Advanced Techniques In Power System Protective Relaying.pdf

+DUYDUG7HFKQRORJ\0LGGOH(DVW

Advanced Techniques In Power System Protective Relaying

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

Copyright © 2004 by Harvard Technology Middle East. All Rights Reserved

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Disclaimer The information contained in these course notes has been complied from various sources and is believed to be reliable and to represent the best current knowledge and opinion relative to the subject. Harvard Technology offers no warranty, guarantee, or representation as to it’s absolute correctness or sufficiency. Harvard Technology has no responsibility in connection therewith; nor should it be assumed that all acceptable safety and regulatory measures are contained herein, or that other or additional information may be required under particular or exceptional circumstances.

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Section 1

Power System Faults

Section 2

Components of Protection Schemes

Section 3

Current Transformers & Voltage Transformers

Section 4

Power System Neutral Grounding

Section 5

Ground – Potential – Rise During Power System 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 in Protective Relaying

Introduction

ELECTRICALPOWER SYSTEM PROTECTIVE RELAYING Protective relaying is the Science or Art of detecting faults on power systems and clearing those faults from the power system as quickly as possible.

SEMINAR OBJECTIVES T0 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.

 

    6HFWLRQ  Power System Faults

Power System Faults

1-1

A power system fault is the breakdown of insulation (between conductors, or between a phase conductor and ground) which results in excess current flow.

1-2

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.

1-3

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.

1-4

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.

1-5

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.

1-6

1-7

The most common causes of faults on overhead lines are: 1) Lightning 2) Contaminated Insulators 3) Punctured or broken insulators 4) Birds and animals 5) Aircraft and cars hitting lines and structures 6) Ice and snow loading 7) Wind In electrical machines, cables and transformers, faults are caus ed by: 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.

1-8

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-reclose will 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 autoreclosed 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.

1-9

Faults in generators, motors, transformers and cables etc. are normally permanent and autoreclose 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.

1-10

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.

1-11

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 (shortcircuit calculation) is given at the end of this section, with a worked example.

1-12

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.

1-13

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.

1-14

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.

1-15

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 protective

relaying systems, and cleared from the systems the opening or tripping of circuit breakers. Fault detecting relays typically operate in about 1 cycle, or 20 milliseconds, 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 protection is often used for fault clearance. i.e. For high fault currents, there is fast clearance. For lower fault currents, the fault clearance time is much slower. The operating time of circuit breakers on distribution systems is typically 5 to 7 cycles, or 100 to 140 milliseconds.

1-16

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 ohmic method, it is usually simpler to use the Per-Unit Method where all of the impedances are referred to an arbitrarily chosen common BASE MVA. 4. Convert all of the various impedances to per-unit values with a common base MVA. 5. Find the total Resistance R, and Reactance X, from the source to the fault.

6. Calculate the total Impedance Z:

Z =

R2 + X2

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

I3phase =

Vphase Z

Calculate the PHASE -TO PHASE FAULT CURRENT

I2phase =

V phase-phase 3 = 2 2Z

I3phase

Calculate the PHASE -TO-GROUND FAULT CURRENT

Iground = V phase Z + ZN

1-17

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. BASE MVA

SOURCE P.U. IMPEDANCE Z PU =

SOURCE S.C. MVA TRANSFORMER P.U. IMPEDANCE ZPU =

FEEDER P.U. IMPEDANCE ZPU = 3-PHASE S.C. MVA AT FAULT

=

RMS SYMM S.C. CURRENT AT FAULT

ZT % 100 ZOHMS

BASE MVA

*

TRANSFORMER MVA BASE MVA

*

kV2

BASE MVA TOTAL ZPU =

BASE MVA 3

=

*

kV * ZPU

S.C. MVA 3

*

kV

1-18

Short Circuit Calculations VØ

ZØ VØ - Ø

FØ - Ø

F 3Ø

ZØ ZØ 3 – PHASE FAULT CURRENT

VØ ZØ

I3 =

PHASE TO PHASE FAULT CURRENT

I2 =

=

VØ – Ø 2 ZØ 3

x

I3 PHASE

2

Phase To Ground Fault VØ

ZØ ZØ

FØ - G

ZØ

ZN PHASE TO GROUND FAULT CURRENT=

VØ ZØ + ZN

1-19

Example of Fault Current Calculation Source S.C. MVA = 350

44KV

Line Impedance

Base = 100

Z = 12.0 44KV / 13.8KV 20MVA

Transformer Impedance Z = 7.7%

MVA

Assume X/R ratios are HIGH, thus resistances are ignored

Feeder Impedance Z = 5.0 13.8KV Fault

100 MVA 350 MVA =

Source PU Z = 44KV Line P U Z =

Transformer P U Z =

12

x 100 MVA (44KV)2

7.7 %

x

100

100 MVA

=

0.620

=

0.385 pu

=

2.625 pu

20 MVA

13.8KV Feeder P U Z = 5

x

100MVA

0.286 pu

13.8 K V

pu

Total impedance from source to fault = 3.916 pu 100MVA

Three Phase SC MVA = RMS SYM SC Current =

3.916 pu

=

25.54MVA = x 13.8 K V

3

25.54 MVA 1068A

1-20

6HFWLRQ  Components of Protection Schemes

Components of Protection Schemes

2-1

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:

C.T. 1200:5A

CIRCUIT BREAKER

110V D.C. SUPPLY

OVERCURRENT RELAY

TRIPPING RELAY

TRIP BREAKER

2-2

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 electromechanical 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 pickup setting is usually adjusted by a dial or by setting DIP switches. Both the electro-mechanical and the electronic versions are functionally identical.

2-3

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.

