Modern Power System Protective Relay REV04

Contents Section 1 Power System Faults Section 2 Components of Protection Schemes Section Sect o 3 Current Cu e t Transformers a s o e s & Voltage Vo tage Transformers Section 4 Power System Neutral Grounding Section 5

Feeder Over current Protection

Section 6 Coordination of Protection Section 7 Bus Protection Section 8 Motor Protection, Starting & Control Section 9 Transformer Protection S i 10 Generator Section G P Protection i Section 11 Transmission Line Protection

Section 1

Power System y Faults

Section 1 ¾ ¾ ¾ ¾ ¾ ¾

¾ ¾

Power System Faults

Types of Faults. Incidence of Faults on Power System Equipment. Effects of Power System Faults. Magnitude of Fault Current. Detection of Faults. Requirements of Protective Relaying Systems (Selectivity ,Dependability ,Reliability ,speed). Clearance of Faults. Calculating Maximum Fault Current

Power System Faults A power system t f lt is fault i the th breakdown b kd of insulation(between conductors or b t between a phase h conductor d t and d ground) which results in excess current flflow.

Types of Faults On a Three-Phase Three Phase power system the principal types of faults are: a)) Phase-to-Ground Ph G d (or ( Single Si l Phase) Ph ) 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

T F lt Types off Faults Sometimes, these faults are accompanied by a broken conductor, or may even take the form of a broken conductor without a ground connection. connection This results in an open-circuit condition. Because no ‘fault fault current current’ flows for this condition, the open-circuit fault is difficult to detect. The open-circuit p does,, of course,, cause severe unbalance on the power system, and can cause overheating in generators.

Types of Faults The g generators must be equipped q pp with protection schemes to detect such unbalances (or negative phase sequence) conditions. This will be covered later under ‘Generator Protection’.Generators, transformers and motors t are subject bj t to t short-circuits h t i it between b t turns of the same winding.

Types of Faults On overhead transmission lines the insulation that breaks down is air. When such a fault occurs there is a flashover or arc(often along the surface of an insulator string). If the th fault f lt is i cleared l d quickly, i kl no permanentt damage results, and the transmission line can immediately be put back into service. service

Types of Faults When faults occur in Transformers,, Generators,, Motors and Cables, permanent damage usually results. Such faults are usually caused by mechanical failure of solid insulation, or in the case of transformers, contamination of the insulating oil. oil For SF6 insulated equipment, equipment faults are often the result of contamination of the SF6 gas by solid particles. particles

IIncidence id off F Faults lt on Power P System y Equipment:q p 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 p per yyear p per 100 Miles (study 2009 USA)

Incidence of Faults on Power System Equipment:For 44kV, 44kV 33kV and 25kV feeders the figures are proportionally higher. The relationship between the number of overhead power p system faults and the voltage level can be explained as follows: By far the most common type of power system fault is the flashover of insulators on overhead transmission lines, due to lightning. Th number The b off faults f lt per year is i proportional ti l to the length, and is approximately inversely proportional to the voltage level.

Incidence of Faults on Power System Equipment:-

IIncidence id lt on Power P S t off F Faults System Equipment:If lightning li ht i strikes t ik th grounded the d d shielding hi ldi conductor, 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 cross arm to a phase conductor may then occur It will most likely occur on the phase occur. with the highest voltage difference to the voltage transient developed by the lightning strike.

Incidence of Faults on Power System Equipment

Incidence of Faults on Power System Equipment: The most common causes of faults on overhead lines are: 1) Li Lightning ht i 2) Contaminated Insulators 3) Punctured P t d or broken b k iinsulators l t 4) Birds and animals 5) Aircraft and cars hitting lines and structures 6) Ice and snow loading 7) Wind

Incidence of Faults on Power System Equipment: In electrical machines, cables and transformers, faults are caused by: 1)) Failure of insulation because of moisture. 2) Mechanical damage. 3) Flashover caused by overvoltage or abnormal loading. g

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

Effects of Power System Faults: About 90% of overhead line faults are t transient i t in i nature: t i.e. flashover of insulators which does not result in permanent damage. damage With such faults, the line can be restored to service immediately after the breakers have tripped.

Effects of Power System Faults: 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.

Effects of Power System Faults: On typical 44kV and 33kV overhead distribution systems y there is an intentional delay y of 0.5 seconds before the breaker is auto-reclosed after a feeder fault. O typical On t i l 500kV and d 230 kV transmission t i i systems there is a 10 second intentional time delay before auto auto-reclosing reclosing after a fault. fault This time delay is to help maintain system stability by not subjecting the power system to two faults in quick succession.

Effects of Power System Faults: Faults in generators, motors, transformers and cables etc. are normallyy permanent and AUTO-RECLOSE is not used. Such faults require the equipment to be taken out of service i for f an assessmentt off the th damage d and d repair.

Effects of Power System Faults: When a fault occurs, a very large current normally flows. flows This fault current, current if allowed to persist, will cause damage to equipment. On an interconnected H.V. transmission system, an un-cleared fault can cause instability and system collapse: i.e. A ‘blackout’ over a very large area. Faults must therefore be cleared in the shortest h t t time ti possible. ibl

Magnitude g 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, generation and the location of the fault.

Magnitude of Fault Current: On large interconnected H.V. 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, 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 Phaseto-ground faults it is the impedance of the line from the bus to the fault, plus the impedance of the ground return. return

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

Magnitude of Fault Current When calculating fault current, 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 l negligible li ibl comparison i t to th the impedance of the line conductors.

NOTE:

Magnitude of Fault Current: The star points of transformer windings are often grounded through a resistor or a reactor. This has the effect of limiting the ground fault current on the feeders. feeders The procedure for calculating the maximum fault current (short-circuit (short circuit calculation) is given at the end of this section, with a worked example. p

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

Requirements of Protective Relaying Systems: 1- SELECTIVE Protective relaying schemes must be able to discriminate between faults on the protected system element, and those on adjacent elements. Hence, only faulted elements are tripped from the power system, system and all healthy elements stay in service. This is particularly important on an interconnected transmission system. 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. elements If one or more of these adjacent elements trip “in sympathy” with the faulted element, then major power interruptions will result.

