi l l not unnecessar i ly operate for faults at the remote stat ion, (which should be c leared by the overcurrent protect ion or fuses at that stat ion) then it must be set to protect only part of the feeder. A safe maximum for most types of re lay is 80% of the feeder length.

The limit is determined by the characteristics of the relay used, and

the length of the feeder. If the feeder is long a high percentage of

the line can be protected; but with short lines it may be less; and

with very short lines it may not be possible to apply instantaneous

overcurrent protection.

This type of protection is known as High-Set Instantaneous

overcurrent protection.

6-7

With such a relay set to detect faults on 80% of the feeder, the remain ing 20% is left unprotected. This is, of course, not acceptable. To provide protect ion for the last 20% of the feeder a t ime-graded, or Inverse Def in i te Minimum Time relaycan be used.

This type of relay provides timed overcurrent protection, and

maintains coordination with the fuses or overcurrent relays at the

remote station. The operating time of the relay is inversely

proportional to the current.

i.e. For very high fault currents the relay will operate in it's minimum

time; and for fault currents only slightly above the relay pick-up

current there will be a very long operating time.

6-8

R E L A Y O P E R A T I N G C U R R E N T ( A M P S )

OP

ER

AT

ING

TIM

E (

SE

CO

ND

S)

The Ìnverse definite minimum time' relay has a characteristic as

shown above.

6-9

INVERSE TIME RELAY

FUSE

R E L A Y O P E R A T I N G C U R R E N T ( A M P S )

OP

ER

AT

ING

TIM

E (

SE

CO

ND

S)

If we superimpose the fuse characteristic of one of the transformer

fuses at the remote station, onto the above overcurrent relay

characteristic, we can see how the relay settings at the supply

station are coordinated with the transformer fuse. With this

scheme of protection, utilizing High-Set overcurrent relays,

Inverse Definite Minimum Time overcurrent relays, and fuses,

we will consider the response of the protection scheme to faults at

various locations.

6-10

BA

800:5A

TRIP

F2

F1

o / co / c

1. For a Fault at point X on the feeder, ONLY the High-Set

Instantaneous overcurrent relay will operate and clear the

fault with no intentional time delay.

2. For a fault at point Y on the feeder, it is beyond the `reach'

of the High-set instantaneous relay, therefore that relay will

not operate. The inverse timed overcurrent relay will operate

after a time delay determined by the magnitude of the fault

current and the relay characteristic.

3. For a fault at point Z , it is again beyond the `reach' of the

High-set Instantaneous relay. The Inverse Timed overcurrent

relay will begin to start to start timing, but the fuse on the

feeder F1 will operate first and clear the fault. The inverse

timed overcurrent relay at station À' will then reset.

6-11

800:5A

80%A

o / c o / c

Now let us look at a typical utility feeder which supplies customer

transformers at many different points along it's length. The same

High-Set Instantaneous Overcurrent and Inverse Timed

Overcurrent relays are used, and the H.S. relay must be set such

that it does not operate for faults beyond the first tap. The High-Set

relay will therefore be set to operate for faults up to 80% of the

distance to the first tap.

6-12

The criteria used for setting the Inverse-TimedOvercurrent relay are:

1. The relay must not operate for the maximum load current that will be carried by the feeder.

2. The relay setting must be sensit ive enough for therelay to operate and clear faults at the very end of the feeder.

3. The relay operating characteristic must be set to coordinate with other protection devices, such as fuses, `downstream' from the supply station.

This type of protection scheme will provide adequate protection for

feeders. However, there are some disadvantages with this

arrangement, particularly on long overhead feeders. The main

disadvantage is that most faults will be slow in clearing because

the inverse time overcurrent relay must operate. This slow fault

clearing is usually disturbing to customers on the affected feeder.

As mentioned earlier, there is a very high incidence of faults

caused by lightning on overhead feeders, particularly at the lower

distribution voltages. Consequently, the great majority of faults on

such feeders are transient in nature, and can be cleared by

opening the breaker, with no permanent damage resulting.

6-13

Protect ion schemes for this type of feeder can be enhanced by adding a Low-SetInstantaneous Overcurrent relay, and providing Auto-Reclosing of the circuit breaker after fault c learance. The low set instantaneous overcurrent relay is set to operate for the minimum fault current at the very end of the feeder. This means that it wil l Òverreach', and operate for faults in the transformers tapped on the feeder. All faults wil l therefore be first detected by the Low-Set relay.

This relay then trips the breaker, and also initiates Auto-Reclose.

For about 90% of the faults this auto-reclose will be successful, and

the interruption to the customers is for only about 0.5 seconds. If,

however, the fault is permanent, such as a broken pole or a tree on

the line, then the auto-reclose will be unsuccessful. After the circuit

breaker has auto-reclosed the tripping from the Low-Set

overcurrent relay is disabled for 10 seconds. This means that

proper protection coordination will then take place: i.e.

6-14

1. If the fault is in a transformer, then the fuse wil l blow to isolate only the faulted transformer, and leave the remainder of the feeder in service.

2. If the fault is on the feeder, beyond the f irst tap, then the inverse t imed overcurrent relay wil l operate after a t ime delay, and the feeder wil l tr ip a second time and `Lock Out'.

3. If the fault is close to the supply station, then the High-Set overcurrent relay wi l l operate and tr ip the feeder a second t ime, with no intentional t ime delay, and `Lock Out'.

6-15

CURRENT FLOW SHOWN FOR A BLUE PHASE TO GROUND FAULT ON THE FEEDER

BUSPROTECTIONC.T.’S

NORMAL LOAD CURRENT = 400 A

I.E. SECONDARY CURENT = 2.5 A

4800 A

FEEDER

800/5A

4800 A

R

W

B

A typical feeder overcurrent a.c. schematic diagram, showing allthree phases, is shown above. The diagram includes High-SetInstantaneous, Inverse Time, and Low-Set Instantaneousrelays. Very often the High-Set Instantaneous and Inverse Timeovercurrent relays are built into a single relay case. Until a fewyears ago, all of these relays were electro-mechanical, and often in separate relay cases. i.e. The H.S. Instantaneous - attractedarmature, and the Inverse Time - induction disc. More recentlyelectronic relays were used, and the settings are applied bychanging the position of `DIP' switches. These electronicovercurrent relays were much more compact, and were functionallyidentical to the electro-mechanical overcurrent relays.

Today, almost all overcurrent relays being installed aremicroprocessor-based, and have many functions in the one relay. As well as the protection functions described, these relays havemany more features available, such as event recording, waveform capture, fault location and frequency trend load-shedding. These features of modern microprocessor-based relays will be discussed later.

6-16

+ ve 125 VDC

H.S. INSTo / c

OPEN FOR 10 SECONDS AFTER BREAKER CLOSE OR RECLOSE

L.S. INSTo / c

TRIP RELAY

INV.TIME

o / c

- ve

TR

IPB

RE

AK

ER

ALA

RM

INIT

IAT

EA

UT

O-R

EC

LO

SE

The d.c. tripping circuit for such an overcurrent protection scheme

is shown above: A typical 27.6 kV feeder arrangement is shown on

the next page. The fault levels at various points on the feeder are

indicated, and the overcurrent protection settings are shown.

The protection coordination curves for the various relays and fuses

are included on a later page.

6-17

PROTECTION COORDINATION

CURVES FOR M4 FEEDER

CURRENT IN AMPS AT 27.6 KV

INVERSE TIMED OVERCURRENT300 E

FUSE

NORMALLOAD 400 AMPS

LOW-SET INSTANTANEOUS OVERCURRENT 1900 AMPS (BLOCKED ON RECLOSURE)

HIGH- SETINSTANTANEOUSOVERCURRENT 6,000 AMPS

1

10

100

1000 2000 6000 10,000 20,000100 200 500

TIM

E I

N S

EC

ON

DS

.1

.2

.3

.5

5

32

2030

27.6kV TRANSFORMER STATION AND FEEDER ARRANGEMENT

3 Phase Fault Values

M4 Load20 MVA 400 amps at 28.9 kVM4

250 MVA 5000 ampsM4 Relay Settings

MVA AMPS

Phase High Set 300 6000

Phase Low Set 95 1900

Phase Timed 50 1000 (minimumpickup)

700 MVA 14000 amps

10 mile feeder

600 MVA 12000 amps

100 MVA 2000 amps

90 MVA1800 amps

Fuse 300 E

MS #1

MS #2

B Bus

Y Bus

T1

T2

6-18

C R I T E R I A F O R S E T T I N G T H E I N V E R S E-T I M E D O V E R C U R R E N T R E L A Y

1. The relay must not operate for the maximum load current that will be carried by the feeder. i .e. COLD LOAD PICK-UP and BACK TO-BACKFEEDER LOADS

2. The relay setting must be sensitive enough for the relay to operate and clear faults at the very end of the feeder.

3. The relay operating characteristic must be set to coordinate with other protection devices, such as fuses, ‘downstream’ from the supply station.

CRITERIA FOR SETTING THE HIGH-SETINSTANTANEOUS OVERCURRENT RELAY

1. The relay must be set to operate for faults up to, but not beyond, the first tap from the feeder.

2. In practice, the relay is set to operate for faults up to 80% of the distance to the first tap.

This provides high-speed clearance for the high level faults close to the supply station.

6-19

CRITERIA FOR SETTING THE LOW-SETINSTANTANEOUS OVERCURRENT RELAY

1. The relay must operate for al l faults on the feeder, right up to the feeder end.

This provides high- speed initial clearance for all faults on the feeder.

For 10 seconds after the feeder breaker auto-recloses, the tripping from the low-set relay is blocked.

6-20

DIRECTIONAL OVERCURRENT PROTECTION

If there is generation connected to a distribution feeder, the system is no longer RADIAL.

Fault current can then flow in either direction – into the feeder from the power system or out of the feeder from the generator

A directional relay or element must be used to supervise the overcurrent relay elements to al low the overcurrent protection to trip ONLY i f the fault current flows into the feeder from the power system.

Directional Overcurrent Protection

Overcurrent protection is used extensively on radial distribution

systems, where the fault current can only flow in one direction. If

there is generation connected to a distribution feeder, then fault

current can flow in either direction, and the system is no longer

radial. If the generation is large (typically above about 5 MW) in

comparison to the normal load on the feeder, then the feeder

overcurrent protection at the supply station requires directional

supervision. A directional relay or element is used to supervise the

overcurrent relay elements to allow the overcurrent protection to

trip only if the fault current flows into the feeder from the power

system. The directional relay prevents tripping if fault current from

the generator flows out from the feeder to a fault elsewhere on the

power system.

6-21

TESTING OF FEEDER OVERCURRENT PROTECTION

The individual C.T's of the feeder overcurrent protect ion scheme are tested as described earl ier. With overcurrent protection the C.T. polarity is not of crit ical importance. However, the relative polarity of al l three phases must be the same. The individual relay elements are tested by injecting a variable test current into the C.T. secondary circuit, via l inks or switches on the front of the relay panel.

The `pick-up' current of the instantaneous relays is verified, and for

the inverse time relays 3 or 4 values of current are injected, and the

relay operating time is verified in comparison to the relay

characteristic curve.

With the feeder òn-load', the current in the C.T. secondary circuit

should be measured, and compared to the indicating ammeter

readings, and with the secondary current from the C.T's on the

opposite side of the circuit breaker.

6-22

Microprocessor-Based Feeder Protection Relays

Most feeder protect ion relays being instal led today are microprocessor-based, and inc lude many functions within the one relay.

As wel l as the basic instantaneous and inverse-timed overcurrent functions, these relays also include many other protect ion funct ions and addit ional features.

•Directional Supervision

•Undervoltage and Overvoltage

•Bus underfrequency & Rate-of-change

•Synchronism Check

•Negative Sequence Voltage

•Auto-reclose

•Event Recording

•Oscillography, or Waveform Capture

•Fault Location

��

�Coordination of Protection Systems

7-1

Coordination of Protection Systems

7-2

COORDINATION OF PROTECTION SYSTEMS

As described earlier, one fundamental requirement of all protection systems is selectivity or discrimination.This means that only the faulted power system elements should be disconnected to clear the fault, leaving all unfaulted equipment in service.

On radial power distribution systems, where the flow of fault current is in one direction only, time-currentcoordination is generally used.

On interconnected transmission systems, where there are many

sources of fault current, the flow of fault current can be in any

direction. Unit type protection schemes, such as differential

protection, are generally used. These unit-protection schemes

operate with no intentional time delay, and provide high-speed

clearance of faults before power system instability results.

7-3

TIME-CURRENT COORDINATION

On radial distribution systems overcurrent devices such as fuses and inverse-time overcurrent relays are generally used to provide protection. The magnitude of the available fault current at any point on the feeder is determined by the impedance of the power system from the point of the fault to the source of supply.

Consequently, the available fault current decreases as the distance from the supply station increases. Overcurrent devices are therefore generally used, in series, with progressively lower ratings, to protect various sections of distribution feeders.

7-4

Maximumclearing time

Current limiting 80E power fuse 34.5kV, 60Hz, 25ºC ambient

Minimummelting time

Tim

e in

Sec

onds

Current in Amps

FUSE-TO-FUSE COORDINATION

The time-current characteristic of a typical fuse is shown above,

and is represented by a band between the minimum melting time

and the maximum clearing time of the fuse element.

7-5

SOURCE

FUSE A

FUSE B

LOAD

FAULT

Current

Tim

e

Fuse A – minimummelting TC curve

75% of Fuse A curve (in time)

Coordination limit

Fuse B – total clearing TC curve

For correct coordination between two fuses in series, it is important

to ensure that the characteristic bands for the two fuses do not

intersect and overlap at any point, when plotted on the same graph.

To provide an adequate coordination margin for two fuses A and B

connected in series, and a fault at point X, the total clearing time for

fuse B would be 75% of the minimum melting time of fuse A.