2-4

The relay characteristic is such that for very high fault currents the relay will operate in it's Minimum time of 0.2 seconds. For lower values 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 relay has a definite minimum pick-up current of 4 Amps. This minimum pick-up current must, of course, be greater than the maximum load on the feeder. The induction disc relay normally has various current tap 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, on adjacent power system elements. As with the instantaneous overcurrent relays, there are now many electronic timed and Inverse Definite Minimum Time overcurrent relays on the market. Their characteristics 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 be covered later in this seminar.

2-5

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 voltage transformers, and are set to operate for certain overvoltage or undervoltage conditions. For example, to protect capacitor banks 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 and leaving the protected zone. If the unbalance is great enough, then a fault condition is detected, and tripping is initiated. For transformers, the differential relay must have some biasing to provide relay restraint for through currents. This will be explained later when we cover Transformer Protection. 2-6

Other Fault detecting relays include those used in Generator Protections, such as Negative Phase Sequence, Overexcitation, Loss of Field, Underfrequency, Out-ofstep, etc. The application of the various relays to power system protection schemes, will be discussed later in the seminar.

2-7

THE TRANSITION FROM ELECTRO-MECHANICAL RELAYS 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 relay which 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 electromechanical 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. 2-8

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.

2-9

TRIPPING AND OTHER AUXILIARY RELAYS Power system faults are detected by the fault detecting relays, which close their output contacts to initiate tripping. These output contacts are used to energise trip relays 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.

2-10

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 of time. 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.

2-11

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.

2-12

C.T. 1200:5A 300A

44kV 1.25A 1.25A

RELAY

Note that the C.T. polarity markings are shown as spots on the primary and secondary sides of the C.T. Also, it is important that the C.T. secondary circuit be grounded, and grounded at one point only.

2-13

SECONDARY WINDING

PRIMARY CONDUCTOR

IRON CORE

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.

2-14

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 voltage transformer connected across the bottom capacitor. This V.T. actually measures one-tenth of the line voltage, as illustrated in the diagram above.

2-15

    

6HFWLRQ  Current Transformers & Voltage Transformers

Current Transformers & Voltage Transformers

3-1

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, which forms 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.

3-2

Oil Circuit Breaker Bushings

Current Transformers Fixed Contact

Moving Contact

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.

3-3

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.

3-4

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 primary conductor within the porcelain. With this type, the tank housing the toroid is at ground potential. The primary conductor is insulated for the full line 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 used where 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 be accommodated in Air Blast circuit breakers, or some outdoor SF6 breakers. Free Standing current transformers must therefore be used with these types of switchgear. Current transformers often have multiple ratios. This is achieved by having taps on various points of the secondary winding, to provide the different turns ratios. Later in this section we will discuss the characteristics and testing of C.T's. 3-5

3-6

TEN EQUAL CAPACIATORS

VOLTAGE TRANSFORMERS 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 33 kV are normally of the WOUND type. That is, a two winding transformer in an oil filled steel tank, with a turns ratio of 416.6:1 or 275:1. On higher voltage systems, such as 230kV and 500kV, CAPACITOR VOLTAGE TRANSFORMERS, (or CVT's) are normally used. A CVT is comprised of a capacitor divider made up from typically 10 equal capacitors, connected in series from the phase conductor to ground, with a voltage transformer connected across the bottom capacitor. This V.T. actually measures one-tenth of the line voltage, as illustrated in the diagram above:

3-7

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.

3-8

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.

3-9

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.

3-10

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.

3-11

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 `open circuit' Whilst primary current is flowing, dangerously high voltages will appear across the C.T. secondary terminals. Extreme care must be exercised when performing `on load' tests on C.T. circuits, to ensure that a C.T. is not inadvertently `open circuited'.

3-12

C.T. ACCURACY A typical protective relaying C.T. has it's accuracy specified as: 2.5

2.5%

L 800

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 & 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.

3-13

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.

VOLTAGE TRANSFORMERS The accuracy for a typical voltage transformer is specified as: 0.6 0.6%

Z 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 VA X = 25 VA Y = 75 VA Z = 200 VA ZZ = 400 VA

3-14

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 optical current 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.

3-15

VARIABLE 120v A.C. SUPPLY (VARIAC)

TESTING OF CURRENT TRANSFORMERS During field commissioning, the following tests are required for Current Transformers: C.T. Excitation Curves The purpose of this test is to verify that the C.T. meets the specifications, and will not saturate during maximum fault conditions. The C.T. characteristics will have been specified by the designer 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 in steps of, say 50 volts, and the C.T. magnetizing current is measured in milli-amps, up until the C.T. saturates. The results obtained should be similar to those specified in manufacturer's test data, and also to the results for similar C.T.'s. NOTE:

The C.T. primary must be `open circuit' when performing excitation tests. 3-16

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.

3-17

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.

3-18

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.

3-19

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.

3-20

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.

3-21

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.

3-22

 6HFWLRQ  Power System Neutral Grounding

Power System Neutral Grounding

-4 1

• • • • •

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 2

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 3

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 4

Among the technical reasons are: • The floating potential on the lower voltage (secondary and tertiary) windings is held to a harmless value. • Arcing faults to ground do not set up dangerously high voltages on the healthy phases. • By controlling the magnitude of the groundfault 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.

-4 5

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 6

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 7

Resistance Grounded Systems A 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 8

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 9

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 10

Reactance Grounded Systems A reactance grounded system is one where the neutral point is connected to ground through a fixed reactor. Again, this is `noneffective' 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 11

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 12

Ground-Fault Detection on Ungrounded Systems On ungrounded systems, a single ground-fault will not result in the flow of any faultcurrent

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 13

GENERATOR NEUTRAL GROUNDING

-4 14

• Reasons for Limiting Generator Ground Fault Current • Methods Used to Ground the Neutral of Generator Stator Windings • Detecting Generator Stator Ground faults

-4 15

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 16

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 17

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 18

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 19

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.