Requirements of Protective Relaying Systems:

2- DEPENDABILITY AND RELIABILITY Protective relaying schemes must be very dependable and reliable. all power system faults must be detected and cleared quickly. quickly On high voltage interconnected transmission systems, an un cleared or slow clearing fault can easily lead to a power system collapse. Such power system collapses occurred in Ontario and the North Eastern U.S.A. in 1965,, and again g in August g 2003.

3 HIGH SPEED 3-HIGH High Hi h speed d ffault lt clearance l iis essential ti l on interconnected transmission systems. By high speed we mean less than 0 0.1 1 seconds seconds. On 500 kV and 230 kV systems faults are normally cleared in 3 or 4 cycles, y or 50 to 80 milli-seconds.

Clearance of Faults On distribution systems, y , which are usuallyy radial in nature, slower fault clearance times are permissible. TIME GRADED over current protection is often TIME-GRADED 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.

Procedure For Calculating Maximum ( Circuit Fault Current(Short Calculation) The g general p procedure for calculating g the fault current for a fault at a particular point on a power system is as follows: 1 Draw 1. D a single-line i l li di diagram off the th power system. 2 Collect detailed impedance data for all of the 2. components of the power system. i.e.

Resistance R & Reactance X. X

3. Although fault current can be calculated using the ohmic method, it is usually simpler to use the Per-Unit M h d where Method h allll off the h impedances i d are referred f d to an arbitrarily chosen common BASE MVA. 4 Convert all of the various impedances to per-unit 4. per unit values with a common base MVA. 5 Fi d the 5.Find th total t t l Resistance R i t R and R, d Reactance R t X from X, f the source to the fault. 6. Calculate the total Impedance Z: Z Z =√√ R2 + X2

7. Calculate the THREE-PHASE (SYMMETRICAL) FAULTCURRENT:

Calculate the PHASE-TO PHASE FAULT CURRENT

Calculate the PHASE-TO-GROUND FAULT CURRENT

8.To

determine the asymmetrical fault current, y 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 i ifi t motor t load, l d the th motor t contribution t ib ti t the to th fault can be approximated as: Symmetrical Contribution

= 4 times Motor Full

Load Current Asymmetrical Contribution =

Full Load Current.

5 times ti M t Motor

Example of Fault Current Calculation

Short Circuit Calculations

Phase to Ground Fault

Example of Fault Current Calculation

Example of Fault Current Calculation

Section 2 Components off Protection Schemes

Section 2 Components of Protection Schemes 1. Fault Detecting or Measuring Relays 2. Tripping and other Auxiliary Relays 3. Circuit Breakers 4. Current Transformers 5. Voltage transformers

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

Components of Protection Schemes

Fault Detecting Relays: Fault detecting, g, or Sensing g relays y monitor p power system AC quantities such as current, voltage, and frequency. They are set to operate, and initiate tripping, when a fault condition is detected. Th mostt common fault The f lt detecting d t ti relays l i use are in over current relays. There are two basic types of over current relays. y These are the instantaneous over current relay and the timed over current relay.

Fault Detecting Relays A. Instantaneous Over current Relays These relays Th l operate, t or pick-up i k att a specific ifi value l off current, with no intentional time delay. The pick-up setting is usually adjustable by means of a dial, or by plug settings. Until a few years ago, all instantaneous Over current relays were of electro-mechanical construction. They were attracted armature types, where the C.T. secondary current is passed through the relay coil, thus attracting the armature against spring tension. tension The movement of the armature causes the relay tripping contact to close.

Fault Detecting Relays years,, electronic versions of the In recent y instantaneous Over current relay have been introduced. On these relays y the pick-up setting is usually adjusted by a dial or by y setting g DIP switches. Both the electromechanical and the electronic versions are functionally y identical.

Timed Over current Relays The electro-mechanical version of this relay has an induction disc. The disc must rotate through g a definite sector before the tripping contacts are closed. This type of y is known as the Inverse Definite f Minimum relay Time relay(IDMT). The characteristic operating curve of an Inverse definite time relay is

shown on the next page.

Timed Over current Relays:

i O Timed Over current Relays: The relay characteristic is such that for very high fault currents, currents the relay will operate in it’s Minimum time of 0.2 seconds. For lower values of fault current the operate t time ti i longer. is l F example, For l att a relay current of 16 Amps, the operating time is 0.4 seconds. The relayy 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. dial

Timed Over current Relays: 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, fuses on adjacent power system elements. As with the instantaneous over current relays, there are now many electronic timed and Inverse Definite Minimum Time Over current relays on the market. Their characteristics are very similar to the electro mechanical versions. Many Over current relays have an instantaneous element, and a timed element, both built into the same relay case. The application of over current relays to feeder protection will be covered later in this seminar.

Timed Over current Relays 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 1. Overvoltage and undervoltage relays

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

2. Impedance relays

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

3. Differential relays

Differential relays are used in Bus Protection and Transformer Protection schemes. They compare th currentt entering the t i and d leaving l i th protected the t t d zone. If the unbalance is great enough, then a fault condition is detected, detected and tripping is initiated. initiated For transformers, the differential relay must have g to p provide relayy restraint for through g some biasing currents. This will be explained later when we cover Transformer Protection.

Timed Over current Relays y Other fault detecting relays include those used in Generator Protections, such as Negative Phase Sequence, Over excitation, Loss of Field, Under frequency, Out-of step, etc. The application of the various relays to power system protection schemes, will be discussed l t in later i the th seminar. i

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays: U til just Until j t a few f years ago, almost l t allll protective t ti relays were electro-mechanical, and many of these relays y changed g veryy little over a p period of 50 years or more. A good example is the induction disc over current relay which is still used extensively and has given many, many many years of reliable service. In the early 1970’s electronic relays were introduced. These relays used di discreet t solid lid state t t electronic l t i components, t and d required external DC power supplies.

i i from f i Relays to The Transition Electro-Mechanical Electronic and Microprocessor Based Relays: The performance Th f off these th early l electronic l t i relays l 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 substations. These early solid state relays offered few advantages over the electro-mechanical relays. They had essentially the same features, but had the disadvantages that they required i d a separate t power supply, l and d they th could ld nott match the reliability of electro-mechanical relays.