Similarly, the time-current characteristics of fuses are coordinated

with those of overcurrent relays associated with circuit breakers

and relosers. Again, adequate margins are applied to ensure that

the characteristic curves do not intersect and overlap when plotted

on the same log-log graph, or on one of the many computer

coordination software packages that are available.

A typical coordination software package is available from the

Canadian company CYME International Inc. at www.cyme.com

7-6

An example of computer software for power system

protective device coordination is:

cyme.com

CYMTCC, Protective device coordination

7-7

PROTECTIVE RELAYING ZONES

The following diagram shows a section of a typical power system, comprising:

2 Transmission Lines2 Transformers2 33 kV Buses4 33 kV Feeders

Each of these power system elements must have a protective relaying scheme; and no part of the system should be unprotected.When applying protective relaying to such a system, we refer to PROTECTION ZONES.

7-8

Adjacent zones are separated by circuit breakers, and are shown in

the diagram above. Protective relaying zones are determined very

largely by the location of the current transformers. It is good

practice, where practical, to establish overlapping protection zones

by locating C.T.'s on the opposite side of the circuit breaker from

the power system element being protected. The overlapping of

adjacent protection zones across the circuit breakers is illustrated

by the location of the current transformers in the above diagram.

7-9

For example, where a feeder is supplied from a bus:

1. THE FEEDER PROTECTION C.T.'s MUST BE LOCATED ON THE BUS SIDE OF THE CIRCUIT BREAKER.

2. THE BUS PROTECTION C.T.'s MUST BE LOCATED ON THE FEEDER SIDE OF THE CIRCUIT BREAKER.

Referring to the diagram on the previous page, there is no circuit

breaker between each transformer and it's associated transmission

line. However, both the transformer and the line each has it's own

protection scheme, and there must be an overlap between the

transformer and line protections.

i.e. The line protection must `reach' into the transformer winding.

Because there is no circuit breaker between the transformer and

the line, BOTH of these elements will be tripped for either a

transformer fault or a line fault.

7-10

REQUIREMENT FOR BACK-UP PROTECTION

It is extremely important that power system faults be cleared as quickly as possible - even if there is a failure of a circuit breaker or protection system.

During our earlier discussion on feeder overcurrent protection we saw that the inverse timed overcurrent relay characteristics are set to co-ordinate, andprovide back-up to downstream devices such as overcurrent relays and/or fuses.

This type of time-graded back-up works fine for radial systems.

However, it is not possible to apply time-graded back-up protection

to interconnected transmission systems. In order to achieve the

required reliability on transmission systems it is usual to duplicate

all of the protective relaying systems to ensure that a single

component failure does not result in the failure of a fault being

cleared from the power system. It is not, of course, practical to

duplicate circuit breakers. Breaker-failure protection is therefore

provided to ensure that the failure of a circuit breaker does not

result in an uncleared fault, and possible power system collapse.

7-11

7-12

BREAKER FAILURE PROTECTION

On radial distribution systems the flow of fault current can be in one direction only. Faults that are uncleared because of a failed breaker will be cleared by the Back-Up feature of the protection scheme of the next system element closer to the source of supply. This was discussed earlier under `Feeder Protection'. The `Back-Up' feature is provided by coordinating the TIME/CURRENT characteristics of the overcurrent protection schemes for adjacent system elements.

On interconnected systems, such as the high voltage transmission system, fault current can flow in either direction, and the application of such `Back-Up' protection is not possible. If a transmission system fault is unclearedbecause of the failure of a Circuit Breaker, the effects can be enormous. There would be indiscriminate tripping of transmission lines and generators, and a power system collapse could easily result.

Breaker Failure protection is therefore provided on ALLcircuit breakers on the transmission system.

7-13

SIMPLIFIED DIAGRAM OF BREAKER FAILURE PROTECTION FOR HIGH VOLTAGE CIRCUIT BREAKERS

TRIP ALL BREAKERSON BOTH ADJACENTZONES

BREAKERAUXILIARYSWITCH

OVERCURRENTSUPERVISION(1000 AMPS)

INITIATINGCONTACTS

D.C. SUPPLY

TIMER(67 ms)

TIMER(105 ms)

BREAKERAUXILIARYSWITCH

( + )

50

52

TRIP FAILED BREAKER

TIMER(500 ms)

94 ET

62 c

62 b

62 a

52

94

A simplified diagram of a typical breaker failure protection scheme

for a high voltage circuit breaker is shown above.

This scheme is used by Ontario Hydro, Canada, on all 230 kV and

500 kV circuit breakers.

7-14

TRIPPING

When the breaker failure protection operates it must trip ALL of the circuit breakers on BOTHadjacent zones, including the breakers at the remote end of associated lines.

The breaker failure protection tripping relays `seal-in' for 45 seconds. This holds the tripping signal on to all of the tripped breakers and prevents them from auto-reclosing.

SPEEDThe speed of operation of breaker failure protection must be fast enough to prevent indiscriminate tripping of power system elements, and to prevent the power system from going unstable. Typically a fault would be cleared in 150 to 200 milli-seconds by the operation of the breaker failure protection.

INITIATIONBreaker failure protection is initiated by all of the protectionschemes that send trip signals to that breaker.

OVERCURRENT SUPERVISIONBreaker failure protection is supervised by high-speedinstantaneous overcurrent relays. These relays must have a very fast reset time and a high pick-up/drop -out ratio.

7-15

RELAY SETTINGS

INSTANTANEOUS OVERCURRENT SUPERVISION RELAYSThe high speed instantaneous overcurrent supervision relays are typically set for 1,000 primary amps.

TIMER 62aThe criterion for setting the 62a timing relay is the opening time of the breaker auxiliary switch (pallet switch) PLUS a 2 cycle margin. Typically this setting would be 4 cycles (or 67 milli-seconds for a 60 Hz power system). This leg of the circuit provides the fastest operation of the breaker failure protection. It will operate if the auxiliary switch has not opened within 67 milli-seconds after the trip signal is sent to the breaker, breaker failureprotection is initiated, and fault current is still flowing.

TIMER 62b

The criterion for setting the 62b timing relay is the breaker tripping time, PLUS the reset time of the overcurrent supervision relays, PLUS a 2 cycle margin. Typically this setting would be just over 5 cycles.

This leg of the circuit is the one which will operate if the breaker auxiliary switch opens, but the main contacts fail to interrupt the fault current.

7-16

TIMER 62c

The purpose of this leg of the circuit is to provide breaker failure protection when there are low magnitudes of fault current, below the 1,000 amp pick-up of the overcurrent supervision relays. (e.g. For faults at the remote end of very long lines). The contacts of this relay are not supervised by the overcurrent relay, and the setting is typically 500 milli-seconds or 0.5 seconds. This slow clearance of such faults can be tolerated because fault currents of less than 1,000 amps would not jeopardize the stability of the power system.

EARLY TRIP FEATURE

The purpose of the 94ET relay is to provide an EARLY TRIP

feature to prevent unnecessary operation of the breaker failure

protection tripping relays for inadvertent or accidental initiation of

the breaker failure protection. Such inadvertent initiation of breaker

failure protection is most likely to occur during trip testing by

maintenance personnel. When breaker failure is initiated, the 94ET

relay operates immediately, and sends a trip signal to the breaker.

If the breaker trips successfully, the breaker failure protection trip

relays will not operate.

7-17

TRIP ALL BREAKERS ON BOTH ADJACENT ZONES

D.C. SUPPLY( + )

INITIATING CONTACTS

BREAKER AUXILIARY SWITCH

52

TRIP FAILED BREAKER

TIMER0.3 SECS

94 ET 94

62

BREAKER FAILURE PROTECTION FOR L.V. BREAKERS

When breaker failure protection is provided for low voltage

breakers, such as on the L.V. side of transformers at transformer

stations, (e.g. 25 Kv, 33 kV, 50 kV) a much simpler scheme is

used. This is shown in the simplified diagram above. There is no

overcurrent supervision, and the breaker failure protection will

simply operate if the breaker auxiliary switch (or pallet switch) has

not opened 200 milli-seconds, or 0.2 seconds, after the trip signal

is sent to the breaker and breaker fail is initiated. An early trip

feature is provided as before, via the 94ET relay.

7-18

AUTO-RECLOSING OF CIRCUIT BREAKERS

As discussed earlier, it is usual to apply auto-reclose to feeder breakers on overhead distribution systems where the vast majority of the faults are transient in nature - mostly caused by lightning. Because these distribution systems are usually radial the auto-reclosescheme does not need any supervision. Typically the breaker would be set to auto-reclose after a time delay of 0.5 seconds.

The fault is cleared and the arc extinguished as soon as the

breaker is opened. The time delay is sufficient to allow the ionized

air to dissipate at the point of flashover where the arc was

established, and allow for a successful auto-reclose.

On high-voltage transmission systems, when a line trips there is a

good possibility that the power system will be 'split', and the two

ends of the line will fall out-of-synchronism. If high-speed auto-

reclose is applied, then there is a very short delay and the breakers

are reclosed before the two ends of the line can fall out-of-

synchronism, and no voltage supervision is required.

7-19

If delayed auto-reclose is applied, then voltage supervision and synchro-check relays are required. The auto-reclose scheme would be set to have the breaker at one end of the line reclose after a time-delay of, say 10 seconds, provided the line is still dead. The breaker at the other end of the line would be set to wait for the line to be re-energised, check the voltages across the breaker, verify that the two voltages are in-synchronism, and then reclose the circuit breaker.

��

Bus Protection

8-1

Bus Protection

8-2

BUS PROTECTION

The main bus in transformer stations is one of the most critical pieces of equipment in our power distribution and transmission systems. Faults on buses are very serious events because they usually result in widespread outages. The fault level on the bus is usually very high because it is close to the main source of supply, and may have multiple in-feeds. Faults on buses are almost always permanent, and auto-reclosingis therefore not applicable.

Reliable bus protection is essential for all power systems, from the

switchboards of industrial plants, to high-voltage buses in utility

substations. The consequences of an uncleared bus fault are

enormous. Also, the unnecessary tripping of a bus due to the

maloperation of the bus protection scheme can cause widespread

outages.

The choice of the type of bus protection to apply for any particular

location is very largely dependent upon the voltage level, and

whether the bus is supplied from a radial system, or is part of an

interconnected system.

8-3

For buses that are part of interconnectedsystems, where there is more than one possible in-feed for fault current, differential protectionis most appropriate. This is typical for utility substations at voltage levels of about 13.8 kV and above.

For buses supplied from radial systems, where there is only one

source of supply, overcurrent protection is appropriate. This is

typical in industrial plants where the bus voltage may be 4.16 kV or

600 volts, and is supplied from a single transformer. Instantaneous

overcurrent and inverse-timed overcurrent devices are used, with

settings selected to coordinate with the downstream devices, asdiscussed earlier.

8-4

8-5

6000A

6000A

RELAY 1200:5A1200:5A

6000A

F2F1

25A25A

25A25A

25A25A

BASIC CONCEPT OF DIFFERENTIAL PROTECTION

The ideal way to protect any power system element is to compare

the current entering that element, with the current leaving it. If there

is no fault condition, then the two quantities are equal. For a fault

condition the two quantities are unequal, and the difference in

currents passes through a relay, and the fault condition is detected.

This principle is known as DIFFERENTIAL PROTECTION.

The diagram above illustrates the principle of Differential Protection

in it's simplest form:

In the above example there is THROUGH or OUT OF ZONE fault

current of 6,000 Amps. The currents in the C.T. secondary circuits

circulate, and there is no SPILL into the relay. Hence, the Bus

Protection does not operate, and remains stable.

8-6

1200:5A

2000A4000A

RELAY

F1 F2

4000A 2000A

1200:5A

6000A

25A

25A

8.3A16.7A

16.7A 8.3A

8.3A16.7A

We now consider a fault on the bus, of the same 6,000 Amps. The

current in both C.T.'s is now in the same direction, and the current

in the C.T. secondary circuit no longer circulates. The two C.T.

secondary currents are summed, and the total of 25 Amps passes

through the differential relay. For this IN ZONE fault, the relay will

operate and initiate tripping.

8-7

From the two examples we can see the importance of the C.T. connections:

• THE C.T. POLARITIES MUST BE CORRECT RELATIVE TO EACH OTHER.

• THE C.T. RATIOS MUST BE THE SAME.

The C.T. excitation characteristics must also be the same.

As mentioned earlier, it is very important that none of the C.T.'s saturate during the maximum fault condition. If one C.T. in a differential protection scheme saturates for a THROUGH fault, then some unbalance will result.

This unbalance will cause some SPILL current to flow through the

relay. If this SPILL current is high enough, it can cause the Bus

Protection to maloperate, and trip the bus unnecessarily for a

THROUGH or OUT OF ZONE fault.

8-8

F1 F2 F3 F4 F5

RELAY

6000A 2000A 5000A 3000A 2000A

1200:5A

75A

75A

18,000A

8.3312.520.838.33A2.5A

APPLICATION TO VARIOUS BUS CONFIGURATIONS

We can now extend this theory to a bus with many lines connected

to it. Take the following example of a bus with 5 feeders connected

to it. For a total bus fault current of 18,000 Amps, the fault current

in each feeder is:

F1 = 6,000 Amps F2 = 2,000 AmpsF3 = 5,000 Amps F4 = 3,000 Amps

F5 = 2,000 Amps

RELAY CURRENT = 75 Amps.

Now, as an exercise, draw the C.T. currents if the same 18,000

Amp fault is in feeder F5.

The C.T. secondary currents once again balance, and the Bus

Protection remains stable for the THROUGH fault.

8-9

8-10

NOTE.

Differential Bus Protection will NEVER operate as BACK-UP protection for uncleared faults on other parts of the power system. For example, an unclearedfault on F5.

Also note the location of the C.T.'s in the bus protection schemes. As mentioned earlier, the bus protection C.T.'s MUST be located on the feeder side of the breakers. If the bus protection C.T.'s are located on the bus side of the breaker, then a protection blind spot exists.