-4 20

6HFWLRQ  Ground–Potential-Rise During Power System Faults

GROUND-POTENTIAL-RISE DURING 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

5-1

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-carrying metal structures and equipment are maintained at the same voltage and that hazardous step and touch voltages do not occur. Equipment Protection The grounding system must be designed to limit the level of transient voltages on station equipment by providing a low impedance path for lightning 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 and surge arresters. The grounding system has an influence on the levels of power system overvoltages and fault current, and the choice of protective relaying.

5-2

WHAT IS GROUNDING?

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

5-3

WHAT IS BONDING?

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

5-4

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 the various 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.

5-5

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 station will be at different voltages during the period of time that fault current is flowing. Hazards to persons working in the sub-station exist because different parts of the human body can bridge across points where a voltage 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.

5-6

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:

Ik =

0 .116 Amps t

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:

Ik =

0.157 Amps t

5-7

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.

5-8

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.

5-9

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 1 Metre.

5-10

Transferred Voltage 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. An example of transferred voltage is where communication cables run between 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.

5-11

Approximating the shoe by a metallic disc of radius 0.083 Metres

R

F

= 3K

ρ

S

where: K = 1.0 for soil immediately beneath the feet which 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.

5-12

Tolerable Limits of Step & Touch Voltages The maximum permis sible step voltage is calculated from the threshold current constraint, and the body circuit resistance through both feet in series.

V S = I K ( R K + 2 R F ) Volts Where Rk is the electrical resistance of the human body, and normally taken as 1,000 Ù.

The equation for step voltage limit becomes:

VS=

116 + 0.7K ρ S Volts t

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

⎛ RF ⎞ ⎟ V T = I K ⎜ RK + 2 ⎝ ⎠

VT=

116 + 0.17K ρ S t

5-13

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.

5-14

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

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

5-16

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.

r=

As π

Calculate the station ground resistance (for unfrozen soil).

R= where

ρe ρ + e 4r L

Ohms

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 shielding or sky-wires, cable sheaths, etc. This should be taken into account when determining the fault current that flows to ground through the station ground grid. 5-17

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 the ground 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.

5-18

5-19

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 grounding system. 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.

5-20

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 of the stone. Substation Fence Electrical regulations usually require that the substation fence be located at least one metre inside the perimeter of the station ground grid. The fence must be connected to the ground grid at various places This reduces the touch voltage for a person standing outside, and touching 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, and touching the fence.

5-21

Some utilities choose to have substation fences isolated 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 connected to the station ground grid.

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

5-22

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.

5-23

GPR and Transferred Voltages

• GPR and Transferred Voltages • Hazards of Communications cables Entering High-Voltage Substations • Control of Transferred Voltage Hazards • Neutralizing Transformers • Optical Isolation Equipment

5-24

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.

5-25

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 the substation. 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 5,000 volts relative to the remote ground at the other end of the telephone circuit. This can cause serious damage to the communications equipment, and poses a serious hazard to any personnel who may be using or working on the circuit.

5-26

Two devices that are commonly used to control this hazard are neutralizing transformers and teleline optical isolators. Neutralizing Transformers The diagram above shows a neutralizing transformer for a single pair telephone circuit.

5-27

Optical Isolation Equipment

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

5-28

5-29

5-30

6HFWLRQ  Feeder Overcurrent Protection

Feeder Overcurrent Protection

6 -1

FEEDER OVERCURRENT PROTECTION By far the most common type of protection for radial distribution feeders is O v e r c u r r e n t protection.Typical distribution system voltages are 44 kV, 33 kV & 25 kV. The point of supply is normally a few kilometres 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 -2

W i t h R a d i a l feeders there is only one possible point of supply, and the flow of fault current is in o n e d i r e c t i o n o n l y . Overcurrent protection can therefore be used to provide adequate protection.

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 the overcurrent relays. These overcurrent relays must then operate and initiate tripping if a fault condition is detected on the feeder.

6 -3

A

B

800:5A

CIRCUIT BREAKER

TRIP

FUSES OVERCURRENT RELAY

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

4800 800

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:

6 -4

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 the effects 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 overcurrent relay to `overreach' the remote terminal, (i.e. a setting less than 4800 primary amps), and introduce a definite time delay in the tripping. This time delay will allow the fuses or overcurrent relays at the remote station to operate to clear faults beyond bus `B' before the time delayed tripping can take place at the supply station `A'. This type of time delay has the major disadvantage that all faults will be slow clearing, even very `close-in' faults, which have the highest magnitude of fault current. This time-delayed clearing of high fault currents is usually unacceptable, and the most common feeder protection scheme, which overcomes the problem utilizes an inverse time overcurrent relay in conjunction with the instantaneous overcurrent relay. The application of this feeder protection scheme, utilizing both instantaneous and inverse time overcurrent relays is described next:

6 -5

In order to ensure that the instantaneous overcurrent relay will not unnecessarily operate for faults at the remote station, (which should be cleared by the overcurrent protection or fuses at that station) then it must be set to protect only part of the feeder. A safe maximum for most types of relay 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 -6

With such a relay set to detect faults on 80% of the feeder, the remaining 20% is left unprotected. This is, of course, not acceptable. To provide protection for the l a s t 2 0 % o f t h e f e e d e r a t i m e- g r a d e d , o r I n v e r s e D e f i n i t e M i n i m u m T i m e relay can 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 -7

OPERATING TIME (SECONDS)

RELAY OPERATING CURRENT (AMPS)

The `Inverse definite minimum time' relay has a characteristic as shown above.

6 -8

OPERATING TIME (SECONDS)

INVERSE TIME RELAY

FUSE

RELAY OPERATING CURRENT (AMPS)

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 -9

A

B

800:5A

F2 TRIP

o / c

1.

F1 o / c

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 `A' will then reset.

6 -10

A

80% 800:5A

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 -11

The criteria used for setting the I n v e r s e-T i m e d Overcurrent 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 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.