The Transition from Electro-Mechanical Relays to Electronic and Microprocessor Based Relays The performance Th f off solid lid state electronic l i relays l steadily dil improved over the years, and by the end of the 1980’s theyy had g gained wide acceptance, p , p particularly y over current relays which are used extensively. However, electronic relays have still not gained universal acceptance even though they are cheaper and more acceptance, versatile than their electro-mechanical counterparts. Relay manufacturers are still supplying thousands of i d i di over current relays induction-disc l to customers who h still ill prefer these robust relays which have many, many yyears of p proven reliability. y

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

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

Microprocessor-based relays are gaining very rapid acceptance by many electrical utilities, and they are revolutionizing the way that high-voltage substation protection, control and monitoring is applied. We will discuss microprocessorbased relays and their various features later in the seminar.

Tripping and Other Auxiliary Relays Power system faults are detected by the fault detecting relays, which close their output contacts to initiate tripping. tripping These output o tp t contacts are used sed to energize trip relays and other auxiliary relays which are normally supplied from the station battery DC supply. supply These auxiliary relays may perform a number of functions, such as: 9 Trip the associated circuit breaker or breakers 9 Send a trip signal to the remote terminal of the line 9 Initiate Auto-reclosing of the circuit breaker 9 Initiate I iti t Breaker B k Failure F il protection t ti 9 Send a TRIP alarm to the control room operator

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

Circuit Breakers

A typical 230kV circuit breaker rating is 70 kA or 25GVA (25,000MVA). As stated earlier, li circuit i it breakers b k mustt be b capable bl off interrupting the fault current in very short periods of time. Typical p yp circuit breaker operating times are: 9 500 kV - 2 cycles or 40 milli-seconds (50 H system) Hz t ) 9 230 kV - 3 cycles or 60 milli-seconds (50 Hz system) 9 33 kV - 6 cycles or 120 milli-seconds (50 Hz system)

Circuit Breakers These are the times from when the trip signal is sentt to t the th breaker, b k to t when h the th fault f lt currentt is i interrupted. Almost all high-voltage high voltage circuit breakers that are being built today are either SF6 Breakers or Vacuum Breakers. SF6 circuit breakers may be Air-insulated for outdoor installations, or SF6 Gas-insulated for indoor installations.

Circuit Breakers Circuit Breaker Types

Bulk B lk 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 bl values l t supply to l relays. l It is i necessary for the C.T. to provide insulation between the power system primary voltage, voltage and the relay circuit. A typical C.T. with a ratio of 1200 : 5A for a 44kV p power system y is shown next.

Current Transformers

Current Transformers Note that the C.T. polarity markings are shown as spots on the primary and secondary sides of the C.T. Also, it is important that the C.T. secondary circuit i it be b grounded, d d and d grounded d d att one point i t only.

C f Current Transformers 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, 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. 0.5 world The various types of C.T. construction will be described later.

Voltage Transformers Voltage Transformers are used to step the power system primary voltage from, 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. yp That is, a two winding g transformer in an oil filled steel tank, with a turns ratio of say 417:1(50Kv/120V) or 275:1(33Kv/120V).

Voltage Transformers On higher g voltage g systems, y , such as 230kV and 500kV, Capacitor Voltage Transformers, (or CVTs) are normally used. A CVT is comprised of a capacitor divider made up from 10 equal capacitors, connected in series from the phase conductor to ground, with a voltage transformer connected across the bottom capacitor. capacitor This V.T. actually measures one-tenth of the line voltage as illustrated in the below diagram voltage, diagram.

Voltage Transformers

End of this Section

Section 3 Section 3 Current Transformers  & Voltage Transformers

Section 3 Current Transformers & Voltage  Transformers

™Types of C.T. and V.T. Construction. ™Voltage Transformers. ™Current Transformer Theory & Characteristics. ™C.T. Accuracy. ™C.T & V.T. Accuracy. ™Testing of Current Transformers:‐ 1 C T R ti T t 1-C.T. Ratio Test. 2-C.T. Polarity Test. 3 Secondary Winding Resistance. 3Secondary Winding Resistance 4-Secondary Winding Insulation Resistance. ™Testing of Voltage Transformers ™Testing of Voltage Transformers ™Same tests

Current Transformers & Voltage Transformers Types of C.T. and V.T. Construction The most common type of C.T. construction is the ‘doughnut’ type. It is constructed of an iron toroid (‫)ح َلقي‬, which forms the core of the transformer, and is wound with secondary turns. turns

Current Transformers & Voltage Transformers The ‘doughnut’ fits over the primary conductor, which constitutes one primary turn. If the toroid is wound with 240 secondary turns, then the ratio of the C.T. is 240: 1 or 1200 : 5A The continuous rating of the secondary winding is normally 5 AMPS in North America, and 1

AMP or 0.5 0 5 AMP in i many other h parts off the h world.

Current Transformers & Voltage Transformers This type of ‘doughnut’ C.T. is most commonly used in circuit breakers and transformers. The C.T. fits into the bushing ‘turret’(‫)برج‬, and the porcelain bushing fits through the centre of the ‘ ‘doughnut’. ’ Up to four f C ’ off this type can be C.T.’s installed around each bushing of an oil circuit breaker This arrangement is shown in the breaker. following diagram

Current Transformers & Voltage Transformers

A similar type yp of C.T. can be fitted over low voltage Bus work. However, the C.T. must be insulated for the primary voltage level.

Current Transformers & Voltage Transformers The straight-through type of construction is shown below:

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

Current Transformers & Voltage Transformers The other principal type of C.T. construction is the Free Standing, g or Post type. y These can be either Straight-Through or Hairpin construction. The toroid, wound with secondary turns, is located in the live tank at the top p of the C.T. High g voltage g insulation must, of course, be provided, between the H.V. primary conductor, and the secondary winding, g, which operates p at essentially y g ground potential. Current transformers of this type are often used at voltage levels of 44 kV, 33kV, and 13.8 kV.