8-11

F2

F4

F6

T2T1

BT

DIFF.RELAY

B.U.RELAY

Now let us consider the Bus arrangement for a typical sub-stationwith two supply transformers: The Bus protections for Buses C andD are exactly the same as the previous examples. i.e The C.T.'s are all connected in parallel, and all have the same ratio andpolarity. However, with this arrangement a BACK-UP protectionfeature can be readily incorporated. If the feeders F2, F4, and F6are RADIAL, then there can be no infeed from them for bus faults. For a fault on BUS D, the fault current is supplied through the T2and BT breakers ONLY.

Consequently, we can provide BACK-UP protection for the feeders by using the T2 and BT breaker C.T.'s. The Back-up protectionrelay is connected as shown, and will normally be an Inverse Time Overcurrent Relay, and set to coordinate with the feeder protection relays. Thus, if there is an uncleared fault on feeder F6 for example (i.e. the breaker fails to clear the fault, or the protection fails tooperate), then the F6 fault current continues to flow through the T2 and BT C.T.'s. The sum of these two currents passes through the D BUS back-up relay, which will operate after a time delay, andclear the fault by tripping the D BUS breakers.

8-12

8-13

8-14

Types of Relays Used

Various types of fault detecting relays are used in Bus Differential protection schemes. These include instantaneous overcurrent, inverse timed overcurrent, and high impedance relays. The high impedance relays are becoming more popular because they give much greater stability under through fault conditions.

Bus Protection Relay Settings.

The settings applied to bus differential relays are determined

mainly by the minimum fault level on the bus. The relays are

usually set to operate at roughly half of that minimum fault current.

If the differential relay is set too low, then there is the risk that it will

maloperate for through faults, and cause unnecessary tripping of

the bus.

8-15

High Impedance Differential Protection

By using High Impedance relays in differential protection the system can be designed to be more tolerant of a saturated C.T.

The High Impedance relays typically have voltage settings of 100 to 200 volts.

A non-linear resistor is connected across the relay terminals to limit the voltage across the differential relay to a safe value during fault conditions.

High impedance relays are used extensively in modern differentialprotection for high voltage buses. The advantage of using HighImpedance relays in bus differential protections is that they can be designed to remain stable (not operate) for external faults, whenany one of the C.T’s has saturated. For an external fault, the worst case is with one C.T. completely saturated, and the other C.T.’s notsaturated. The resulting differential current will cause the maximumvoltage to occur across the differential relay. A relay setting (involts) is chosen, with sufficient margin, to ensure that thedifferential protection does not operate for this external faultcondition. The resistance of the C.T. secondary windings and C.T.cabling must be known, and is used in the relay settingcalculations.

For internal faults the high impedance of the differential relayforces much of the resulting differential current through the C.T.exciting impedances. The resulting voltage developed across therelay is essentially the open-circuit voltage of the C.T.’s, and will be well above the voltage setting of the relay. A non-linear resistor, or varistor is connected across the relay terminals to limit the thevoltage to a safe value during fault conditions.

8-16

Bus Protection Tripping

When a bus fault is detected, all of the circuit breakers on that bus are tripped. Bus faults are almost always permanent,rather than transient faults. There must therefore be no auto-reclosing of breakersafter a bus fault. Bus protections will often cancel the auto-reclose on any breaker which may have been initiated by another protection.

Testing of Bus ProtectionThe C.T. circuits of bus protections are of critical importance, andgreat care must be taken to ensure that the ratio, polarity, andcharacteristics are all correct.

The best way to test the C.T. circuits, after all of the wiring iscomplete, is by PRIMARY INJECTION. Here a test current ispassed into the bus through one breaker, and out through a secondbreaker. The C.T. secondary current is measured, and shouldcirculate, with no Spill into the relay. This test is repeated tocompare the current in each breaker in turn, with the first.

The fault detecting relays are tested by injecting a test current into the C.T. secondary circuit, and into the relay. It is preferable toinject the test current via test links on the front of the relay panel,rather than test the relays on a bench. By injecting the test currentthrough test links on the panel, the C.T. secondary wiring as wellas the relay is tested.

With the Bus In-Service and On-Load, the C.T. secondarycurrents should be measured. The vector sum of all of the currentsshould be zero.

i.e. NO SPILL CURRENT THROUGH THE RELAY.

8-17

Many countries use busbar arrangements as shown above, where feeders can be switched from one bus to another by means ofisolating switches. This complicates the bus protection somewhat,because the C.T. secondary circuits must be switched, by means of the isolator auxiliary switches, to correspond with the appropriatebus.

It is usual to have one zone of protection for each section of thebus. These are known as discriminating zones. There is alsoanother zone of differential protection for the entire substation,which is known as the check zone. For tripping of a bus to take place with this arrangement it is necessary for both a discriminatingzone relay and the check zone relay to operate.

8-18

��

Motor Protection, Starting & Control

9-1

Motor Protection, Starting & Control

9-2

MOTOR STANDARDSENCLOSURES

• ODP - Open Drip-Proof enclosure

• WPI - Weather Protected I

For dry, clean non-corrosive locations. Water droplets at 0 to 15 degrees from vertical will not enter the motor enclosure ventilation openings.

This enclosure is similar to the ODP, but with additional shielding to protect the windings and bearings from water spray.

• WPII - Weather Protected II

• TEFC - Totally Enclosed Fan CooledWith this type of motor no outside air enters the enclosure. Cooling is provided by an externally mounted fan which blows air over the surface of the enclosure.

• TEFC EXPLOSION PROOFThis type of motor enclosure is required in hazardous locations, with the following classifications:

CLASS I - ExplosiveVapours/GasesCLASS II - Explosive DustsCLASS III - Explosive FibresDIVISION I - Hazardous materials normally presentDIVISION II - Hazardous materials may be present

Further shielding is provided on this type of enclosure to change the direction of the cooling air by three 90 degree turns to minimize the amount of moisture that can enter the motor.

9-3

INSULATION TEMPERATURE CLASSIFICATIONS

• CLASS B - 130 Degrees C Max.

• CLASS F - 155 Degrees C Max.

• CLASS H - 180 Degrees C Max

These temperature classifications indicate the maximum temperature that can be tolerated in the hottest part of the winding.

SERVICE FACTOR

Service factor is a classification of the capability of a motor to tolerate periodic overloading. Typical service factors are 1.0 and 1.15

• A service factor of 1.0 means that damage may occur whenever the motor full load current rating is exceeded.

• A service factor of 1.15 means that an overload of 15% can be tolerated periodically without seriously effecting the life of the motor.

9-4

EFFICIENCY

The efficiency of a motor is a measure of the ability of to convert electrical input in kW, to mechanical output at the shaft, in H.P. There are considerable energy and cost savings to be realized by using high efficiency motors. Typical values for high efficiency motors range from 82% for 1 HP to 95% for 500 HP.

9-5

MOTOR PROTECTION AND CONTROLThe vast majority of motors in industrial applications are induction motors, with supply voltages of 600 Volts or less. The following protection requirements are applicable to these motors.

OVERLOAD PROTECTIONMotors may be overloaded due to mechanical or electrical causes, and overload protection applies to both. The line current is proportional to the motor load, and so this current is used to activate the overload protection device.

Overload protection of three-phase motors is achieved in most

controllers by heating elements in series with all three motor leads.

These bimetallic heating elements activate electrical contacts,

which open the coil circuit when used on magnetic controllers.

When used on manual starters or controllers, the heating elements

release a mechanical trip to drop out the line contacts. These

bimetallic overload devices have inverse-time characteristics as

discussed earlier. Consequently, for a very small percentage

overload it may take a considerable time before tripping takes

place. However, for a very heavy overload fast tripping is achieved.

Ideally, the time-current characteristic of the thermal overload

device should coordinate with the damage curve of the motor.

9-6

The setting of the overload device depends upon the service factor of the motor. For a service factor of less than 1.15 the maximum overload setting should be 115% of the full load current rating of the motor. For a service factor of 1.15 or greater the maximum overload setting should be 125% of the full load current rating. (Typical electrical regulations).

A coordination diagram showing the thermal overload, motor

damage curves, and motor currents is included on the next page.

9-7

OVERCURRENT PROTECTION

Overcurrent protection is required for the motor branch circuits. -

Overcurrent protection is provided by fuses or a circuit breaker, to detect and clear faults on the cable supplying the motor, or in the motor itself. Contactors are used to control motor operation. However, contactors have a very limited fault interrupting capability, and are not used to clear faults (other than overloads).

9-8

GROUND FAULT PROTECTION

Ground fault protection is normally only provided on motors larger than about 200 HP. The three phase conductors are passed through a window-type zero-sequence current transformer which supplies a ground overcurrent relay. Operation of this ground fault relay then causes tripping of the motor.

The ground fault relay can also be supplied from the residual connection of the three phase C.T.'s. However, on motor starting current, unequal C.T. saturation can cause a residual current to flow in the relay, and appear as a ground fault.

When considering ground fault protection we must first determine howthe neutral of the power supply system is grounded.

The magnitude of the ground-fault current is determined by the method by which the supply transformer neutral is grounded. In many industrialplants the neutral of the supply transformer is grounded through aresistor to limit the ground-fault current. Typically the neutral of the 600 volt winding of the transformer is grounded through a 15 Ohm resistor,which limits the maximum ground-fault current to 23.1 amps.

For small motors on this system, of less than about 20 HP, motorground faults will be cleared by the operation of the phase overcurrentdevice, or the thermal overload device.

9-9

UNDERVOLTAGE PROTECTION

Motors must be disconnected from the source of supply for low-voltage conditions. (Electrical Safety Code Rule 28-400). This is usually provided by the contactor coil releasing the contactor when anundervoltage condition exists.

LOSS OF PHASE or SINGLE PHASING

This condition occurs whenever a fuse has blown in the supply to the motor. The condition is detected and cleared by properly sized overload devices. Table 25 of the Electrical Safety Code requires that an overload device be provided in each phase. Older installations may have only two overload devices on three-phasemotors.

9-10

MOTOR WINDING TEMPERATURE

Overheating protection may be required as per Electrical Safety Code rules 28-314,316 & 318. This is provided by temperature sensors embedded in the motor stator windings, which detect the high temperature condition and trip the motor.

Very large motors, with supply voltages above 600 Volts, are

expensive, and it is usually wise to provide more comprehensive

protection schemes. Such schemes include differential protection,

phase unbalance or negative phase sequence, incomplete start

sequence, stall or locked rotor, and out-of-step.

9-11

MOTOR DIFFERENTIAL PROTECTION

Differential protection is often provided for medium and large size motors with supply voltages of greater than about 4 kV, and electrically operated (shunt trip) circuit breakers. The differential protection provides high speed direction and clearance of faults on the motor stator windings.

Where the power supply system is solidly grounded the differential protection will detect both phase-to-phase and phase-to-ground faults.

Where the power system is resistance grounded, and the maximum ground-fault current is limited to a low value, the differential protection may not be sensitive enough to detect phase-to-ground faults. In such cases it is necessary to provide separate ground-fault protection as described previously.

9-12

MOTOR STATOR WINDINGS

CIRCUIT BREAKER

DIFFERENTIAL RELAY

DIFFERENTIAL PROTECTION FOR MEDIUM SIZED MOTORS

With differential protection the current at each end of each winding is compared to determine when a fault condition exists.

For medium size motors it is often possible to economize on C.T.'s anduse a single C.T. per phase. For each phase the connection from eachend of the winding is passed through the single C.T. as shown above.

Under healthy conditions the C.T. output will be zero. When a faultexists a differential current flows in the C.T. secondary, and causes the relay to operate.

9-13

DIFFERENTIALRELAY

CIRCUIT BREAKER

MOTOR STATOR WINDINGS

DIFFERENTIAL PROTECTION FOR VERY LARGE MOTORS

For very large motors a separate C.T. is used at each end of thewinding, for each of the three phases.

The C.T.'s are connected differentially as shown above, and underhealthy conditions the differential current in the relay is zero.

Under fault conditions there will be a different current in the two C.T.'s. The C.T. secondary differential current will cause the relay to operate,and send a trip signal to the circuit breaker to clear the fault and shutdown the motor.

9-14

MOTOR CONTROL AND STARTING

Contactors are used to switch the power supply on and off for motor control. However, as mentioned earlier, contactors have limited fault current interrupting capability. The coil of the contactor usually acts as theundervoltage sensor to drop-out the contactor for a low voltage condition.

9-15

FULL VOLTAGE STARTING

Full voltage starting is when the supply line voltage is applied directly to

the motor winding. This results in a very high starting current until the

motor reaches full speed. This high starting current of typically six

times full-load current causes a voltage drop in the supply system. It

is the simplest and cheapest method of starting because only one

contactor is used, and only three conductors are required for three-

phase motors. Full voltage starting is used for almost all motors of less

than about 100 HP, and wherever the voltage dip can be tolerated, and

the motor loads come up to speed quickly. A schematic diagram of a

typical motor control circuit for full voltage starting is shown above:

9-16

For larger motors where the high starting current cannot be tolerated, some other type of starting is employed which results in a lower starting current. All of these starting systems apply a reduced initial voltage to the motor for typically 2 seconds, until the speed has increased, at which time the full line voltage is applied.

9-17

STAR-DELTA or WYE-DELTA STARTING

Initially the line-to neutral voltage is applied to the motor windings (by connecting the windings in star), and after a short time delay the full line voltage is applied (by connecting the windings in delta). Three contactors are required for this system, and six conductors are required to supply the motor. The motor starting torque isreduced by 33%.

9-18

AUTOTRANSFORMER STARTING

Autotransformers are used to apply the initial reduced voltage to the motor. This system has the advantage that the transformer tap settings can be varied to change the voltage, and starting torque. Also, only three conductors are required to the motor.