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 -12

Protection schemes for this type of feeder can b e e n h a n c e d b y a d d i n g a L o w - Set I n s t a n t a n e o u s O v e r c u r r e n t relay, and providing A u t o - R e c l o s i n g of the circuit breaker after fault clearance. 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 will `Overreach', and operate for faults in the transformers tapped on the feeder. All faults will therefore be first detected by the L o w - S e t r e l a y.

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 -13

1. If the fault is in a transformer, then the fuse will 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 first tap, then the inverse timed overcurrent relay will operate after a time delay, and the feeder will trip a second time and `Lock Out'. 3. If the fault is close to the supply station, then the High- Set overcurrent relay will operate and trip the feeder a second time, with no intentional time delay, and `Lock Out'.

6 -14

R W B 4800 A

800/5A CURRENT FLOW SHOWN FOR A BLUE PHASE TO GROUND FAULT ON THE FEEDER BUS PROTECTION C.T.’S NORMAL LOAD CURRENT = 400 A I.E. SECONDARY CURENT = 2.5 A

4800 A

FEEDER

A typical feeder overcurrent a.c. schematic diagram, showing all three phases, is shown above. The diagram includes High-Set Instantaneous, Inverse Time, and Low-Set Instantaneous relays. Very often the High-Set Instantaneous and Inverse Time overcurrent relays are built into a single relay case. Until a few years ago, all of these relays were electro-mechanical, and often in separate relay cases. i.e. The H.S. Instantaneous - attracted armature, and the Inverse Time - induction disc. More recently electronic relays were used, and the settings are applied by changing the position of `DIP' switches. These electronic overcurrent relays were much more compact, and were functionally identical to the electro-mechanical overcurrent relays. Today,

almost

all

overcurrent

relays

being

installed

are

microprocessor-based, and have many functions in the one relay. As well as the protection functions described, these relays have many 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 -15

125 VDC

+ ve

H.S. INST o/c

L.S. INST o/c

INV. TIME

OPEN FOR 10 SECONDS AFTER BREAKER CLOSE OR RECLOSE

o/c

INITIATE A U T O- R E C L O S E

ALARM

TRIP BREAKER

TRIP RELAY

- ve

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 -16

PROTECTION COORDINATION

TIME IN SECONDS

CURVES FOR M4 FEEDER 100

30 20

INVERSE TIMED OVERCURRENT

300 E FUSE

10 5 3 2

NORMAL LOAD 400 AMPS

1

H I G H- SET INSTANTANEOUS OVERCURRENT 6,000 AMPS

.5 L O W -S E T I N S T A N T A N E O U S OVERCURRENT 1900 AMPS (BLOCKED ON RECLOSURE)

.3 .2 .1 100

200

500 1000

2000

6000

10,000

20,000

CURRENT IN AMPS AT 27.6 K V

27.6 kV TRANSFORMER STATION AND FEEDER ARRANGEMENT

T1 B Bus

3 Phase Fault Values

M4

T2

M4 Load 20 MVA 400 amps at 28.9 kV

700 MVA 14000 amps

Y Bus

10 mile feeder Fuse 300 E MS #1

M4 Relay Settings MVA

AMPS

Phase High Set

300

6000

Phase Low Set

95

1900

Phase Timed

50

1000 (minimum pickup)

600 MVA 12000 amps 100 MVA 2000 amps

250 MVA 5000 amps MS #2

90 MVA 1800 amps

6 -17

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 ETIMED OVERCURRENT RELAY 1 . The relay must not operate for the maximum load current that will be carried by the feeder. i.e. COLD LOAD PICK- U P a n d B A C K T O-B A C K FEEDER 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-SET INSTANTANEOUS 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 -18

CRITERIA FOR SETTING THE LOW-SET INSTANTANEOUS OVERCURRENT RELAY 1 . The relay must operate for all 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 autorecloses, the tripping from the low-set relay is blocked.

6 -19

DIRECTIONAL OVERCURRENT PROTECTION If there is generation connected to a distribution feeder, the system is no longer R A D I A L .

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 allow the overcurrent protection to trip O N L Y if 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 -20

TESTING OF FEEDER OVERCURRENT PROTECTION The individual C.T's of the feeder overcurrent protection scheme are tested as described earlier. With overcurrent protection the C.T. polarity is not of critical importance. However, the relative polarity of all 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 links 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 `on-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 -21

Microprocessor-Based Feeder Protection Relays Most feeder protection relays being installed today are microprocessor- b a s e d , a n d i n c l u d e m a n y functions within the one relay. As well as the basic instantaneous and inversetimed overcurrent functions, these relays also include many other protection functions and additional 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

6 -22

 6HFWLRQ  Coordination of Protection Systems

Coordination of Protection Systems

7-1

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-current coordination 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.

7-2

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.

7-3

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

Time in Seconds

Maximum clearing time

Minimum melting time

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.

7-4

SOURCE

FUSE A

Fuse A – minimum melting TC curve

75% of Fuse A curve (in time) Time

FUSE B

FAULT

Fuse B – total clearing TC curve

LOAD

Coordination limit

Current

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

7-5

An example of computer software for power system protective device coordination is:

cyme.com CYMTCC, Protective device coordination

7-6

PROTECTIVE RELAYING ZONES The following diagram shows a section of a typical power system, comprising: 2 Transmission Lines 2 Transformers 2 33 kV Buses 4 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.

7-7

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.

7-8

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.

7-9

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, and provide 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.

7-10

7-11

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 BackUp feature of the protection scheme of the next system element closer to the source of supply. This was discussed earlier under `Feeder Protection'. The `BackUp' 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 uncleared because 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 ALL circuit breakers on the transmission system.