Current Transformers & Voltage Transformers The HAIRPIN C.T. C T gets it it’s 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 y at voltage g levels of 500kV and 230kV. Free standing current transformers are very p , and are onlyy used where it is not p possible expensive, to install ‘Doughnut’ C.T.’s in Oil Breakers or transformer bushing turrets.

Current Transformers & Voltage Transformers As an example, example C T ’s 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, winding to provide the different turns ratios. Later in this section we will discuss the characteristics and testing of C.T.’s.

Current Transformers & Voltage Transformers

Current Transformers & Voltage Transformers

V lt T f Voltage Transformers Voltage Transformers are used to step the power system primary voltage from, from say 50 kV or 33 kV to 120 volts phase-to-phase, or 69 volts phase-toground. It is this secondary voltage that is applied t the to th fault f lt detecting d t ti relays, l and d meters. t 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, 275:1. systems such as 230kV and 500kV, CAPACITOR VOLTAGE TRANSFORMERS, (or CVT’s) are normally used.

Voltage Transformers A CVT is comprised p of a capacitor p 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 V.T. act all measures meas res one-tenth one tenth of the line voltage, as illustrated in the diagram above.

Current Transformer Theory & Characteristics Current Transformers for protective relaying purposes must reproduce the primary current accurately for all expected fault currents. If we have a 33 kV C.T. with a ratio of 1200:5A, the h secondary d winding i di is i continuously i l rated d for f 5 Amps. If the maximum fault current that can flow through g the C.T. is 12,000 , Amps, p , 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. breaker

Current Transformer Theory & Characteristics The C.T. must be designed g such that the iron core does not saturate for currents below the maximum fault current. A magnetizing, or excitation curve for f a typical C.T. C is shown next.

Current Transformer Theory & Characteristics

For this C.T. to operate satisfactorily at maximum fault currents, it must operate on the linear part of the magnetizing curve. i i.e. B l Below th point the i t att which hi h saturation t ti occurs, which is known as the KNEE POINT. The KNEE POINT is defined as the p 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. secondaryy circuit, as shown next.

Current Transformer Theory & Characteristics In this example the resistance of the C.T. secondary circuit, or C.T. burden is:

C.T. Secondary Winding Resistance Resistance of Cable from C.T. to Relay Resistance of Relay Coil Total Resistance of C.T. Secondary Circuit

= 1 OHM = 2 OHMS = 2 OHMS = 5 OHMS

Current Transformer Theory & Characteristics

If the fault current is 12,000 Amps, and the C.T. ratio is 1200:5A, then the C.T. secondary currentt is i 50 Amps. A At this thi secondary d currentt and the above C.T. burden of 5 OHMS, the C T must produce a terminal voltage of 250 C.T. 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.

C f i i Current Transformer Theory & C Characteristics It is usual practice to select a C.T. with a magnetizing g g characteristic such that the maximum terminal voltage under steady state conditions, does not exceed 50% of the knee point voltage. p g This allows an adequate q margin g for remnant flux in the core, and for transient conditions. The importance of the C.T. C T maintaining good accuracy, and not saturating at the maximum fault current, is most critical on differential protection This will be covered later in the protection. course when we discuss Bus Protection and Transformer Protection.

Current Transformer Theory & Characteristics When C.T.’s are used for metering purposes, they must have a high degree of accuracy only at LOAD currents. i.e. 0 to 5 Amps secondary. There is no need for a high degree of accuracy for fault currents, t and d it is i quite it acceptable t bl for f a metering t i C.T. to saturate when fault current flows through it. A C.T 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. C T ’ss are in service they MUST have a continuous circuit connected across the secondary terminals. If the C.T. secondary i ‘open is ‘ circuit’ i i ’ whilst hil primary i current is i 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. C T is not inadvertently ‘open open circuited’.

C.T. Accuracy A typical protective relaying C.T. has it’s accuracy specified ifi d as:

This protective Thi t ti relaying l i C C.T. T h has an accuracy off 2.5% and the excitation curve knee-point voltage is 800 Volts.

C.T & V.T. Accuracy CURRENT TRANSFORMERS A typical current transformer for protective relaying purposes on high voltage transmission systems may have an accuracy rating of 2.5%. 2 5% For industrial protective relaying systems accuracy ratings of up to 10% are common. Th margins The i used d in i protection t ti relay l setting tti criteria it i are usually quite large, and 2.5% to 10% accuracy is adequate q - p provided the C.T. maintains this accuracy for all fault currents up to the maximum possible fault current.

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

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

Voltage Transformers

The accuracy for a typical voltage transformer is specified as:

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

Future Trends in C.T. Design Using Optics Free-standing C.T. C T ’s 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, relays etc. etc through fibre optic cables. Some proto-type optical current transducers are in-service at various locations and it is expected that this development locations, will lead to considerable decrease in costs for high-voltage C.T.’s.

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

1- CT Excitation Curves The p purpose p of this test is to verify y that the C.T. meets the specifications, and will not saturate during maximum fault conditions. The C.T. characteristics will ill have h b been specified ifi d by b the th designer d i off the th protection scheme.

Testing of Current Transformers

T ti off Current C t Transformers T f Testing The C.T. excitation test is performed as follows: Th voltage The lt applied li d to t secondary d t terminals i l off the th C.T. is varied in steps of, say 50 volts, and the C.T. magnetizing current is measured in milliamps, up until the C.T. saturates. The results obtained should be similar to those specified in manufacturer manufacturer’ss test data, data and also to the results for similar C.T.’s.