9-19

PART WINDING STARTING

Part winding starting initially applies full line voltage to one section of the motor winding, and after a typical time delay of 2 seconds, the remainder of the motor winding is energised. Two contactors are required, and six conductors are needed to the motor.

9-20

9-21

SOLID STATE STARTING

With solid state starters a low voltage is initially applied to the motor and is gradually ramped up to full voltage. The variable voltage is achieved by waveform chopping using SCR's.

9-22

MICROPROCESSOR-BASED CONTROL & PROTECTION DEVICES

Microprocessor-based devices are now widely available to perform many motor control, protection, metering, and monitoring functions. These devices are commonly used on larger motors (above about 2OO HP), where they have become the most economical way of providing all of the various functions. Input signals are required from current transformers, (and sometimes voltage transformers),thermistors or RTD's, contactor status, etc.

The protection functions available in a typical motor managementdevice include overcurrent with a selection of overload curves available, locked rotor, current unbalance or negative phase sequence, ground fault, undervoltage, winding and bearing high temperature.

These devices provide control of the motor contactors for variousstarting configurations, such as star-delta, autotransformer, part winding, and for two-speed and reversing, etc.

The metering function provides a display of motor current, voltage, kW, power factor, and alarm conditions on the front panel of the device.Also, communication ports are included to allow communication withcomputers. This allows for the setup of the devices, and for remotemonitoring by plant computer control systems.

A descriptive leaflet of a typical motor management device is include at the back of this section.

9-23

9-24

��

Transformer Protection

10-1

Transformer Protection

10-2

TRANSFORMER PROTECTION

The various types of protection schemesfor power system transformers include:

• Differential protection• Overcurrent and ground fault

protection• Gas pressure relays• Oil and Winding temperature

devices

APPLICATION OF DIFFERENTIAL PROTECTION TO

TRANSFORMERS

With Bus Differential protection we saw that we compared

the current entering the bus, with that leaving the bus, in

order to detect a fault.

With TRANSFORMER DIFFERENTIAL PROTECTION

we use the same principle. However, we must make a

few changes to adapt that principle for use on

transformers:

10-3

• The C.T. ratios on the transformer primary and secondary sides must be chosen to match the transformer ratio.

• The C.T. secondary windings are usually deltaconnected for a star connected transformer winding, andstar connected for a delta connected winding.This is to accommodate the primary to secondary phase shift.

• Some accommodation must be made for the transformer tap changer, which, of course changes the primary to secondary ratio of the transformer.

• Some accommodation must also be made for the magnetising inrush current which flows when thetransformer is energised. This inrush current can be as high as ten times the full load current of the transformer, and flows into the transformer, but not out.

NOTE: With modern microprocessor-based transformer protection relays it is usual to connect the C.T,’s in Star (or Wye) on both the primary and secondary sides of the transformer. The transformer winding configuration is programmed into the relay, and any phaseangle shift is taken care of by the relay microprocessor.

10-4

OPERATINGCOIL

RESTRAINTCOILS

The C.T. ratios on the transformer primary and secondary sides are

chosen for a current balance with the tap changer in the mid, or

neutral position. As the tap changer moves away from the neutral

position, the unbalance between the primary and secondary C.T.

currents increases.

The transformer differential relay is designed especially to

accommodate this mismatch in the primary and secondary C.T.

currents. The transformer differential relay has both restraint (or

Bias) coils, and operate coils, as shown above.

The differential current flows through the operate coil to make

the relay pick-up, and the through current flows through the

restraint or bias coils, and tends to make the relay restrain.

10-5

If there is an out of zone fault when the tap changer is away from

the neutral tap, then the through C.T. secondary current flowing

through the restraint coils will overcome the tendency for the relay

to operate by the spill current flowing through the operate coil.

The differential relay will not operate for this out-of-zone fault

condition.

10-6

For the “In-Zone” fault shown the current through the ‘operate’ coil is very high, and the net restraining current is low.

The differential relay will operate for this “In-Zone” fault

10-7

When a transformer is energised, there is a magnetising inrush current, which can be as high as ten times the full load current of the transformer. This high inrush current lasts for only a few cycles. However, it can cause the differential relay to operate because it has the appearance of an internal fault (current flows into but not out of the transformer).

This inrush current is predominantly second harmonic. A filter is used to separate the second harmonic component, and the output from this filter is fed into the restraint coil of the relay to restrain operation.

This feature is known as SECOND HARMONIC RESTRAINT, and

is incorporated into all modern transformer differential relays.

On microprocessor-based transformer differential relays the

restraint for magnetizing inrush is achieved in a different way. The

shape of the waveform is analysed by the microprocessor to

determine if magnetizing inrush current is present.

10-8

EFFECTIVE RESTRAINT CURRENT (AMPS)

OPERATECURRENT(AMPS)

The operating characteristics of a transformer differential relay are

shown above:

Note that the `pick up' current of the relay increases with the

amount of through current.

10-9

IMPORTANT:

BECAUSE DIFFERENTIAL PROTECTION REMAINS STABLE FOR `THROUGH' OR ÒUT OF ZONE' FAULTS, IT PROVIDES NOOVERLOAD PROTECTION FOR THE TRANSFORMER.

10-10

OVERCURRENT AND GROUND FAULT PROTECTION

Overcurrent and ground fault protection is commonly used on transformers. This is either as the primary protection for smaller units or any unit without differential protection, or as backup protection on larger units protected by differential relays. For transformers of around 10 MVA and below, primary fuses are normally used.

It is desirable to set the relays or fuses as sensitive as possible.

However, they must not operate for any tolerable condition such as

magnetising inrush, cold load pick-up, or any emergency operating

condition. The ground fault relays must be set above the maximum

zero-sequence unbalance that can exist due to single phase

loading. Overcurrent relays and/or fuses must protect the

transformer against damage from `through' faults. The settings

should be coordinated with the transformer damage curves, and

with the relay settings on the adjacent elements.

10-11

Where transformers are operated in parallel it is not possible to adequately apply overcurrent protection for each transformer, and also provide the necessary selectivity. The overcurrent protection for both transformers can operate for a fault on the L.V. bus of one of the transformers. It is usual practice to apply differential protection where transformers are operated in parallel.

If overcurrent is used as backup protection on transformers operating in parallel, emergency overload conditions must be taken into account when determining the minimum pickup setting.

When one transformer trips, the total load is then carried by the

transformer remaining in service. This can result in emergency

overloading of this transformer of, say, 150%. It may be possible

for the transformer to tolerate this emergency condition for about 2

to 3 hours, providing a winding temperature of 105 degrees C is not

exceeded. During this emergency overload period load shedding

or load transfers can take place to bring the transformer load down

to the nameplate rating, before the windings become overheated.

An overcurrent pickup setting of twice full-load is often used to

allow for this emergency situation.

10-12

RESTRICTED EARTH-FAULT (OR GROUND-FAULT) PROTECTION

Ground-fault protection for each of the windings of a transformer

can be provided by connecting the C.T.’s as shown above for delta

and star (or wye) connected transformer windings.

This system uses the differential principle to detect ground faults

within the transformer.

10-13

GAS RELAYS

The accumulation of gas or changes in pressure inside the tank of oil filled transformers are good indicators of internal faults. Gas relays are used to detect these conditions:

• A very slow build up of gas can be caused byvery low energy arcs and deterioration of insulation, and core problems. This is known as GASACCUMULATION.

• A flashover of arc within the transformer tank will cause a sudden increase in pressure, and cause a surge of oil to flow in the pipe from the top of the tank to the oil conservator. This is known as a GASPRESSURE or SURGE condition.

A single relay is used to detect these two conditions. The relay is

mounted at the top of the transformer, with a pipe from the relay to

the oil conservator tank. Any gas formed in the transformer will

collect in the top section of the relay, depressing the float. This

registers on a gauge on the front of the relay, and will indicate a

GAS ACCUMULATION alarm. This accumulated gas can be bled

from the relay for analysis. The very slow accumulation of gas may

be a tolerable operating condition with some transformers.

A flashover in the transformer will cause a pressure wave to travel

through the oil and will compress the flexible bellows in the bottom

section of the relay. The air inside the bellows will be compressed,

and will cause the flexible diaphragm to actuate the micro-switch to

initiate tripping of the transformer.

10-14

10-15

The above is a simplified cross section of a General Electric Model12 gas relay, commonly installed on North American transformers.

10-16

The relay described previously is the type used on transformers built in North America. Transformers built in Europe use what is known as a BUCHHOLZ relay. The Buchholz relay is mounted in the pipe work from the top of the transformer to the oil conservator tank. It has a gas accumulation feature as described previously. However, the tripping feature of the relay is somewhat different. There is a `flap' in the relay which deflects whenever there is a sudden flow of oil through the relay, towards the conservator tank.

On some transformers the start-up of oil circulating pumps can

cause sufficient pressure change to operate the gas relay. This

should be checked during commissioning tests, and corrected if

necessary.

10-17

OIL AND WINDING TEMPERATURE DEVICES

It is extremely important that transformer temperatures be monitored, and limited to acceptable values. The temperature of the winding insulation determines the life-span of the transformer.

Insulation temperature at the hottest location is known as the hot-spot temperature, and it is the insulation at this hot-spot which ages the fastest. The hot-spot temperature is therefore the limiting factor in determining the life-span of the transformer.

10-18

For a typical transformer with paper insulation:

• If the hot-spot temperature is kept below 90 degrees C the expected life-span is more than 50 years.

• At a temperature of 110 degrees C the life-span is reduced to 7.3 years.

Transformers are usually equipped with devices to monitor the

temperature of the oil and the windings. The first device monitors

oil temperature, and is connected via a capillary tube to a bulb

fitted into a pocket surrounded with oil. The winding temperature

device is similar, except that there is a heater in the pocket with the

bulb. This heater is supplied from a C.T. which is normally in the

white phase primary bushing of the transformer. This heating circuit

is designed to simulate the temperature of the transformer winding.

When the transformer is on-load, the winding temperature device

should, of course, always indicate a higher temperature than the oil

temperature device.

10-19

For transformers equipped with cooling fans and pumps, the temperature devices are used to automatically start and stop the forced cooling. They are also equipped to initiate an alarm and a trip for very high transformer temperatures.

Typical settings are:

75 Degrees C - Start cooling.

65 Degrees C - Stop Cooling.

90 Degrees C - High Temperature Alarm.

105 Degrees C - Trip Transformer L.V. Breaker.

Temperature Rise

Transformer specifications usually include a guaranteed

temperature rise at specific transformer loads.

As an example, a transformer with a nameplate rating of 17.5 MVA:

Guaranteed maximum winding temperature rise of 55 degrees C at

17.5 MVA

Guaranteed maximum winding temperature rise of 65 degrees C at

19.6 MVA

The actual temperature of the winding insulation depends upon the

ambient temperature. For an ambient temperature of 20 degrees C

the maximum temperature of the winding at a load of 19.6 MVA will

be 85 degrees C

10-20

TESTING OF TRANSFORMER PROTECTION

The individual current transformers, and the overcurrent relays are

tested as described previously.

The operation of the transformer differential relay is tested by

injecting current into the C.T. secondary circuit. The basic pick-up

of the relay is tested by passing a current through one restraint coil

in series with the operate coil.

In order to test the restraining characteristics of the relay for

through faults, two current sources are used as shown above. The

pick-up current (I1) is measured for various values of `through'

current (I2). The operation of the second harmonic restraint

feature is tested by passing the test current through a diode, and

noting that the pick-up current of the relay has increased.

10-21

The most effective test of the current circuits on a transformer protection is a PRIMARY INJECTION test.This test should be performed during commissioning, after all of the wiring is complete, and before the transformer goes into service. A three phase short circuit is applied to the L.V. buswork, on the load side of the transformer breaker. The transformer is then energised from a 208 volt, 415 volt, or 600 volt three phase supply. This will produce a primary current of up to about 10 amps. The secondary currents are then measured at the relay panel in all branches of the circuit. A sample test procedure for the primary injection test is attached, along with some actual test results.

Gas relays are tested by injecting air into the relay, or into the pipe

work adjacent to the relay. The relays are usually equipped with a

valve, through which air can be injected from either a pump or a

compressed air bottle.

10-22

The diagram above shows the actual test results for the primary injection test on a 230 kV :44 kV transformer. The purpose of thetest was to verify the correctness of the C.T. circuits and theconnections to the differential relay.

10-23

The diagram above shows the actual test results for the primary injection test on a 500 kV : 230 kV transformer.

10-24

As an exercise, draw in on the above diagram, the magnitude and direction of all of the C.T. secondary currents.

10-25

The above diagram shows a transformer differential protection,combined with H.V. and L.V. Restricted Earth Fault Protection.

10-26

The above diagram shows the actual test results from a primary injection test a transformer differential protection, combined withH.V. and L.V. Restricted Earth Fault Protection.

10-27

Microprocessor-Based Transformer Protection/Management Relays

Most protective relay manufacturers now have modern

microprocessor-based transformer protection/management

relays on the market. These microprocessor-based relays

typically have many different protection, control and

monitoring functions, such as:

• Differential protection with harmonic restraint

• Overcurrent protection for each winding of the

transformer

• Restricted ground fault protection

10-28

• Overexcitation protection, Volts per Hertz & Fifth Harmonic

• Over-frequency, Under-frequency, and rate of frequency decay

• Event recording

• Waveform capture

• Metering

• Tap position

• Harmonic analysis

• Programmable logic

One of the main protection functions of these relays is the

differential protection. With electronic and electro-mechanical

differential relays it is necessary to provided external auxiliary

current transformers to match the H.V. and L.V. C.T. secondary

currents, and to compensate for any phase angle shift across the

transformer. One major advantage of the microprocessor-based

relay is that the C.T. secondary current matching, and the phase

angle compensation is performed within the microprocessor. The

current transformers for the H.V. and L.V. sides of the transformer

are therefore always WYE or STAR connected.