7-12

SIMPLIFIED DIAGRAM OF BREAKER FAILURE PROTECTION FOR HIGH VOLTAGE CIRCUIT BREAKERS D.C. SUPPLY

(+)

INITIATING CONTACTS

OVERCURRENT SUPERVISION (1000 AMPS)

50

BREAKER AUXILIARY SWITCH

TIMER 62 a (67 ms) 52 TIMER 62 b (105 ms)

52

BREAKER AUXILIARY SWITCH

TIMER (500 ms) 62 c

94 ET

TRIP FAILED BREAKER

94

TRIP ALL BREAKERS ON BOTH ADJACENT ZONES

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.

7-13

TRIPPING When the breaker failure protection operates it must trip ALL of the circuit breakers on BOTH adjacent 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.

SPEED The 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. INITIATION Breaker failure protection is initiated by all of the protection schemes that send trip signals to that breaker. OVERCURRENT SUPERVISION Breaker failure protection is supervised by high-speed instantaneous overcurrent relays. These relays must have a very fast reset time and a high pick-up/drop -out ratio.

7-14

RELAY SETTINGS INSTANTANEOUS OVERCURRENT SUPERVISION RELAYS The high speed instantaneous overcurrent supervision relays are typically set for 1,000 primary amps.

TIMER 62a The 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 milliseconds 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 milliseconds after the trip signal is sent to the breaker, breaker failure protection 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.

7-15

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 pickup 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.

7-16

(+)

D.C. SUPPLY

INITIATING CONTACTS 52

TIMER 0.3 SECS 94 ET

TRIP FAILED BREAKER

BREAKER AUXILIARY SWITCH

62

94

TRIP ALL BREAKERS ON BOTH ADJACENT ZONES

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.

7-17

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-reclose scheme 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 autoreclose is applied, then there is a very short delay and the breakers are reclosed before the two ends of the line can fall out-ofsynchronism, and no voltage supervision is required.

7-18

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 timedelay 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.

7-19

6HFWLRQ  Bus Protection

Bus Protection

8-1

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-reclosing is 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.

8-2

For buses that are part of interconnected systems, where there is more than one possible in-feed for fault current, differential protection is 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, as discussed earlier.

8-3

8-4

6000A

25A

25A

25A

25A

1200:5A

RELAY

1200:5A

6000A 6000A

25A

25A

F1

F2

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.

8-5

4000A

2000A

6000A

16.7A

8.3A 25A

16.7A

8.3A

RELAY

1200:5A

1200:5A

25A

4000A

16.7A

F1

2000A

8.3A

F2

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.

8-6

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.

8-7

18,000A

75A 2.5A

8.33A

20.83

12.5

8.33

1200:5A

RELAY 75A

6000A

2000A

F1

5000A

F2

3000A

F3

2000A

F4

F5

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 Amps

F3 = 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.

8-8

8-9

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

8-10

T1

T2

F2

BT B.U. RELAY

F4 DIFF. RELAY

F6

Now let us consider the Bus arrangement for a typical sub-station with two supply transformers: The Bus protections for Buses C and D 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 and polarity. However, with this arrangement a BACK-UP protection feature can be readily incorporated. If the feeders F2, F4, and F6 are 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 T2 and 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 protection relay 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 to operate), 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, and clear the fault by tripping the D BUS breakers.

8-11

8-12

8-13

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.

8-14

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 differential protection for high voltage buses. The advantage of using High Impedance relays in bus differential protections is that they can be designed to remain stable (not operate) for external faults, when any 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 not saturated. The resulting differential current will cause the max imum voltage to occur across the differential relay. A relay setting (in volts) is chosen, with sufficient margin, to ensure that the differential protection does not operate for this external fault condition. The resistance of the C.T. secondary windings and C.T. cabling must be known, and is used in the relay setting calculations. For internal faults the high impedance of the differential relay forces much of the resulting differential current through the C.T. exciting impedances. The resulting voltage developed across the relay 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 the voltage to a safe value during fault conditions.

8-15

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 breakers after 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 Protection The C.T. circuits of bus protections are of critical importance, and great care must be taken to ensure that the ratio, polarity, and characteristics are all correct. The best way to test the C.T. circuits, after all of the wiring is complete, is by PRIMARY INJECTION. Here a test current is passed into the bus through one breaker, and out through a second breaker. The C.T. secondary current is measured, and should circulate, with no Spill into the relay. This test is repeated to compare 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 to inject 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 current through test links on the panel, the C.T. secondary wiring as well as the relay is tested. With the Bus In-Service and On-Load, the C.T. secondary currents should be measured. The vector sum of all of the currents should be zero. i.e. NO SPILL CURRENT THROUGH THE RELAY. 8-16

Many countries use busbar arrangements as shown above, where feeders can be switched from one bus to another by means of isolating 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 appropriate bus. It is usual to have one zone of protection for each section of the bus. These are known as discriminating zones. There is also another 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 discriminating zone relay and the check zone relay to operate.

8-17

8-18

6HFWLRQ  Motor Protection, Starting & Control

Motor Protection, Starting & Control

9-1

MOTOR STANDARDS ENCLOSURES

• ODP -

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

• WPI - Weather Protected I This enclosure is similar to the ODP, but with additional shielding to protect the windings and bearings from water spray.

• WPII - Weather Protected II 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. • TEFC - Totally Enclosed Fan Cooled With 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 PROOF This type of motor enclosure is required in hazardous locations, with the following classifications: CLASS I - ExplosiveVapours/Gases CLASS II - Explosive Dusts CLASS III - Explosive Fibres DIVISION I - Hazardous materials normally present DIVISION II - Hazardous materials may be present

9-2

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.

9-3

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.

9-4

MOTOR PROTECTION AND CONTROL The 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 PROTECTION

Motors 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.

9-5

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.

9-6

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).

9-7

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 zerosequence 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 how the 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 industrial plants the neutral of the supply transformer is grounded through a resistor 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, motor ground faults will be cleared by the operation of the phase overcurrent device, or the thermal overload device.