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

2- C.T. Ratio Test The purpose of this test is to verify that the C.T. ratio is correct for the various taps on the secondary winding. Th simplest The i l t test t t for f C.T. C T ratio ti is i to t pass a current, t of say 12 Amps, through the primary of the C.T., and measure the secondary current with a milli milliammeter, say 50 mA. The C.T. ratio is then calculated as 12A: 5OmA or 1200 : 5A. The C.T. ratio ti can also l be b tested t t d by b using i a RATIOMETER. RATIOMETER

3- C.T. Polarity Test The purpose of the C.T. polarity test is to ensure that direction of current flow in the secondary circuit i it is i correctt relative l ti t the to th primary. i Thi is This i extremely important where the secondary windings of a number of C.T. C.T.’s s are connected together, such as in a differential protection scheme. We will discuss this later when we cover B Protection. Bus P t ti

C.T. Polarity Test

The C.T. ppolarityy can be verified byy a veryy simple p test, known as the Flick Test.

C.T. Polarity Test An analogue meter, on the d.c. milli-amp range, is connected across the C.T. secondary terminals, with the positive lead to ‘spot’ or X1. A 1.5 volt ‘D’ cell is then used to pass a current through the C.T. CT primary. As the connection is made to the ‘D’ cell, to pass current from the cell positive, to the C.T. primary ‘spot’ spot or H1, H1 then the d.c. d c milli-ammeter milli ammeter will deflect or ‘flick’ in a positive direction. As the connection from the ‘D’ cell is removed, the milliammeter t will ill deflect d fl t in i a negative ti di ti direction. If a ratio meter is used to check the C.T. ratio, then the correct p polarity y will be indicated by y that meter.

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

5-Secondary 5 Secondary Winding Insulation Resistance The purpose of this test is to verify that the C.T. secondary winding insulation is in good condition. The entire secondary circuit of the C.T. must be tested with a MEGGER and a result in excess of 10 MEG OHMS, at 500 volts is normal. It is very important that the C.T. secondary circuit is GROUNDED AT ONE POINT ONLY, normally att the th relay l panel. l If the th grounding di i done is d through a link, then this provides a convenient point to disconnect the ground to ‘Megger’ the entire C.T.secondary circuit during routine maintenance tests.

Testing of Voltage Transformers The purpose of this test is to record the magnetizing current, current and compare it with the manufacturer’s test data, and to record it for future reference. reference This test is of questionable value, and may not be worth performing, performing in view of the risks associated with the very high voltages.

V.T. Ratio and Polarity Test The V.T. ratio and polarity can be tested with a ratio ti meter. t Alternatively, the V.T. primary winding can be energized at 120 volts A.C. A C and the secondary voltage measured. With the V.T. V T in-service, in-service the secondary voltage and phase angle should be checked against g a known V.T. The p polarity y of the V.T. can be checked by performing the ‘FlickTest’ described earlier for C.T.’s.

Secondary y Winding g Resistance The secondary Th d winding i di resistance i t should h ld b be measured with a digital ohm-meter.

Insulation Resistance of Windings The insulation resistance of the secondary and primary p y windings g 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.

End of this End of this Section

Section 4 Power System Neutral  y Grounding

Section 4   Power System Neutral Grounding ¾ ¾ ¾ ¾ ¾

Ungrounded Systems Solidly Grounded Systems Solidly Grounded Systems Resistance Grounded Systems R t Reactance Grounded Systems G d dS t Typical Resistance Grounded Systems in  Industrial Plants Industrial Plants ¾ Ground Fault Detection on Resistance  Grounded Systems Grounded Systems ¾ Ground Fault Detection on Ungrounded  Systems

Power System Neutral Grounding During g p power system y ground faults the magnitude g g of the current that flows in the ground is governed by the method adopted for grounding the power system t star t or neutral t l point. i t For most power system elements (such as feeders, lines buses & transformers) it is usual for ground lines, faults to result in an excessive current flow. The protection relays or fuses respond to this over current condition to clear the fault from the system.

Power System Neutral Grounding However, for some power system elements, notably(‫ )بشكل خاص‬generators, 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 less than about 5 Amps. There are various reasons, both technical and economic, for grounding the neutral point of a power system. t I the In th early l days d th three phase h power systems were operated with the neutral ungrounded.

Power System Neutral Grounding

However, these systems were found to be prone(‫) ّتعرّ ض‬ to failures due to common mode transient over voltages. For a ground fault on one phase, the voltage off the h un faulted f l d phases h i increases. Al Also, d i system during ground faults the voltage of the neutral point of the transformer winding increases. I order In d to t limit li it the th magnitude it d off the th over voltages, lt solid grounding of the neutral was adopted. The economic reason applies for High Voltage systems where, here by b solidly solidl grounding gro nding the neutral ne tral point of a transformer it is permissible to grade the thickness of the winding insulation downwards towards the neutral point This is almost universal at voltages of 100 kV point. and above.

A th t h i l Among the technical reasons are: The floating potential on the lower voltage (secondary and tertiary) windings is held to a harmless value. Arcing faults to ground do not set up dangerously hi h voltages high lt on the th healthy h lth phases. h By controlling the magnitude of the ground-fault current inductive interference between power and current, communication circuits can be controlled. A high value of ground-fault current is normally available il bl to t operate t the th more usuall types t off protection schemes, such as over current and impedance. p

P S t N t lG di Power System Neutral Grounding 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 capacitance-to-ground 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, outage and the cost of ground fault detection equipment is low. The disadvantages are that they are subject to transient over voltages, and the insulation strength of equipment connected to ungrounded systems must be greater than for grounded systems.

Power System Neutral Grounding The methods most commonly used to ground power system neutrals are as follows:

¾ SOLIDLY GROUNDED SYSTEMS Solidly S lidl grounded d d means a direct di t connection ti with ith a conductor of adequate size, from the neutral to the ground g g grid. There is no intentional impedance p introduced, other than the resistance of the grounding conductor itself. The term EFFECTIVELY GROUNDED is often used to define this type of grounding. grounding The term EFFECTIVELY GROUNDED is often used to define this type of grounding. grounding

Power System Neutral Grounding An EFFECTIVELY GROUNDED system is defined as “Grounded Grounded through a sufficiently low impedance such that for all system conditions the ratio of zerosequence reactance to positive sequence reactance is positive and Less than three, and the ratio of zero-sequence resistance to positive sequence resistance i t

is i positive iti and d lless th than one.””