��

General Protection

11-1

Generator Protection

11-2

GENERATOR PROTECTION

Generators are the most expensive pieces of equipment on our power systems. Reliable generator protection schemes are therefore required to minimise damage and repair time following fault conditions.

Generators can be damaged as a result of a wide variety of different fault conditions which may exist on the power system. These fault conditions can be categorised into two groups:

a. Internal faults within the generator zone.

b. External power system faults and/or abnormal operating conditions.

The various fault and system conditions that can cause damage togenerators are:

A. GENERATOR INTERNAL FAULTS.

1. Phase-to-Phase faults on the stator winding.2. Phase-to-ground faults on the stator winding.3. INTER-TURN faults on the stator winding.4. Ground faults in the rotor (or field winding).

B. EXTERNAL POWER SYSTEM FAULTS AND ABNORMALOPERATING CONDITIONS.

1. Phase unbalance (Negative phase sequence).2. Out-of-step (pole slipping or loss of synch)3. Under and over frequency.4. Loss of excitation (Loss of field).5. Overexcitation.6. Reverse power (loss of prime mover).7. Non-synchronized connection of generator.

11-3

B. EXTERNAL POWER SYSTEM FAULTS AND ABNORMAL OPERATING CONDITIONS.

1. Phase unbalance (Negative phase sequence)2. Out-of-step (pole slipping or loss of synch)

3. Under and over frequency

4. Loss of excitation (Loss of field)5. Overexcitation

6. Reverse power (loss of prime mover)7. Non-synchronized connection of generator

All medium to large generators, i.e. 20 MVA to 1000 MVA, will be

equipped with protection schemes to detect most, if not all, of the

above conditions. For small hydraulic generators it may not be cost

effective to provide the same number of protection schemes as

larger units. Also, many smaller hydraulic generators are better

capable of withstanding some of the above adverse conditions,

without damage, than the larger units.

11-4

VOLTAGERELAY

GROUNDINGTRANSFORMER

CIRCUITBREAKER

4 kV22 kV

R

230 kV

Medium and large size generators are usually `Direct Connected' to

a generator output transformer, supplying the output to the high

voltage transmission system. This means that there is no circuit

breaker between the generator and the main output transformer.

With this arrangement the generator is synchronized to the power

system across a 230 kV circuit breaker.

A typical 500 MVA generator has a terminal voltage of 22 kV, and

is directly connected to a generator output transformer to supply a

230 kV transmission system. Such an arrangement is shown

above.

The generator protection zone in the above example includes the

generator, the main output transformer, the unit station service

transformer, and the buswork up to the 230 kV circuit breakers.

11-5

The following protective relaying schemes will normally be appliedto most medium to large size generators:

a. Differential Protection. (87)- To detect phase to phase faults.

b. Stator Ground Fault Protection. (64)

c. Rotor Ground Fault Protection. (64)

d. Phase Unbalance Protection. (46)- To detect negative phase sequence currents which

cause overheating of the rotor.

e. INTERTURN Protection of the Stator Winding.(60)

f. Underfrequency Protection. (81)

g. Out of Step Protection. (21-78)- To detect generator pole slipping due to power system

disturbances.

11-6

h. Loss of Excitation Protection. (40)

i. Overexcitation Protection. (59)- To prevent core saturation due to overexcitation during run

up and shutdown.

j. Reverse Power Protection. (32)- To detect loss of prime mover which causes the machine to

motor.

k. Phase Supplementary Start Protection. (50)- To detect a fault condition as the generator is being run up

to synchronous speed.

l. Phase Back-up Protection (21B)- To detect uncleared generator, transformer, and bus

faults.

The following is a description of typical protective relaying functions

that are used on generators to detect and trip the unit for various

faults and abnormal system conditions.

11-7

DIFFERENTIAL PROTECTION (87)

Differential protection is provided to detect phase to phase faults in the generator zone. With most generators the star point of the stator winding is grounded through a resistor, a reactor, or a grounding transformer. This has the effect of limiting the ground fault current to as little as 10 amps. Consequently, ground faults within the generator zone will not be detected by the differential protection.

Generator differential protection uses the same principles as those

described earlier for Bus Differential protection and Transformer

Differential protection.

11-8

VOLTAGERELAY

DIFFERENTIALRELAY


30 MW GENERATOR

CIRCUITBREAKER

33 kV

600:1

600:1

R

Current transformers are located at each end of the stator winding

as shown in the diagrams. The C.T. ratios are the same, and under

healthy conditions the C.T. current circulates, with no spill current

flowing in the differential relay operating coil. With this arrangement

of generator differential protection there is no magnetizing inrush

current problem. Also, because the currents at each end of the

stator windings are exactly equal, and the C.T. ratios are the same,

then there is no need for the differential protection relay to have

restraint or biasing coils.

11-9

DIFFERENTIALRELAY

VOLTAGERELAY


DIFF’LRELAY

DIFF’LRELAY

R

Since there is not normally a circuit breaker between the generator

and it's output transformer, a set of differential protection is usually

provided, especially on large generators, to include the generator

and the transformer, as shown above. This arrangement has three

sets of differential protection, covering different parts of the

generator and transformer zone. It provides duplication such that

any fault will be detected by two of the three protections.

It should be noted that differential protection will not detect faults

between turns on the same winding (Inter-turn faults) since the

currents entering and leaving the protected section will be the

same during such faults.

11-10

GENERATOR STATORWINDINGS

RELAY

RELAY

RELAY

Differential protection for small generators is sometimes provided

by passing the two ends of each stator winding through the same

C.T. as shown above.

This scheme provides a high speed sensitive protection, and will

detect both phase-to-phase, and phase-to-ground faults (providing

the ground fault level for faults within the differential zone is greater

than the sensitivity).

Copyright 2004 - C.M.Sothwood, P.Eng. 11-11

VOLTAGERELAY

GROUND FAULT

STATORWINDINGS


60 Hz PASS180 Hz BLOCK

RFILTER

STATOR GROUND FAULT PROTECTION (64)

The stator winding of a typical generator is grounded at it's starpoint through a neutral grounding transformer, with a resistorconnected across the secondary terminals. The value of thisresistor is chosen to limit the ground fault current, for phase-to-ground faults on the stator winding, to about 10 amps. A VoltageRelay is connected across the resistor to detect stator groundfaults.

Under normal healthy conditions the grounding transformerdevelops no secondary voltage, and no voltage is applied to therelay. When a stator ground fault occurs, a voltage is developedacross the grounding transformer secondary terminals, and thevoltage relay operates. This condition will usually cause thegenerator to trip, but if the ground fault current is limited to a verylow value, such as 10 amps, then it may just annunciate an alarmcondition.

The above stator ground fault protection is not sensitive for groundfaults very close to the neutral point. It is generally considered thatstator ground fault protection of this type is sensitive for faults on 90% of the winding

11-12

THIRD HARMONIC GROUND DETECTOR USING RELATIVE MAGNITUDECOMPARATOR


STATORWINDINGS

R

V.T.

RELAY

To detect faults on the last 10% of the winding some other type ofprotection must be used. One type of protection that is used todetect such faults compares the third harmonic voltages between the V.T. at the generator terminals, and that at the neutralgrounding V.T. If a stator ground fault occurs, then there will be a change in the third harmonic voltages applied to the relay. Thechange of third harmonic voltage is greatest for ground faults at theneutral end of the winding, and least for ground faults at the statorterminals.

The relay is set to operate if there is a significant change in thethird harmonic voltages applied to it. This type of stator ground faultprotection is most sensitive for ground faults close to the star point,and will operate for faults on about the lower 90% of the statorwinding. This type of protection will usually annunciate an alarmcondition, and not trip the unit. By supplementing the conventionalstator ground fault protection with this scheme, ground faults aredetected on 100% of the stator winding.

11-13

ROTOR GROUND FAULT PROTECTION (64)

The rotor or field winding on large thermal generators is ungrounded, thus a single ground fault produces no fault current. A single ground fault, however, raises the potential of the whole field and exciter system, and the extra voltages induced by opening the field breaker, or the main generator breaker, particularly under fault conditions, may cause a second fault on the field winding. A second fault to ground may cause local heating of the iron which could distort the rotor, causing dangerous unbalance.

If part of the winding is shorted out due to a second ground fault,

the current in the remainder of the winding will increase and may

cause unbalance in the air gap fluxes, and set up serious

vibrations. Thus, it is important to know when a ground fault has

occurred on the rotor winding, so that the necessary repairs can be

made at the earliest convenient time.

11-14

ROTORGROUND FAULT RELAY

MAINEXCITER

GENERATORFIELD

One method of detecting rotor ground faults utilizes a high

resistance connected across the rotor circuit, the centre point of

which is connected to ground through the coil of a sensitive relay

as shown above. This relay will detect ground faults over most of

the rotor circuit. There is, however, a blind spot at the centre of the

field winding which is at the same potential as the mid point of the

resistor, under ground fault conditions. This blind spot can be

tested by arranging a tapping switch which, when operated, shifts

the relay connection from the centre of the resistor to a point a little

to one side. Alternatively, one half of the resistor can be replaced

by a non linear resistor which, since it will change it's value for

different values of rotor voltage, will continuously vary the effective

resistor tapping voltage as the field conditions change.

11-15

AC SUPPLY30V DC

EXCITER

CURRENT LIMITING RESISTOR

ROTORGROUNDFAULTRELAY

ROTOR

FIELDCIRCULTBREAKER

FIELDWINDING

A second method of detecting rotor ground faults is shown above.

The field circuit is biased by a d.c. voltage, which is applied to the

rotor through a fault detecting relay, in series with a current limiting

resistor. A fault on any part of the field system will pass a current of

sufficient magnitude through the relay to cause operation.

11-16

The above sketch shows the arrangement of a brushless exciter.With this arrangement there is no external connection to the rotorfield winding and diodes. It is therefore difficult to apply rotorground fault protection to brushless exciters. One method ofapplying rotor ground fault protection uses optical coupling to therotor.

11-17

PHASE UNBALANCE or NEGATIVE PHASE SEQUENCE PROTECTION (46)

The function of generator negative phase sequence protection is to protect the machine against the overheating effects, which occur as a result of unbalance of the stator phase currents. Such unbalance is usually due to faults, or òpen-circuits' on the external high voltage transmission system. This causes a negative phase sequence component in the stator currents, and since this component produces an armature flux rotating in the opposite direction to the rotor, it induces eddy currents in the rotor mass. These eddy currents, which are at twice the system frequency, will produce local overheating at the periphery of the rotor.

The ability of the machine to withstand this heating effect will

depend to a large degree on it's particular design features, but the

temperature rise of the rotor will depend on the duration of the

negative phase sequence current, as well as it's magnitude. The

heating effects are proportional to I2 x t.

i.e. The square of the negative phase sequence current multiplied

by the time.

11-18

POSITIVE SEQUENCE NEGATIVE SEQUENCE

NEGATIVE PHASE SEQUENCE NETWORK

R

W

B

XN.P.S.

RELAYZB ZR

IWIB

IR

VZR

VZB

IR

IW IB

VZB

VZR VZB+

VZR

A typical Negative Phase Sequence protection scheme is shown

above. The generator C.T's supply a N.P.S. network, across which

a relay is connected. The relay has a setting characteristic which

matches the generator heat build up characteristic. There may be

two stages. The first stage is an alarm, set to annunciate a low

level of negative phase sequence current, and allow some remedial

action to be taken, such as reducing the load on the generator. The

second stage operates for higher levels of N.P.S. current, and trips

the generator before damage from overheating can result.

With today’s modern microprocessor-based multi-function

generator protection relays the level of negative phase sequence is

calculated by the relay microprocessor. The relay is programmed to

alarm and trip at the appropriate settings.

11-19

GENERATOR STATOR WINDINGS

RELAY

RELAY

RELAY

INTERTURN PROTECTION (60)

Split-Phase protection can be used to detect open or shorted

stator turns (inter-turn faults). This type of protection is only

possible when each phase of the stator winding is made in two

similar halves, connected in parallel. The two halves of the winding

are passed through a C.T. in opposite directions as shown above.

A sensitive overcurrent relay is connected to the C.T. secondary.

With no fault on the stator winding, the current in the two halves of

the winding will be equal, and no current will flow in the relay. If an

INTER-TURN fault occurs, then this will create an unbalance in the

two halves of the winding, and current will flow in the relay, causing

it to operate and trip the generator.

11-20

FAULT CONDITIONNORMAL CONDITON

INTER – TURN PROTECTION

OPEN CORNER DELTA VOLTAGE

PHASE TOPHASE VOLTAGE

RELAY COILSIN QUADRATURE

On larger generators where it is not practical to use split phase

protection, very sensitive voltage relays are used to detect

INTERTURN faults. Quadrature coils of the relay are supplied with

a.c. voltages from the generator V.T's.

One pair of coils on the relay is supplied with an òpen-corner-delta

voltage, and the other pair of coils is supplied with the V.T. phase-

to-phase voltage. Under normal healthy conditions the òpen

corner delta' voltage is zero. If a fault develops there will be an

òpen corner delta' voltage, and the two voltages applied to the

relay will produce a torque to operate the relay.

11-21

UNDERFREQUENCY AND

OVERFREQUENCY PROTECTION. (81)

This protection detects system disturbances,

rather than generator faults. A major power

system break-up can result in either an

excess, or insufficient generating power for

the remaining connected load.

In the first case, overfrequency, with possible overvoltage results because of the reduced load demand. Operation in this mode will not produce overheatingunless rated power and approximately 105% rated voltage is exceeded. The generator controls should be promptly adjusted to match the generator output to the load demand.

With insufficient generation for the connected load, underfrequency results, with a heavy load demand. The drop in voltage causes the voltage regulator toincrease excitation. The result is that overheating can occur in both the rotor and the stator. At the same time, more power is being demanded, with the generator less able to supply it at the decaying frequency. Automatic or manualtransmission system load shedding should ideally adjust the load to match the connected generation before a total power system collapse occurs.