9-8

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 an undervoltage 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-phase motors.

9-9

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.

9-10

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.

9-11

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 and use a single C.T. per phase. For each phase the connection from each end 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 fault exists a differential current flows in the C.T. secondary, and causes the relay to operate.

9-12

MOTOR STATOR WINDINGS

CIRCUIT BREAKER

DIFFERENTIAL RELAY

DIFFERENTIAL PROTECTION FOR VERY LARGE MOTORS

For very large motors a separate C.T. is used at each end of the winding, for each of the three phases. The C.T.'s are connected differentially as shown above, and under healthy 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 shut down the motor.

9-13

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 the undervoltage sensor to drop-out the contactor for a low voltage condition.

9-14

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 threephase 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:

9-15

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.

9-16

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 is reduced by 33%.

9-17

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.

9-18

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.

9-19

9-20

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.

9-21

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 management device 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 various starting 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 with computers. This allows for the setup of the devices, and for remote monitoring by plant computer control systems. A descriptive leaflet of a typical motor management device is include at the back of this section.

9-22

9-23

9-24

6HFWLRQ Transformer Protection

Transformer Protection

10-1

TRANSFORMER PROTECTION The various types of protection schemes for 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:

10-2

•

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 delta connected for a star connected transformer winding, and star 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 the transformer 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 phase angle shift is taken care of by the relay microprocessor.

10-3

RESTRAINT COILS

OPERATING COIL

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.

10-4

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.

10-5

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

10-6

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.

10-7

OPERATE CURRENT (AMPS)

EFFECTIVE RESTRAINT CURRENT (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.

10-8

IMPORTANT: BECAUSE DIFFERENTIAL PROTECTION REMAINS STABLE FOR `THROUGH' OR `OUT OF ZONE' FAULTS, IT PROVIDES NO OVERLOAD PROTECTION FOR THE TRANSFORMER.

10-9

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.

10-10

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.

10-11

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.

10-12

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 by very low energy arcs and deterioration of insulation, and core problems. This is known as GAS ACCUMULATION. • 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 GAS PRESSURE 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.

10-13

10-14

The above is a simplified cross section of a General Electric Model 12 gas relay, commonly installed on North American transformers.

10-15

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.

10-16

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.

10-17

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.

10-18

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

10-19

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.

10-20

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.

10-21

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

10-22

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

10-23

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

10-24

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

10-25

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

10-26

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

10-27

•

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.

10-28

6HFWLRQ  General Protection

Generator Protection

11-1

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 to generators 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 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. 11-2

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.

11-3

230 kV CIRCUIT BREAKER

22 kV

GROUNDING TRANSFORMER

4 kV

R

VOLTAGE RELAY

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.

11-4

The following protective relaying schemes will normally be applied to 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.

11-5

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.

11-6

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.

11-7

33 kV

600:1

CIRCUIT BREAKER

DIFFERENTIAL RELAY

30 MW GENERATOR

600:1

GROUNDING TRANSFORMER

R

VOLTAGE RELAY

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 inr ush 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.

11-8

DIFF’L RELAY DIFF’L RELAY

DIFFERENTIAL RELAY

GROUNDING TRANSFORMER

R

VOLTAGE RELAY

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.

11-9

GENERATOR STATOR WINDINGS

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).

11-10

STATOR WINDINGS

GROUND FAULT

60 Hz PASS 180 Hz BLOCK

GROUNDING TRANSFORMER

R

FILTER

STATOR GROUND FAULT PROTECTION

VOLTAGE RELAY

(64)

The stator winding of a typical generator is grounded at it's star point through a neutral grounding transformer, with a resistor connected across the secondary terminals. The value of this resistor is chosen to limit the ground fault current, for phase-toground faults on the stator winding, to about 10 amps. A Voltage Relay is connected across the resistor to detect stator ground faults. Under normal healthy conditions the grounding transformer develops no secondary voltage, and no voltage is applied to the relay. When a stator ground fault occurs, a voltage is developed across the grounding transformer secondary terminals, and the voltage relay operates. This condition will usually cause the generator to trip, but if the ground fault current is limited to a very low value, such as 10 amps, then it may just annunciate an alarm condition. The above stator ground fault protection is not sensitive for ground faults very close to the neutral point. It is generally considered that stator ground fault protection of this type is sensitive for faults on Copyright 2004 - C.M.Sothwood, P.Eng. 11-11 90% of the winding

V.T.

STATOR WINDINGS

RELAY

GROUNDING TRANSFORMER

THIRD HARMONIC GROUND DETECTOR USING RELATIVE MAGNITUDE COMPARATOR

R

To detect faults on the last 10% of the winding some other type of protection must be used. One type of protection that is used to detect such faults compares the third harmonic voltages between the V.T. at the

generator terminals, and that at the neutral

grounding V.T. If a stator ground fault occurs, then there will be a change in the third harmonic voltages applied to the relay. The change of third harmonic voltage is greatest for ground faults at the neutral end of the winding, and least for ground faults at the stator terminals. The relay is set to operate if there is a significant change in the third harmonic voltages applied to it. This type of stator ground fault protection is most sensitive for ground faults close to the star point, and will operate for faults on about the lower 90% of the stator winding. This type of protection will usually annunciate an alarm condition, and not trip the unit. By supplementing the conventional stator ground fault protection with this scheme, ground faults are detected on 100% of the stator winding. 11-12

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.

11-13

GENERATOR FIELD

MAIN EXCITER ROTOR GROUND FAULT RELAY

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.

11-14

FIELD CIRCULT BREAKER

ROTOR FIELD WINDING

EXCITER ROTOR GROUNDFAULT RELAY CURRENT LIMITING RESISTOR AC SUPPLY 30V DC

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.

11-15

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

11-16

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 `open-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.