Power System Neutral Grounding Another definition is “An Effectively-Grounded System is one in which during a phase phase-toto ground fault, the voltage to ground of any of the healthy phases does not exceed 80% of the voltage between phases of the system.”

Resistance Grounded Systems Resistance Grounded Systems A resistance grounded system is one where a the neutral point is connected to ground through a fixed resistor. i t This is also known as ‘non-effective’ grounding. The effect of g grounding g the system y neutral through g 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 over voltages.

R it G d dS t Resistance Grounded Systems A value sometimes chosen for the grounding resistor is one that limits the ground ground-fault fault current, 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. grounds A typical value of neutral grounding resistor for utility power systems p y 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. amps A high neutral grounding resistance of 69 OHMS limits the ground fault current to about 5 amps on a 600 Volt V lt system. t

d d Resistance Grounded Systems

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

Ground Fault Detection on Resistance‐Grounded Systems

Ground faults can be detected on resistancegrounded systems by monitoring the current that flows through the neutral grounding resistor. In the h above b example l a current transformer f i fitted is fi d around the conductor from the resistor to ground, and the secondary current of the C.T. supplies an over current relay. On systems that are grounded through a high resistance, where the ground fault current is low, low the ground-fault ground fault detection over current relay may initiate an alarm, rather than trip.

Reactance Grounded Systems A reactance grounded system is one where the neutral point is connected to ground through a fixed reactor. Again, this is ‘non-effective’ grounding. The advantages of reactance grounding are similar t those to th f for resistance i t grounding. di A typical t i l distribution utility uses 2 OHM reactors to ground the neutral on it it’ss 25 kV system, system and 5 OHM reactors on the neutrals of it’s 44 kV system. y

ARC Suppression Coil Grounded Systems Arc-suppression coil grounding (or resonant or ground fault neutralizer grounding) uses a reactor with a value chosen to match the value off the th capacitance it t ground to d off two t phases h with ith the third phase connected solidly to ground. I this In thi way the th reactive ti componentt off the th 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 g from the capacitance p current.

ARC Suppression Coil Grounded Systems This tuning of the grounding reactor with the system y capacitance p results in g 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 th U.S.A. the USA

Petersen Coil earthing Petersen Coil earthing is a special case of high impedance earthing. earthing The network is earthed via a reactor, reactor whose reactance is made nominally equal to the total system capacitance to earth. Under this condition, a single phase-earth fault does not result in any earth fault current in steady-state conditions. The effect is therefore similar to having an insulated system. system The effectiveness of the method is dependent on the accuracy of tuning of the reactance value – changes in system capacitance (due to system configuration changes for instance) require changes to the coil reactance. In practice, perfect matching of the coil reactance to the system capacitance is difficult to achieve, achieve so that a small earth fault current will flow. Petersen Coil earthed systems are commonly found in areas where the system consists mainly of rural overhead lines, and are particularly beneficial in locations subject to a high incidence of transient faults.To faults To understand how to correctly apply earth fault protection to such systems, system behaviour under earth fault conditions must first be unders

G d F lt D t ti U d d Ground‐Fault Detection on Ungrounded  Systems On ungrounded O d d systems, t a single i l ground-fault d f lt will not result in the flow of any fault-current. For a ground-fault ground fault on one of the phases, phases the voltage-to ground on the two un faulted 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. ground-fault systems It is usually a requirement that ground-fault detection be provided on ungrounded systems. systems

Generator Neutral Grounding

Generator Neutral Grounding ¾Reasons for limiting generator ground fault  current. current ¾Methods used to ground the neutral of  generator stator windings. t t t i di ¾Detecting generator stator ground faults.

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

Generator Neutral Grounding 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.

Generator Neutral Grounding The value of the neutral grounding resistor d t determines i th maximum the i ground-fault d f lt currentt 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. amps With this arrangement stator ground faults are detected by the use of an over current relay supplied from a current transformer measuring the neutral-grounding resistor current.

Generator Neutral Grounding 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 g g transformer ,,with a resistor connected across the secondary terminals. Usuallyy a distribution transformer is used.

Generator Neutral Grounding

l d Generator Neutral Grounding The value of the resistor is chosen to limit the ground fault current, current for phase phase-to-ground 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 ground-fault fault, but if a second ground fault occurs there would be very high fault current and serious damage to the machine would result.

Generator Neutral Grounding

Generator Neutral Grounding Detecting Stator Ground Faults The stator winding of a typical generator is grounded at the star point through a neutral grounding transformer, transformer with a resistor connected across the secondary terminals, as shown in the above diagram. g The value of this resistor is chosen to limit the ground fault current, for phase-to-ground faults on the th stator t t winding, i di t about to b t 5 amps. A Voltage Relay is connected across the resistor to detect stator g ground faults.

Generator Neutral Grounding This type yp of stator g ground-fault p 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.

End of this End of this Section

Section 5 Section 5 Feeder Over current Protection Feeder Over current Protection

Section 6  Feeder Over current  Protection

Feeder Over current Protection. Criteria for Setting the Low‐set  g Instantaneous Over current Relay. Directional Over current Protection Directional Over current Protection. Testing of Feeder Over current Protection. Mi Microprocessor‐Based Feeder Protection  B dF d P i Relays.

Feeder Over current Protection By far the most common type of protection for radial distribution feeders is Over current protection. Typical distribution system voltages are 44 kV, kV 33 kV & 25 kV. The point of supply is normally a few e kilometers o ete s from o tthe e load. oad

Feeder Over current Protection Feeder Over current Protection With Radial feeders there is only one possible point of supply, and the flow of fault currentt is i in i one direction di ti only. l Over O currentt protection can therefore be used to provided adequate q protection. p 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 over current relays. These over current relays must then operate and initiate tripping if a fault condition is detected on the feeder.

Feeder Over current Protection

Feeder Over current Protection The over current protection at the supply end of the feeder must operate for all faults on the feeder, but should not operate for faults beyond y the remote station ‘B’. If we first consider an instantaneous over current relay, then the setting is determined by the magnitude of the fault current at the end of the feeder.