As well as these generator problems, Underfrequency and overfrequencyconditions can cause serious damage to steam turbines. Turbine blades are designed and tuned for continuous operation at normal synchronous speed. At other speeds serious vibrations, and possibly resonance, can occur and result in blade damage, particularly on the longer blades at the low pressure end of the turbine.

11-22

Underfrequency protection for a 60 Hertz generator is typically arranged to trip the high voltage circuit breaker if the frequency drops below 57.5 Hz for 10 seconds, or instantaneously if the frequency drops to 56 Hz.

For a 50 Hz generator typical settings are 47.5 Hz for 10 seconds, or instantly at 46 Hz.

Ideally, automatic load shedding from `Frequency Trend Relays‘,‘Rate-of-Change of Frequency’, or Underfrequency relays on the distribution system or transmission system will coordinate with thegenerator underfrequency protection to match the connected load to the available generation, before generators trip.

Underfrequency protection trips only the H.V. circuit breaker, and allows the unit to keep running, and available for service when thetransmission system is restored.

11-23

OUT-OF-STEP PROTECTION (21-78)

Out-of-Step protection detects a condition caused by power system disturbances, rather than generator faults.An uncleared, or slow clearing fault on the transmission system can cause generators to start slipping poles, or go òut-of-step' with the rest of the system.

Such a condition is undesirable because harmful mechanical

stresses are exerted on the shaft, and the severe power swings

have a disturbing effect on the power system voltages. Out-of-Step

protection detects the condition when the generator slips it's first

pole, and causes the generator breakers to trip. The turbine is not

tripped, enabling the machine to be re-synchronized after the

system disturbance is cleared.

This protection can be considered complementary to `Loss of

Excitation' protection. The òut-of-step' condition occurs with the

generator at full field, and the loss of synchronism due to

underexcitation occurs when the generator has no field.

11-24

1

OPERATINGREGIONBLINDER‘B’

X

2

3

OPERATINGREGIONBLINDER ‘A’

R

FOR THE OUT-OF-STEP PROTECTION TO TRIP, THE LOCUS OF THE IMPEDANCE VECTOR Z-LOAD MUST ENER REGIONS 1, 2, 3 (OR 3, 2, 1), IN SEQUENCE.

OUT-OF-STEPIMPEDIANCE OPERATING

AREA

ZLOAD

230 kV BUS

AB

Out-of Step protection uses three impedance measuring relays.

These relays are supplied by the generator C.T's and V.T's, and

measure the generator load impedance.

These relays detect a power swing condition if the three relays

operate in the correct sequence, and will initiate tripping of the H.V.

circuit breakers. The three relays have operating characteristics as

shown above. For tripping to occur, the locus of the generator load

impedance must be within the circle, and must cross both of the

parallel lines.

11-25

LOCUS OF GENERATOR TERMINAL IMPEDANCE SEEN BY RELAY

LOSS OF FIELD

NORMAL FIELDZ LOAD

LOSS OF EXCITATION PROTECTION (40)When a generator loses excitation (or field), reactive power flowsfrom the power system into the generator. The generator thenloses synchronism and runs as an induction generator, abovesynchronous speed. Above synchronous speed the rotor will start to oscillate in an attempt to lock into synchronism, resulting inoverheating and other damage. As long as the system is stable, MVARS will flow into the generator and the machine will continueto put out MW.

Loss of field protection uses a relay that detects the change inReactive flow, from the normal LAGGING condition, to MVARSLEADING. A typical Loss of Excitation Protection scheme uses an Òffset Mho' relay to measure the generator load impedance, and has an operating characteristic as shown above.

The Òffset Mho' impedance relay is a single phase relay, and issupplied from the generator C.T's and V.T's.

The Loss of Field relay will operate if the locus of the loadimpedance falls within the operating characteristic of the relay. Atiming relay is included to initiate tripping of the machine if theLEADING MVARS condition persists for 1 second.

11-26

VOLTS / HzRELAY

V.T.

OVEREXCITATION PROTECTION. (59)

The purpose of overexcitation protection is to prevent the core of

the main output transformer from being saturated during generator

start-up or shutdown. Overexcitation can be explained by the

following expression:

For the core flux B to remain below the saturation point, the

generator voltage may only be increased as the frequency (or

speed) is increased. If the excitation is increased too rapidly, then

this overexcitation condition must be detected, and the field

breaker tripped. Overexcitation protection schemes use Volts per

Hertz relays. These relays have a linear characteristic, and will

operate if V, the Voltage, divided by the frequency exceeds the

set value.

CORE FLUX B αVF

(APPLIED VOLTAGE)(FREQUENCY)

11-27

ZERO TORQUE LINE

POWERPOUT

OPERATE ZONE

PIN

P

V.T.

REVERSEPOWERRELAY

REVERSE POWER PROTECTION (32)

Reverse power protection is provided to detect a condition when

the generator is acting as a motor. This condition occurs when the

steam (or water) supply to the turbine fails, and the generator

draws power from the transmission system. In steam turbines the

steam acts as a coolant, maintaining the blades at a constant

temperature. Failure of the steam supply can cause overheating of

the blades. On some machines the temperature rise is very low,

and motoring can be tolerated for a considerable time. In such

cases the Reverse Power protection will annunciate an alarm

condition, to allow corrective action to be taken without tripping the

generator. Reverse Power protection uses a power directional relay

to monitor the generator load. The relay is supplied from the

generator C.T's and V.T's as shown, and will operate when any

negative power flow is detected.

11-28

CLOSED BELOW 52Hz

TRIP

V.T.

LOW SET O/C RELAY

UNDERFREQUENCY

RELAY

SUPPLEMENTARY START PROTECTION. (50)

Phase supplementary start protection is provided to detect a

condition where a fault exists when the generator is being run up to

speed. Generators must not, of course, be started-up into a load or

into a fault condition. To prevent this, a scheme of protection is

used that switches into service low-set overcurrent relays ONLY if

the frequency is below 52 Hz on 60 Hz power systems, and 42 Hz

on 50 Hz systems. When the generator is ready to pick up load the

overcurrent trip must, of course, be disabled. This is accomplished

by a contact of an underfrequency relay which opens when the

generator approaches synchronous speed.

11-29

V.T.

THE RELAY OPERATES WHEN THE MEASURED LOAD IMPEDANCE FALLS WITHIN THE CIRCLE

RELAYZ

PHASE BACK-UP PROTECTION (21B)

Back-up protection is provided to detect uncleared faults in the

generator, the transformer, or the H.V. buswork.

A typical phase back-up protection scheme, shown above, uses

three impedance relays, supplied by the generator C.T's and V.T's.

These impedance relays measure the absolute load impedance. If

the measured impedance falls below 84% of the combined

impedance of the generator and the generator transformer, then

tripping is initiated.

The impedance relay has a circular, or MHO, characteristic of, say,

7 ohms radius, and tripping occurs if the minimum load impedance

falls within the circle.

11-30

GENERATOR OVERCURRENT PROTECTION VOLTAGE CONTROLLED & VOLTAGE RESTRAINED

Overcurrent relays are often used to provide primary protection for small generators. For larger generatorsovercurrrent relays are applied as Back-up protection.The purpose of the overcurrent protection is to detect and trip the generator for fault conditions. The overcurrent relays are not intended to provide overload protection, as the relay characteristics are in no way related to the thermal characteristics of the generator.

The overcurrent protection C.T.'s should be located at the neutralend of the stator winding, particularly for a single generatorsupplying an isolated system. If the C.T.'s are located at theterminal end of the generator winding, phase-to-phase faults may be undetected.

There is difficulty in applying inverse time overcurrent protection to generators because a phase-to-phase fault near the terminals of the generator will cause the terminal voltage to decrease. The rateof decay is determined by the decrement characteristic of themachine, and the response of the voltage regulator. As the terminalvoltage of the generator decreases, the output current willdecrease accordingly. In many cases the sustained fault currentcan be lower than the generator full-load current. For a fault to be cleared correctly the inverse time overcurrent relay must operateprior to the current decaying to a value below the pick-up setting of the relay.

Voltage Restrained and Voltage Controlled Overcurrent Relaysare used to deal with the problem of decaying voltage and currentat the generator terminals during phase faults.

11-31

In a Voltage Controlled inverse-time overcurrent relay the voltage element is used to inhibit operation of the relay until the sensed voltage falls below a set value.

Voltage Controlled Overcurrent

This voltage inhibit setting is typically adjustable from 40 volts to120 volts as shown above.

The overcurrent relay with voltage control provides sensitiveprotection where the expected fault current is less than thegenerator full load current, and the generator voltage always fallsbelow the voltage inhibit setting of the relay. The voltage inhibit

setting must be low enough to prevent relay operation onrecoverable voltage dips, such as the starting of large motors, andhigh enough to permit the relay to operate before the generator current decays below the overcurrent relay pickup point.

Another type of Voltage Controlled overcurrent relay has twoinverse-time characteristics. The first characteristic providesoverload protection when the generator terminal voltage is normal.The second characteristic provides overcurrent protection forgenerator faults when the voltage falls below a predeterminedvalue.

11-32

The Voltage Restrained inverse-time overcurrent relay uses the sensed voltage from the generator V.T.'s to adjust the current pick-up level.

Voltage Restrained Overcurrent

As shown in the diagram above, when the generator V.T. voltage

falls below the nominal value, the inverse-time overcurrent relay

pick-up setting is lowered proportionally. This has the effect of

shifting the overcurrent characteristic and decreasing the tripping

time as the generator voltage decays.

Instantaneous overcurrent elements are often used to provide

additional protection for close-in high current faults.

11-33

GENERATOR SHORT-CIRCUIT CURRENTIn the event of a short-circuit close to the terminals of the generator the time variation of the fault current isconsiderably affected by the specific characteristics of the generator. The fault current first rises to a high initial value,and then decays to the continuous shot-circuit current, as shown in the typical generator decrement curve on the next page.

To a close approximation the generator short-circuit current can be divided into three components:

•Subtransient Component

•Transient Component

•Continuous Component

This progression of the short-circuit current is determined by the

electromagnetic process that occurs within the generator and the

resulting effect on the voltage. In practice, however, it is usual for

the representation and calculation of short-circuit characteristics to

be based on a constant voltage, and on an assumption that the

decay of fault current is due to an increase in the reactance of the

generator.

Corresponding to the above postulated current components, the

associated reactances are:

• Subtransient Reactance X''d

• Transient Reactance X'd

• Synchronous Reactance Xd

11-34

The Subtransient Reactance influences the fault current for only about the first 0.2 seconds. For a typical value of X''d of 0.11 p.u. the subtransientsymmetrical short-circuit current is:

F.L.C.X9.1=0.11

F.L.C.=dXCURRENTLOADFULL=I ′′

′′

The Transient Reactance influences the fault current for about the first 1 second. For a typical value of X'd of 0.19 p.u. the transient symmetrical short-circuit current is:

F.L.C.X5.26=0.19

F.L.C=dXCURRENTLOADFULL=I ′

′

11-35

The Synchronous Reactance determinesthe sustained short-circuit current, and for a typical value of Xd of 1.35 p.u., the continuous generator short-circuit current is:

F.L.C.X0.74=1.35

F.L.C.=X

CURRENTLOADFULL=Id

The generator current decrement characteristic shown on the next

page is based on the assumption that the field current from the

exciter remains constant during the fault condition. If the generator

is equipped with an automatic voltage regulator the field current will

increase as the generator voltage falls, because the AVR tries to

maintain a constant generator terminal voltage. This has the effect

of increasing the amount of fault current from the generator. The

actual value of the steady-state fault current will depend upon the

characteristics and settings of AVR and excitation system.

11-36

Generator Current Decrement

At V=1pu; time=0 Time Constants

X"d=11% I"d =V(1/X"d-1/X'd) = 3.83pu T"d=0.02s

X'd=19% I' d=V(1/X'd -1/X d) = 4.52pu T'd=1s

Xd=135% I d =V/X d = 0.74pu

g GE MULTILIN

Time(s)

I"d I'd I I total

0.00 3.83 4.52 0.74 9.09

0.02 1.41 4.43 0.74 6.58

0.04 0.52 4.35 0.74 5.60

0.10 0.03 4.09 0.74 4.86

0.20 0.00 3.70 0.74 4.44

0.50 0.00 2.74 0.74 3.48

1.00 0.00 1.66 0.74 2.40

2.00 0.00 0.61 0.74 1.35

5.00 0.00 0.03 0.74 0.77

11-37

Generator Current Decrement

I'd

I"d

Id

Itotal

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

1.40

1.50

1.60

1.70

1.80

1.90

2.00

2.10

2.20

2.30

2.40

2.50

2.60

2.70

2.80

2.90

3.00

3.10

Time (s)

Cur

rent

(pu

)

��

Cogeneration & Non-Utility Generation (NUG)

12-1

Cogeneration & Non-UtilityGeneration (NUG)

12-2

REQUIREMENTS FOR INTERCONNECTION WITH THE UTILITY

PROTECTIVE RELAYING REQUIREMENTS

In general, the design objectives of all protective relaying systems are to minimize the severity and extent of power system disturbances and to minimize possible damage to equipment.

Protective relaying should be provided to detect and clear all faults

on the main power output system in as short a time as possible.

The protection should only isolate the faulted equipment, and allow

the remaining healthy equipment to remain in-service. If these

requirements are met, then the damage to equipment is minimized,

and there should be little effect on other customers on the Utility

Distribution System.

The generator protections described earlier provide protection for

faults within the generator, and also cause tripping of the generator

to prevent it from being damaged due to uncleared faults on the

power system, or other abnormal conditions.