11-17

R W B

X

ZB

ZR

N.P.S. RELAY

NEGATIVE PHASE SEQUENCE NETWORK

IR

IR VZR

VZR

+ VZB

VZR VZB

IB

VZB

IW

IW

POSITIVE SEQUENCE

IB NEGATIVE SEQUENCE

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.

11-18

RELAY

GENERATOR STATOR WINDINGS

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.

11-19

PHASE TO PHASE VOLTAGE OPEN CORNER DELTA VOLTAGE

RELAY COILS IN QUADRATURE

INTER – TURN PROTECTION

NORMAL CONDITON

FAULT CONDITION

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 `open-corner-delta voltage, and the other pair of coils is supplied with the V.T. phaseto-phase voltage. Under normal healthy conditions the `open corner delta' voltage is zero. If a fault develops there will be an `open corner delta' voltage, and the two voltages applied to the relay will produce a torque to operate the relay.

11-20

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 overheating unless 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 to increase 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 manual transmission 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 overfrequency conditions 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.

11-21

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 the generator 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 the transmission system is restored.

11-22

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 `out-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 `out-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.

11-23

B

X

A

OPERATING REGION BLINDER ‘B’

ZLOAD 230 kV BUS

R 3 1 2

OPERATING REGION BLINDER ‘A’

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-STEP IMPEDIANCE OPERATING AREA

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.

11-24

Z LOAD NORMAL FIELD

LOSS OF FIELD LOCUS OF GENERATOR TERMINAL IMPEDANCE SEEN BY RELAY

LOSS OF EXCITATION PROTECTION

(40)

When a generator loses excitation (or field), reactive power flows from the power system into the generator. The generator then loses synchronism and runs as an induction generator, above synchronous speed. Above synchronous speed the rotor will start to oscillate in an attempt to lock into synchronism, resulting in overheating and other damage. As long as the system is stable, MVARS will flow into the generator and the machine will continue to put out MW. Loss of field protection uses a relay that detects the change in Reactive flow, from the normal LAGGING condition, to MVARS LEADING. A typical Loss of Excitation Protection scheme uses an `Offset Mho' relay to measure the generator load impedance, and has an operating characteristic as shown above. The `Offset Mho' impedance relay is a single phase relay, and is supplied from the generator C.T's and V.T's. The Loss of Field relay will operate if the locus of the load impedance falls within the operating characteristic of the relay. A timing relay is included to initiate tripping of the machine if the LEADING MVARS condition persists for 1 second.

11-25

VOLTS / Hz RELAY

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:

CORE FLUX B α

V

(APPLIED VOLTAGE)

F

(FREQUENCY)

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.

11-26

ZERO TORQUE LINE

V.T.

REVERSE POWER RELAY

P IN

POWER P OUT P

OPERATE ZONE

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.

11-27

V.T.

UNDER FREQUENCY RELAY

CLOSED BELOW 52Hz

LOW SET O/C RELAY

TRIP

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.

11-28

V.T.

Z RELAY

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

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.

11-29

GENERATOR OVERCURRENT PROTECTION VOLTAGE CONTROLLED & VOLTAGE RESTRAINED Overcurrent relays are often used to provide primary protection for small generators. For larger generators overcurrrent 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 neutral end of the stator winding, particularly for a single generator supplying an isolated system. If the C.T.'s are located at the terminal 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 rate of decay is determined by the decrement characteristic of the machine, and the response of the voltage regulator. As the terminal voltage of the generator decreases, the output current will decrease accordingly. In many cases the sustained fault current can be lower than the generator full-load current. For a fault to be cleared correctly the inverse time overcurrent relay must operate prior to the current decaying to a value below the pick-up setting of the relay. Voltage Restrained and Voltage Controlled Overcurrent Relays are used to deal with the problem of decaying voltage and current at the generator terminals during phase faults. 11-30

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 to 120 volts as shown above. The overcurrent relay with voltage control provides sensitive protection where the expected fault current is less than the generator full load current, and the generator voltage always falls below the voltage inhibit setting of the relay. The voltage inhibit setting must be low enough to prevent relay operation on recoverable voltage dips, such as the starting of large motors, and high 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 two inverse-time characteristics. The first characteristic provides overload protection when the generator terminal voltage is normal. The second characteristic provides overcurrent protection for generator faults when the voltage falls below a predetermined value. 11-31

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.

11-32

GENERATOR SHORT-CIRCUIT CURRENT In the event of a short-circuit close to the terminals of the generator the time variation of the fault current is considerably 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

11-33

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 subtransient symmetrical short-circuit current is:

I ′′ =

FULL LOAD CURRENT F.L.C. = = 9.1 X F.L.C. X ′′d 0.11

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: I′ =

F.L.C FULL LOAD CURRENT = 5.26 X F.L.C. = 0.19 X ′d

11-34

The Synchronous Reactance determines the sustained short-circuit current, and for a typical value of Xd of 1.35 p.u., the continuous generator short-circuit current is:

I =

FULL LOAD CURRENT Xd

=

F.L.C. = 0.74 X F.L.C. 1.35

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.

11-35

Generator Current Decrement At V=1pu; time=0

g

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

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

11-36

60

10

00

90

3.

3.

2.

80

70

60

2.

2.

2.

50

40

30

20

2.

2.

2.

2.

10

00

90

80

70

2.

2.

1.

1.

1.

50

40

30

20

10

00

90

80

70

60

2.00

1.

1.

1.

1.

1.

1.

1.

0.

0.

0.

50

1.00

0.

0.

40

30

20

0.

0.

0.

10

00

0.

0.

Current ( pu)

Generator Current Decrement

10.00

9.00

8.00

7.00

6.00

5.00

4.00

3.00 I'd

I"d Itotal

Id

0.00

Time (s)

11-37

6HFWLRQ  Cogeneration & Non-Utility Generation (NUG)

Cogeneration & Non-Utility Generation (NUG)

12-1

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.