Feeder Over current Protection Let us assume that the fault current at that point is 4800 amps. 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 i for f the th following f ll i reasons: (A)It is not possible for the relay to differentiate between faults which are veryy close to,, but which are on each side the Bus ‘B’, since the difference in the currents would be extremely s a small.

(B)Inaccuracies in the C.T’s and relays, and the effects of distortion of the current waveform under transient conditions p produce errors in the response p 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 t changes h as generators t are putt in i and out of service.

Feeder Over current Protection O l i hi problem bl i to set the h One solution to this is instantaneous Over current 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 over current 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’ close in faults, which have the highest magnitude of fault current.

Feeder Over current Protection This time-delayed clearing of high fault currents is usually unacceptable, and the most common protection scheme, which overcomes the feeder p problem utilizes an inverse time over current relay in conjunction with the instantaneous over current relay. y The application pp of this feeder protection scheme, utilizing both instantaneous and inverse time over current relays is described next: In order to ensure that the instantaneous over current relay will not unnecessarily operate for faults at the remote station, station (which should be cleared by the over current protection or fuses at that station) then it must be set to protect only part of the feeder. feeder A safe maximum for most types of relay is 80% of the feeder length.

Feeder Over current Protection Feeder Over current Protection The limit is determined by the characteristics of the relay used, and the length of the feeder. If the feeder is long, 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 over current protection. protection This type of protection is known as High-Set Instantaneous over current protection. Wi h such With h a relay l set to detect d f l on 80% off faults the feeder, the remaining 20% is left unprotected. This is, of course, not acceptable. To provide protection for the last 20% of the feeder a timegraded, or Inverse Definite Minimum Time relay can be used.

Feeder Over current Protection This type yp of relayy p provides timed over current protection, and maintains coordination with the fuses or over current relays l att the th remote t station. t ti The operating time of the relay is inversely proportional to the current. current i.e. 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.

Feeder Over current Protection If we superimpose the fuse characteristic of one off the th transformer t f f fuses att the th remote t station, on to the above Over current relay characteristic, we can see how the relay settings at the supply station are coordinated with the transformer fuse. With this thi scheme h off protection, t ti utilizing tili i HighHi h Set over current relays, Inverse Definite y , and fuses,, Minimum Time over current relays, we will consider the response of the protection scheme to faults at various locations. locations

Feeder Over current Protection 1. For a Fault at point X on the feeder, ONLY the High- Set S Instantaneous over current 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, th f therefore th t relay that l will ill nott operate. t The Th inverse i timed Over current relay will operate after a time g of the fault delayy determined byy the magnitude current and the relay characteristic.

Feeder Over current Protection 3. For a fault at point Z, it is again beyond the ‘reach’ reach of the High High-set set Instantaneous relay. The Inverse Timed over current relay will start timing timing, but the fuse on the feeder F1 will operate first and clear the fault. The inverse timed over current relay at station ‘A’ will then reset.

Feeder Over current Protection

Feeder Over current Protection 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 Over currentt and d Inverse I Ti d Over Timed O currentt relays are used, and the H.S. relay must p for be set such that it does not operate 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.

Feeder Over current Protection The criteria used for setting the Inverse-Timed O Over currentt relay l are: 1. The relay must not operate for the maximum load current that will be carried by the feeder. 2. The relay y setting g 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 3. set to coordinate with other protection devices, such as fuses, ‘downstream’ from the h supply l station. i

Feeder Over current Protection 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 g is that most faults will be slow in clearing because the inverse time over current relay l mustt operate. t This Thi slow l ffaultlt clearing l i is usually disturbing to customers on the affected feeder feeder.

Feeder Over current Protection As mentioned A ti d earlier, li there th i a very high is hi h incidence of faults caused by lightning on overhead h d feeders, f d particularly ti l l att the th lower distribution voltages. Consequently, th greatt majority the j it off faults f lt on such h feeders are transient in nature, and can b cleared be l d by b opening i th breaker, the b k with ith no permanent damage resulting.

Feeder Over current Protection Protection schemes for this type yp of feeder can be enhanced by adding a Low-Set Instantaneous Over current relay and providing AutoReclosing of the circuit breaker after fault clearance. The low set instantaneous over current relayy is set to operate for the minimum fault current at the very end of the feeder. This means that it will ‘Overreach’ Overreach and operate for faults in the transformers tapped on the feeder. All faults will therefore be first detected by the Low-Set relay.

Feeder Over current Protection This relay then trips the breaker, and also initiates A t Reclose. AutoR l F For about b t 90% off the th faults f lt this auto-reclose will be successful, and the interruption p to the customers is for onlyy 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. unsuccessful After the circuit breaker has auto reclosed the tripping from the Low-Set overcurrent relay is disabled for 10 seconds. d Thi means that This th t proper protection t ti coordination will then take place: i.e.

Feeder Over current Protection 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 2. th fault f lt is i on the th feeder, f d beyond b d the th first fi t tap, t then the inverse timed overcurrent relay will operate p after a time delay, y, and the feeder will trip p a second time and ‘Lock Out’. 3. If the fault is close to the supply station, then the High-Set High Set overcurrent relay will operate and trip the feeder a second time, with no intentional y and ‘Lock Out’. time delay,

Feeder Over current Protection A typical feeder over current A.C. schematic diagram, showing all three phases, is shown above The diagram includes High-Set above. Instantaneous, Inverse Time, and LowSet Instantaneous relays. Very often the hi h t instantaneous high-set i t t and d inverse i ti time overcurrent relays are built into a single g , all of relayy case. Until a few yyears ago, these relays were electro-mechanical, and often in separate relay cases.

Feeder Overcurrent Protection ii.e. e The H.S. H S Instantaneous - attracted armature, and the Inverse Time - induction disc More recently electronic relays were disc. used, and the settings are applied by changing the position of ‘DIP’ DIP switches. These electronic over current relays were much more compact, p , and were functionallyy identical to the electro-mechanical over current relays.

Feeder Over current Protection Today, almost all over current relays being Today 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.