12-3

One possible abnormal operating condition that may be encountered at a Non-UtilityGenerating station is ISLANDING. This is a condition where there has been a break-up of the utility power system, and the generator remains connected to a block of load. It is very unlikely that the block of connected load will perfectly match the generator output, and allow the frequency to remain at 60 Hertz. If there is a deficiency of generation for the remaining block of connected load, then the frequency, and generator speed, will fall. .

Similarly, if there is a surplus of generation for the connected load,the frequency, and generator speed, will increase. These frequencyexcursions are highly undesirable, and can be damaging to theturbine. Overfrequency and Underfrequency protection systems are provided to detect this condition, and disconnect the generator.Typical settings are 59.5 and 60.5 Hertz with a time delay of 1Second. Similarly, if there is a surplus of generation for theconnected load, the frequency, and generator speed, will increase.These frequency excursions are highly undesirable, and can bedamaging to the turbine. Overfrequency and Underfrequencyprotection systems are provided to detect this condition, anddisconnect the generator. Typical settings are 59.5 and 60.5 Hertzwith a time delay of 1 Second.

Overvoltage and Undervoltage protection is also provided todisconnect the generator for excursions in the voltage on the utilitypower system. Typical settings are plus/minus 6% of the nominal voltage.

12-4

Reverse Power Protection

Some electrical distribution utilities require cogeneration plants to install reverse power protection relays at the interface.

The purpose of this reverse power protection is to prevent any in-feed from the generator into the utility distribution system.

12-5

The protective relaying for the feeder to which the generator is connected will normally be located at the utility substation. On power distribution systems at voltages of below 50 kV, the feeders will normally be equipped with OVERCURRENT PROTECTION. With generation connected to the feeder there must be directional supervision of the overcurrentrelays, to ensure that the protection will only operate when fault current flows into the feeder from the substation, and not when current flows out of the feeder. .

When a fault is detected on the feeder and the overcurrent relays

operate, the feeder circuit breaker at the utility substation must trip

to clear the fault current in-feed from the power system. However,

the generator will also be delivering fault current into the feeder to

supply the fault. Therefore, the generator must also be tripped

when feeder faults are detected. A tripping signal is sent from the

utility substation, to the non-utility generating station, to trip the

generator breaker for all feeder faults.

12-6

REMOTE TRIPPING REQUIREMENTS

Various options are available for the Remote or Transfer Tripping Channels between the utility substation and the NUG. These include:

• Frequency Shift Audio-Tone signalling over leased telephone lines

• 125 Volt D.C. Signalling over leased metallic telephone lines

• Fibre-optic cable

• Power-Line-Carrier

• VHF Radio

• Microwave

Duplicate Remote Tripping channels are normally required to

provide the required redundancy. If there is a complete failure of

the remote tripping, i.e. a failure of both channels, then the utility

will normally require that the generator be taken out of service.

The most economical system for most applications will be Audio-

Tone equipment operating over leased telephone lines. Low-cost

transmitter/receiver units are available and are well suited for this

application. It should be noted that precautions may have to be

taken to guard against the hazards of Ground-Potential-Rise, due

to transferred voltage on communication circuits, during phase-to-

ground faults at the generating station. Special isolation equipment

is available for this purpose.

12-7

AUTO-RECLOSURE OF THE FEEDER CIRCUIT BREAKER

The circuit breakers on utility overhead distribution feeders are usually equipped with AUTO-RECLOSING.After the protective relaying has operated and the feeder fault is cleared, the circuit breaker auto-reclosesafter a time delay of 0.5 seconds, to restore the supply to the customers. On radial feeders, where the flow of current is in one direction only, no supervision of the auto-reclose scheme is necessary. However, if there is generation connected to the feeder, then there is a possibility that the feeder could be energised from the generator, and out-of-synchronism with the rest of the power system.

It is therefore necessary to provide voltage supervision to the auto-

reclose scheme to ensure that the breaker can only reclose when

the feeder is dead. A voltage transformer is connected at the

feeder terminal, and the V.T. secondary winding supplies the

voltage supervision relay. Another option is to send information

from the NUG, over a communication channel, to permit auto-

reclose only when the generator circuit breaker is open.

12-8

OPERATING AGREEMENT WITH THE UTILITY

Before the generating station goes into service an operating agreement between the utility and the NUG is signed by both parties. This agreement covers the procedures for operating the high-voltage electrical equipment that is connected to the feeder, the synchronizing of the generator, notification of load changes and planned outages, and maintenance of equipment. .

The utility usually insists on having operating control of the high-

voltage disconnect or load-break switch. This means that NUG staff

cannot operate the switch without instruction from the utility.

12-9

MONITORING OF PLANT ELECTRICAL OUTPUT BY THE UTILITY

The electrical utility will usually monitor the electrical output of non-utility generating stations, and display the information at their system control centre. Ontario Hydro monitors the following quantities for their Data Acquisition & Computer System (DACS):

• Net Generator Output in MEGAWATTS• Net Generator Output in MEGAVARS• Status indication of High-Voltage Disconnect

Switch Position • Status Indication of the High-Voltage Circuit

Breaker Position

This information can be provided by installing a small single-board

Remote Terminal Unit (RTU) at the NUG, and having it

communicate with the utility equipment via modem and telephone

line.

12-10

REVENUE AND BILLING METERING EQUIPMENT

The revenue and billing metering equipment is installed at the NUG site by the utility, at their expense. The electronic meter measures and records the following quantities:

• Megawatt Demand - Import and Export

• Megavar Demand - Leading and Lagging• Megawatt-Hours - Import and Export

• Megavar-Hours - Leading and Lagging

The electronic meter produces pulse output data. These pulses are

fed into a Remote Interrogation Metering System (RIMS) unit for

storage. This RIMS unit is then interrogated, over a telephone line,

by the utility computer to retrieve the meter readings. The same

pulses that are fed into the RIMS unit are available for use by the

NUG if desired. This pulse data can be used by the NUG to monitor

the net plant output to the utility.

��

��

High-Voltage Transmission Line Protection

13-1

High-Voltage Transmission Line Protection

13-2

INTERCONNECTED SYSTEMS WITH TWO-WAY FLOW OF FAULT CURRENT

Time-graded overcurrent protection cannot be successfully applied to high voltage transmission lines because there are usually many interconnected sources of fault current.

13-3

The requirements of protection schemes for high-voltagetransmission lines are:

• The protection system must be able to detect all faults on the protected line.

• The protection system must be able to discriminate between faults on the protected line and faults on adjacent lines, buses, transformers, etc.

• The protection system must be able to clear faults very quickly, ( i.e in less than 0.1 seconds ) before the power system goes unstable.

• The protection system must be dependable, and must be capable of clearing faults when any single piece of equipment has failed.

Protection schemes on high-voltage transmission lines are usually

duplicated to ensure that no single component failure will result in a

failure to detect and clear a fault. The two protection schemes may

be supplied by separate C.T. cores, and use duplicate station

batteries. The high-voltage circuit breakers have duplicate trip coils,

and breaker failure protection is applied.

13-4

The relay operates if the ratio falls below the setting of the relay in OHMS.

DISTANCE OR IMPEDANCE PROTECTION SCHEMES

The basic element of this type of protection scheme is the impedance relay. This relay is supplied with current and voltage from the line C.T.'s and V.T.'s.During a fault condition there is a very high current, and the line voltage falls.

The relay therefore measures line impedance Z.

IV= Zi.e.

(Amps)(Volts)

IV

13-5

V.T.2000:1

500:1

C.T.

IMPEDANCERELAY

In the above example the impedance of the line is 3 OHMS. To

determine the impedance measured by the relay the primary

OHMS must be converted to secondary OHMS by multiplying by

the C.T./V.T. Ratio.

Secondary OHMS = 3 x 500 / 2000 = 0.75 OHMS

This is the impedance measured by the relay. For any fault on the

transmission line, the impedance from the circuit breaker (where

the C.T.'s are located) to the fault will always be less than 3

Primary OHMS, or 0.75 Secondary OHMS, and the relay will

operate.

For any fault beyond the end of the transmission line, the

impedance will be greater than 3 Primary OHMS, and therefore

the relay will not operate.

13-6

V.T.

C.T.TRIP

PIVOT

The simplest type of impedance relay, and that used in the very

early protection schemes, had a beam, pivoted in the middle as

shown in the diagram below. The voltage restraining coil is supplied

from the line V.T., and the current operating coil is supplied from

the C.T.

It is useful to use this example to illustrate the principle of

impedance protection.

Under normal load conditions there is a low current and normal

rated voltage. The beam is therefore pulled down at the left hand

side by the voltage coil and the tripping contacts remain open.

If a fault occurs there is a very high current, and the line voltage

falls. The beam is pulled down to the right hand side because the

pull by the current coil overcomes the pull by the voltage coil. The

contacts then close and trip the breaker.

13-7

The relay just described will operate for fault currents both into the transmission line and out of the line.In order to use this type of relay in a practical protection scheme it would require a directional relay to supervise it and ensure that tripping occurs onlywhen fault current flows into the line.

13-8

LIN

E A

NG

LE

ZONE 2 REACHZONE 1 REACH

75º

TERMINALB

Almost all modern Distance or Impedance protection schemes

use relays with MHO directional impedance characteristics as

shown above. The MHO relay has a circular characteristic which is

set to cover the transmission line as shown above. The relay will

operate for any value of impedance which lies within the circle. The

maximum value of Z for operation is represented by the diameter of

the circle which is shown at 75 degrees to the R axis. This is close

to the typical characteristic angle for a transmission line. The

circular characteristic of the relay cuts the intersection of the X and

R axis. With such a characteristic the relay measures impedance in

one direction only. i.e. When fault current flows into the line. When

fault current flows out of the line, the impedance vector will lie in

the third quadrant, which is outside of the circular operate zone of

the relay.

13-9

Let us now apply such relays to a practical protection scheme for a high-voltagetransmission line. We require relays (or relay elements) to detect all possible fault conditions.i.e.

Phase-to-Phase Faults Phase-to-Ground Faults

A to B A to Grnd

B to C B to Grnd

C to A C to Grnd

Other fault conditions, such as two phases-to-ground, or three-

phase faults can be considered as combinations of these basic

fault conditions.

It is not practical to set an impedance relay to measure exactly the

impedance of the line up to the breaker at the remote end. This is

because of errors in such things as C.T.'s, V.T.'s, Relays,

calculation of line impedance, etc. Because of this we set the relay

to measure, or reach, some impedance less than the full length of

the line. This reach is normally chosen as 75% of the line

impedance, and is called ZONE 1. We must be certain that the

ZONE 1 reach does not extend beyond the remote end of the line.

13-10

A second relay, or relay element, is used to cover the remainder of the line. The reach of this relay must extend beyond the remote end of the line. This reach isnormally chosen as 125% of the line impedance, and is called ZONE 2. We must be certain that the ZONE 2 reach extends beyond the remote terminal of the line.

The complete scheme therefore comprises the following relays, or

relay elements, to detect all of the various line fault conditions:

A to B ZONE 1 A to G ZONE 1

A to B ZONE 2 A to G ZONE 2

B to C ZONE 1 B to G ZONE 1

B to C ZONE 2 B to G ZONE 2

C to A ZONE 1 C to G ZONE 1

C to A ZONE 2 C to G ZONE 2

The ZONE 1 relays cause the local circuit breaker to trip with no

intentional time delay. The ZONE 2 relays cause tripping after a

time delay of typically 0.4 seconds.

13-11

ZONE 2 REACH

ZONE 1 REACH

IMPEDANCERELAY

F2F1

Faults on the transmission line are therefore cleared as follows:

For a fault at F1 the ZONE 1 relay sees it and operates and trips

the circuit breaker at station A with no intentional time delay.

For a fault at F2 the ZONE 2 relay operates and trips the breaker at

station A after a time delay of 0.4 seconds.

If station B has similar relays to station A, faults F1 and F2 will both

be detected by the ZONE 1 relays at B. The relays will therefore

trip the station B breaker without intentional time delay for both

faults.

With this scheme of protection we can see that we do not get high-

speed clearance for all faults. i.e. Faults within 25% of either

terminal are cleared at the far terminal after a time delay.

13-12

By adding a communication channel in each direction, between the two terminals, we can coordinate the operation of the relays at each end to give instantaneous clearance for all faults on the line. This channel is known as an acceleration orpermissive channel. The acceleration signal is sent to the other end whenever the ZONE 2 relays operate. When an acceleration signal is received it by-passes the ZONE 2 time delay, and makes ZONE 2 tripping instantaneous.

13-13

ZONE 2OF A

ZONE 2OF B

ZONE 1OF B

ZONE 1OF A

F4

F2F3 F1

BA

Now let us consider faults at various locations on the high-voltage

line shown above:

• For a fault at position F1 the ZONE 1 relays at each end will

operate and trip the line instantaneously. Also, the ZONE 2 relays

at each end will operate and send acceleration to the other end.

When acceleration is received at each end the ZONE 2 relays will

also trip without a time delay.

• For a fault at position F2 the ZONE 1 relay at end B operates

and trips that end instantaneously. The ZONE 2 relay at end B also

operates and sends an acceleration signal to end A. At end A the

ZONE 2 relay operates and starts the timing relay. When the

acceleration signal is received at end A the timing relay is

bypassed, and the ZONE 2 relay will trip without a time delay.

13-14

• For a fault at position F3 the sequence is similar to that for F2, but with an accelerated ZONE 2 at end B.

• For a fault at position F4, NONE of the relays at end B will operate because they only look in the forward direction. At end A the ZONE 2 relay will operate and start the ZONE 2 timing relay. Noacceleration signal will be received, therefore the protection at end A will not trip unless the fault stays on for 0.4 seconds. By this time, of course, the fault should have been cleared by the protection on that particular system element.