12-2

One possible abnormal operating condition that may be encountered at a Non-Utility Generating 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 frequency excursions are highly undesirable, and can be damaging to the turbine. 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 1 Second. Similarly, if there is a surplus of generation for the connected load, the frequency, and generator speed, will increase. These frequency excursions are highly undesirable, and can be damaging to the turbine. 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 1 Second. Overvoltage and Undervoltage protection is also provided to disconnect the generator for excursions in the voltage on the utility power system. Typical settings are plus/minus 6% of the nominal voltage. 12-3

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.

12-4

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 overcurrent relays, 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.

12-5

REMOTE TRIPPING REQUIREMENTS Various options are available for the Remote or Transfer Tripping Channels between the utility substation and the NUG. These include: • 125 Volt D.C. Signalling over leased metallic telephone lines

• Frequency Shift Audio-Tone signalling over leased telephone lines

• Fibre-optic cable

• VHF Radio

• Power-Line-Carrier

• 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 AudioTone 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-toground faults at the generating station. Special isolation equipment is available for this purpose.

12-6

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-recloses after 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 autoreclose 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 autoreclose only when the generator circuit breaker is open.

12-7

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 highvoltage disconnect or load-break switch. This means that NUG staff cannot operate the switch without instruction from the utility.

12-8

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.

12-9

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.

12-10

  6HFWLRQ  High-Voltage Transmission Line Protection

High-Voltage Transmission Line Protection

13-1

INTERCONNECTED SYSTEMS WITH TWOWAY 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.

13-2

The requirements of protection schemes for high-voltage transmission 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.

13-3

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. i.e.

Z =

V I

The relay operates if the ratio VI the setting of the relay in OHMS.

(Volts) (Amps)

falls below

13-4

500:1

C.T.

V.T. 2000:1 IMPEDANCE RELAY

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.

13-5

TRIP

C.T.

V.T.

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.

13-6

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 only when fault current flows into the line.

13-7

LE ANG L IN E TERMINAL B

ZONE 2 REACH ZONE 1 REACH

75º

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.

13-8

Let us now apply such relays to a practical protection scheme for a high-voltage transmission 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 threephase 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.

13-9

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 is normally 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.

13-10

F1

F2 ZONE 1 REACH ZONE 2 REACH

IMPEDANCE RELAY

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 highspeed clearance for all faults. i.e. Faults within 25% of either terminal are cleared at the far terminal after a time delay.

13-11

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 or permissive 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.

13-12

A

B

ZONE 1 OF A

F3

ZONE 1 OF B

ZONE 2 OF B

F1

F4

F2

ZONE 2 OF A

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.

13-13

• 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. No acceleration 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.

13-14

13-15

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 BLOCKING signal 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.

13-16

13-17

PHASE COMPARISON PROTECTION SCHEMES Another protective relaying system for high-voltage transmission 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.

13-18

Line Differential Protection The 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.

13-19

Line Differential Protection The line differential relays at each end of the transmission line compare 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 the magnitude and phase angle of the current entering the line at one end, with the current leaving the line at the other end. If the two are not equal, within a reasonable tolerance, then a fault condition is detected, and the line is tripped. The relay also has various other protection elements, such as instantaneous overcurrent, timed overcurrent, phase and ground directional overcurrent, and distance (or impedance). The distance, or impedance element is often used for back-up protection. Direct tripping is provided between the two terminals of the transmission line.

13-20

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. High quality 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-Comparison protection.

•

Direct Tripping channel between terminals of the line.

•

Communication channel for Pilot-Wire protection.

13-21

The various types of communication channels commonly used for the protection of high-voltage transmission 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.

13-22

• 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.

13-23

13-24

   6HFWLRQ  Static Capacitor Protection

Static Capacitor Protection

14-1

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.

14-2

Some of the configurations that are commonly used are: 1.

Grounded Star

2.

Grounded Double Star

3.

Ungrounded Star

4.

Ungrounded Double Star

14-3

CAPACITOR BREAKER

FUSES

SERIES GROUP 1

200KVAR CAPACITORS

FUSES

SERIES GROUP 2

CAPACITORS

FUSES

SERIES GROUP 3

CAP A R ACIT SIM R A N G OR W P ILAR T E . HA O SE

CAPACITORS

A typical arrangement of a Grounded Star capacitor bank is shown above:

14-4

CAPACITOR UNIT FUSING The first line of protection for a capacitor bank is the individual, external, indicating capacitor fuse as shown 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.

14-5

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.

14-6

The capacitor bank protection should detect the following conditions: A.

Overcurrents due to capacitor bank BUS 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.

14-7

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-tophase or phase-to-ground faults.

14-8

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.

14-9

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.

14-10

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 overvoltage is 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 starungrounded 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.

14-11

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.

14-12

6HFWLRQ  Recent Developments and Future Trends in Protective Relaying

Recent Developments and Future Trends in Protective Relaying

15-1

DIGITAL MICROPROCESSOR-BASED RELAYS In the last few years digital microprocessorbased relays have been introduced to all areas of protective relaying. With the many features available in these relays they are revolutionizing the way that protection, control, and monitoring is being applied in high-voltage substations.

15-2

The features of modern microprocessor-based relays include: •

Many Functions in a Single Relay.

•

Group Settings Readily Changeable for changes 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

15-3

•

Oscillography or waveform capture – storage of 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’

15-4

DIGITAL SIGNAL PROCESSORS The digital signal processor, or DSP, is the heart of modern microprocessor-based relays. 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.

15-5

OPTICAL CURRENT TRANSFORMERS The use of optical C.T.’s or optical current transducers in modern protective relaying applications will likely increase considerably in the coming years. There is the expectation that the development of optical C.T.’s will lead to much simpler structures, and considerable cost savings over existing high-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

15-6

15-7

15-8

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 will allow different makes of relays to communicate with each other.

15-9