13-15

13-16

Another application of impedance, or distance,protection is to utilize a BLOCKING channel instead of the acceleration channel. This scheme has ZONE 1 and ZONE 2 impedance relays as before. The ZONE 1 relays trip instantaneously. The ZONE 2 relays also trip instantaneously unless a BLOCKING signal is received from the other end. If a BLOCKING signal is received and the ZONE 2 relay remains operated, tripping takes place after 0.4 seconds. The BLOCKINGsignal is sent by a third relay element which operates for faults in the reverse direction, but will never operate to send BLOCKING for faults on the protected line.

13-17

13-18

PHASE COMPARISON PROTECTION SCHEMES

Another protective relaying system for high-voltagetransmission lines is Phase Comparison Protection. This system uses the principle of comparing the phase angle between the currents at the two ends of the protected line. During external faults the current entering the line is of the same relative phase angle as the current leaving the line, and the phase comparison relays at each terminal measure little or no phase angle difference.

The protection therefore stabilizes and no tripping occurs. For an

internal fault the current will enter the line at both ends, and the

phase comparison relays detect this phase angle difference. The

relay then operates to clear the fault. With phase comparison

schemes starting relays are used to start the phase comparison

process whenever a fault condition is detected. These starting

relays must operate for both internal and external faults. A reliable

communication channel is required for phase comparison

protection. Until a few years ago power line carrier was used as

the communication channel for almost all phase comparison

schemes. More recently microwave systems and fibre optic cables

have been used.

13-19

Line Differential ProtectionThe fundamental principle of differential protection is applied to the transmission line by comparing the current entering the line at one terminal, with the current leaving line at the remote terminal.

The line differential relays at each end of the transmission line compare data on the line current via a fibre-optic communications link.

13-20

Line Differential ProtectionThe line differential relays at each end of the transmission linecompare data that is exchanged via a fibre-optic link between the two terminals. Many utilities have a fibre-optic cable embedded in the skywire of H.V. transmission lines.The relays compare themagnitude and phase angle of the current entering the line at oneend, with the current leaving the line at the other end. If the two are not equal, within a reasonable tolerance, then a fault condition isdetected, and the line is tripped. The relay also has various otherprotection elements, such as instantaneous overcurrent, timedovercurrent, phase and ground directional overcurrent, anddistance (or impedance).

The distance, or impedance element is often used for back-upprotection. Direct tripping is provided between the two terminals of the transmission line.

13-21

COMMUNICATION CHANNEL REQUIREMENTS BETWEEN TERMINALS

In order to achieve high-speed tripping for faults on transmission lines, reliable communication channels are required between the protective relaying equipment at each terminal of the line. Highquality communication channels are required for the following functions associated with transmission line protections:

• Acceleration or Blocking signals for Distance or Impedance protection schemes.

• Communication channel for Phase-Comparisonprotection.

• Direct Tripping channel between terminals of the line.

• Communication channel for Pilot-Wire protection.

13-22

The various types of communication channels commonly used for the protection of high-voltagetransmission lines include:

• Metallic Pilot Wires. This type of channel may be direct buried cable and customer-owned, or a circuit leased from the telephone company. Limited to fairly short distances.

• Voice-Frequency Tone circuit leased from telephone or communications company.

• Microwave Channel. This is very expensive unless the channel can be shared for many transmission lines and/or other users.

13-23

• Power Line Carrier. The signals are injected into the power line through the C.V.T.'s, and is used extensively for inter-tripping, acceleration, and phase-comparison,particularly on very long lines.

• VHF Radio. Must be line-of-site, and is limited to fairly short distances.

• Fibre Optic Cable. The fibre may be leased from a communications company, or installed as part of the transmission line earth-wire or sky-wire. This practice is becoming very common in electrical utilities, where fibre-optic earth-wire or sky-wire is being installed on many new transmission lines. This has the advantage that the electrical utility can lease out spare fibres in the sky-wire or earth-wire to communication companies.

13-24

��

��

Static Capacitor Protection

14-1

Static Capacitor Protection

14-2

STATIC CAPACITOR PROTECTION

Shunt capacitor banks are used at transformer stations in 15 kV, 25 kV, 33 kV and 44 kV sub-transmission systems for voltage control, and power factor improvement.

The basic building block of these capacitor banks is the single

encapsulated capacitor unit, with many elements in a series -

parallel arrangement. The individual elements are made from

aluminum foil sheets, separated by a paper film insulation,

immersed in a liquid dielectric, and contained in a metal tank. The

capacitor unit can be either a two-bushing type or a single bushing

type. The capacity of each unit is usually 200 kVAR or 300 kVAR,

at voltage ratings of about 8 kV to 16kV.

The individual units (or cans) may be arranged in various

configurations, with different series - parallel arrangements to

obtain the required bank ratings. The units are mounted on

insulated racks, and are interconnected.

14-3

Some of the configurations that are commonly used are:

1. Grounded Star

2. Grounded Double Star

3. Ungrounded Star

4. Ungrounded Double Star

14-4

SERIESGROUP 1

SERIESGROUP 2

SERIESGROUP 3

FUSES

200KVARCAPACITORS

FUSES

CAPACITORS

FUSES

CAPACITORS

CAPACITORBREAKER

CAPA

CITO

RAR

RANG

E.SIM

ILAR T

O W

PHAS

E

A typical arrangement of a Grounded Star capacitor bank is shown

above:

14-5

CAPACITOR UNIT FUSING

The first line of protection for a capacitor bank is the individual, external, indicating capacitor fuse asshown in the diagram on the previous page. The fuse should sense a failed capacitor unit and isolate the defective unit from the bank fast enough to prevent case rupture in the presence of heavy energy discharge from the other healthy parallel capacitors. The I2t rating of the fuses must be adequate to avoid operation on normal transient in-rush currents. Abnormal in-rush currents resulting from capacitor back-to-back switching (one energised when another is connected to the same bus) should also be considered.

A capacitor bank can continue to operate in spite of the loss of a

limited number of units in a series group. Fuses give a visible

indication when they blow. The isolation of a failed capacitor unit by

its fuse results in an increased impedance of that series section

from which the faulty unit has been removed. The larger the

number of units removed, the higher will be the increase in

impedance of that series section. As there can be many sections in

series, the effect of increased impedance in one section does not

decrease the phase current in the same relative inverse proportion.

As a result, the slightly reduced current flowing through a more

markedly increased impedance causes a higher voltage to appear

across the remaining units in that section. If the situation remains

undetected and not corrected within a reasonable time, the higher

voltage can cause a progressive `cascading' failure of the units,

leading to the eventual blowing of all the fuses in the series group.

14-6

PROTECTION CONSIDERATIONS

A shunt capacitor bank should be in service whenever load conditions require power factor improvement and voltage regulation.

Ideally, the bank should not be tripped for one or two failed

capacitor units in one series group, provided the remaining units

are not subjected to an overvoltage exceeding 10% of their rated

voltage. At the same time, the protection should ensure removal of

the bank from the system before it is exposed to severe damage

either from excessive overvoltage or from fault currents. The

protection should not maloperate because of in-rush currents as a

result of switching, or because of out-rush currents as a result of an

external fault.

14-7

The capacitor bank protection should detect the following conditions:

A. Overcurrents due to capacitor bankBUS faults.

B. System steady-state overvoltages.

C. Overcurrents due to individual capacitor unit failure.

D. Continuous capacitor unit overvoltages.

E. Flash-over within the capacitor rack.

Individual capacitor fuses protect against rupture or case-bursting

of failed units. The blown fuses prevent interruption in operation of

the bank, and give a visual indication of failed units to facilitate their

replacement. Protection against system surge voltages is normally

provided by spark gaps or surge arrestors at the capacitor.

14-8

CAPACITOR BANK OVERCURRENT PROTECTION

Conventional overcurrent relays, both Phase and Ground, provide protection against bus faults. i.e. The faults occurring on the buswork between the circuit breaker and the capacitor bank. Overcurrent relays with both instantaneous and inverse timed elements are used. The inverse time delay will override the transient in-rush currents, including those of back-to-back switching.

The relays are supplied with current from the C.T's located in the

bushings on the bus side of the capacitor circuit breaker.

The inverse time elements are set low enough to respond to rack

faults of capacitor banks with more than one series group in each

phase. A rack fault can be an arc-over of a single series section or

a number of series groups, caused as a result of a foreign object

initiating the short. Unlike other equipment where the arc-over is

line-to-ground or line-to-line, the flash-over in a capacitor bank can

be across only a portion of the line to neutral voltage. As a

consequence, the fault current is smaller than the typical phase-to-

phase or phase-to-ground faults.

14-9

PHASE OVERVOLTAGE PROTECTION

The phase overvoltage relays protect the capacitor against sustained system overvoltage.

The voltage ratings of capacitor banks are generally higher than

the maximum system operating voltages. Since other elements of

the system are more vulnerable to damage from system

overvoltages than the capacitor banks, the capacitor bank phase

overvoltage protection may be viewed as a system overvoltage

protection. The overvoltage relay is connected phase-to-phase to

the bus V.T. secondary. A time delay relay is included in the

tripping circuit to reduce the chances of false trips due to transient

overvoltage conditions.

14-10

OVERCURRENT IN INDIVIDUAL CAPACITOR UNITS

As described earlier, a damaged capacitor unit, which would cause currents to increase, is isolated by the fuse which serves the double duty as a protective device and a disconnect switch.

Fuse co-ordination is important for reliable protection. The fuses

must be able to withstand the inrush, transient, and discharge

currents; but excessive currents must be interrupted for individual

capacitor units to avoid case rupture.

14-11

CONTINUOUS CAPACITOR UNIT OVERVOLTAGE PROTECTION

NEUTRAL UNBALANCE

Loss of one or more capacitor units causes an increase in the voltage across the remaining units within the group. A continuous excessive overvoltageis detrimental to the capacitor units. Protection is therefore needed to sense the capacitor bank unbalance, and to alarm the operator, or to trip off the bank in cases of overvoltages exceeding about 110%of the rated voltage.

An unbalance in the grounded-star capacitor bank will cause

current to flow in the neutral. Likewise for the double star-

ungrounded bank whose neutrals are tied, an unbalance in one of

the two stars will cause current to flow in the neutral.

By providing overcurrent relays to sense the currents in the

neutrals of grounded star capacitor banks, continuous capacitor

unit overvoltage conditions can be detected. Two instantaneous

overcurrent relays are used. The first one has a low setting such

that it will initiate an alarm if a single capacitor fuse has blown. The

second relay has a higher setting and will trip the capacitor bank if

a specific number of units fail which results in more than 10%

overvoltage on the remaining units. This second relay should also

trip the bank for rack faults. Both of these relays are time delayed

to prevent operation for transient in-rush or external ground faults.

14-12

MICROPROCESSOR-BASED CAPACITOR PROTECTION & CONTROL SYSTEMS

Microprocessor-based systems have recently become available to perform the many protection functions for static capacitor banks, as well as having features to provide automatic control. As an example, a brochure is attached for a recently introduced unit which provides digital protection and control of capacitor banks. This brochure illustrates the various features available on such units.

��

Recent Developments and Future Trends inProtective Relaying

15-1

Recent Developments and Future Trends in Protective

Relaying

15-2

DIGITAL MICROPROCESSOR-BASEDRELAYS

In the last few years digital microprocessor-based relays have been introduced to allareas of protective relaying. With the many features available in these relays they are revolutionizing the way that protection,control, and monitoring is being appliedin high-voltage substations.

15-3

The features of modern microprocessor-based relays include:

• Many Functions in a Single Relay.

• Group Settings Readily Changeable forchanges in feeder configuration.

• Programmable Output Relays

• Communication Ports for connection to SCADA Systems, Modems, and Personal Computers

• Sequence-of-Events Stored for many recent faults

15-4

• Oscillography or waveform capture – storageof pre and post-fault current & voltage waveform data for analysis of faults

• Measurements – current, voltage & maximum demand can be displayed & recorded.Calculated values such as MW, MVA & MVAR can be displayed.

• Aid to circuit breaker maintenance. Fault interrupting duty, per phase, can be recorded.

• Fault Locater – Displays distance to fault.

• Other special features such as ‘cold-load-pick-up’

15-5

DIGITAL SIGNAL PROCESSORS

The digital signal processor, or DSP, is the heart of modern microprocessor-basedrelays. The DSP digitizes the A.C. signals from the C.T.’s & V.T’s at a rate of many times per cycle. The DSP continuously uses the digital data for multiple functions, such as protection, fault recording, fault location, metering, power quality, etc.

Algorithms are performed on the data to detect fault conditions that are

determined by the settings which are programmed into the DSP, or

relays. Data is processed by the DSP at a very high speed. The output

data is then passed on to the control computer or microprocessor. This

output data can be a digital signal to indicate that a fault condition has

been detected, and tripping must result. The output data may also be

RMS values of current & voltage, etc. for the display of indicating

metering.

15-6

OPTICAL CURRENT TRANSFORMERS

The use of optical C.T.’s or opticalcurrent transducers in modernprotective relaying applications will likelyincrease considerably in the comingyears. There is the expectation that thedevelopment of optical C.T.’s will lead to much simpler structures, andconsiderable cost savings over existinghigh-voltage free-standing C.T.’s.

The optical signals are compatible with the latest types of

microprocessor-based devices. Although optical current transducers are

still in the development stage, there are many units in-service at various

locations throughout the world, and electrical utilities are gaining

operational experience with this technology.

A diagram showing Faraday cell, and the principle of operation of the

optical current transducer is included later in this section

15-7

15-8

15-9

FIBRE OPTIC COMMUNICATIONS

Fiber optic communications is gaining widespread use in power system protective relaying. In Substations fibre optic cable is being used for communication between various microprocessor based relays, and between optical current transducers and relays of D.S.P.’s. Many protection tone channels and inter-tripping circuits between substations use fibre optics, often utilizing fibres built into the earth-wire or sky-wire of transmission lines.

One difficulty faced by utilities today is the need to communicate with the many different makes and types of microprocessor-based devices installed in large transmission and distribution stations.

The industry is working towards the development standards that willallow different makes of relays to communicate with each other.

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