Feeder Over current Protection The D.C. D C tripping circuit for such an over current 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 over current protection settings are shown. The protection coordination curves for the various relays and fuses are also shown. shown

Criteria for Setting the Inverse‐Timed Over current  Relay 1.The relay must not operate for the maximum load current that will be carried by the feeder. i.e. cold load pick pick-up up and back back-to-back to back 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. f 3.The relay operating characteristic must be set to coordinate with other protection devices, devices such as fuses, ‘downstream’ from the supply station.

Criteria for Setting the High‐set Instantaneous  Over current Relay Over current Relay 1 The relay must be set to operate for faults up to 1. to, but not beyond, the first tap from the feeder. 2 In practice 2. practice, the relay is set to operate for faults up to 80% of the distance to the first tap. This provides high-speed g clearance for the high g level faults close to the supply station.

Criteria for Setting the Low‐set I t t Instantaneous Over current Relay O tR l 1. The relay must operate for all faults on the f d right feeder, i ht up tto the th feeder f d end. d 2. This provides high-speed initial clearance for all f lt on the faults th feeder. f d 3. For 10 seconds after the feeder breaker auto recloses the tripping from the low recloses, low-set set relay is blocked.

Directional Over current Protection Over currentt protection O t ti i used is d extensively t i l 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, d ect o , a and d tthe e syste system iss no o longer o ge radial. ad a If the generation is large (typically above about 5 MW) in comparison to the normal load on the feeder, then the feeder over current protection at the supply station requires directional supervision.

Directional Over current Protection A directional relay or element is used to supervise the Over current relay elements to allow the over current 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.

Microprocessor‐Based Feeder Protection  Relays Most feeder protection relays being installed today are microprocessor-based, microprocessor-based and include many functions within the one relay. As well as the basic instantaneous and inverse- timed over current functions, these relays y also include manyy other p protection functions and additional features.

Microprocessor‐Based Feeder Protection Relays ¾ Directional Supervision ¾ Under voltage and Overvoltage ¾ Bus under‐frequency & Rate‐of‐change ¾ Synchronism Check ¾ Negative Sequence Voltage N ti S V lt ¾ Auto‐reclose ¾ Event Recording Event Recording ¾ Oscillography, or Waveform Capture ¾ Fault Location Fault Location

Feeder Protection System  F60

Section 6 Coordination of Protection Systems

Section 7  Coordination of Protection Systems

• • • • • •

Time‐Current Coordination. Protective Relaying Zone. Requirement for Back up Protection Requirement for Back‐up Protection. Breaker Failure Protection. Tripping. Relay Settings. y g

Coordination of Protection Systems As described earlier, one fundamental requirement q of all p protection systems y is selectivity or discrimination. This means that only the faulted power system elements should b disconnected be di t d to t clear l th fault, the f lt leaving l i allll unfaulted equipment in service. On radial power distribution systems, systems where the flow of fault current is in one direction only, timecurrent coordination is g generally y used.

d f Coordination of Protection Systems On interconnected transmission systems, 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. used These unit unit-protection protection schemes operate with no intentional time delay, and provide high-speed clearance of faults before power system instability results.

Time‐Current Coordination On radial distribution systems over current devices such as fuses and inverse-time over current relays are generally used to provide protection. protection the available fault current decreases as the distance from the supply station increases. increases Over current devices are therefore generally used, in series, with progressively lower ratings, to protect various sections of distribution feeders.

Time‐Current Coordination Fuse‐to‐fuse Coordination

The time-current characteristic of a typical fuse is shown below, and is represented t d by b a band b d between b t th the minimum melting time and the maximum clearing time of the fuse element.

Time‐Current Coordination For correct coordination between two fuses in series it is important to ensure that the series, characteristic bands for the two fuses do not p at any y p point, when intersect and overlap plotted on the same graph. To provide an adequate coordination margin for two fuses A and B connected in series, 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 A. Similarly Similarly, the time current time-current characteristics of fuses are coordinated with those of over current relays associated with circuit breakers and re closers.

Relay to Relay coordination : Relay to Relay coordination :  With the time‐current characteristic, the time of operation is inversely proportional to the fault current level and the actual characteristic is a function of both ‘time’ and 'current' settings. Sh t t operating Shortest ti times ti can be b achieved hi d by b the th relays l nearestt to t the source, where the fault level is the highest The disadvantages of grading by time or current alone are overcome . For optimal grading between two relays The total interval required to cover circuit breaker interrupting time, relay timing error, overshoot and CT errors, depends on the operating speed of the circuit breakers and the relay performance. At one time 0.5s was a normall grading di margin i With faster f t modern d circuit i it breakers b k and da lower relay overshoot time, 0.4s is reasonable, while under the best conditions even lower intervals may be practical.Figure below shows the characteristics of five relays y ggiven different current‐time settings. Grading example

Relay to Relay coordination :  y y

Relay to Relay coordination  example  

Protective Relaying Zone The following diagram shows a section of a t i l power system, typical t comprising: i i 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.

Protective Relaying Zone Adjacent zones are separated by circuit breakers, and are shown in the diagram above. above Protective relaying zones are determined very largely by the location of the current transformers. It is good practice where practical, practice, 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. protected The overlapping of adjacent protection zones across the circuit breakers is illustrated by the l location ti off the th currentt transformers t f i the in th above b diagram.

Protective Relaying Zone For example example, where a feeder is supplied from a bus: 1 The feeder protection C 1. C.T.’s T ’s m must st be located on the bus side of the circuit breaker. breaker 2. The bus protection C.T.’s must be located on the feeder side of the circuit breaker.

Requirement for Back up Protection Requirement for Back‐up Protection During our earlier discussion on feeder over current protection we saw that the inverse timed over current relay characteristics are set to co-ordinate, and provide back-up to downstream devices such as over current relays and/or fuses.

Requirement for Back‐up Protection This type of time-graded back-up works fine for radial systems. systems However, 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 g cleared from the power system. It is not, of course, practical to duplicate circuit breakers. Breaker-failure protection is therefore provided to ensure that th failure the f il off a circuit i it breaker b k does d nott result lt in i an uncleared fault, and possible power system collapse.

Breaker Failure Protection On interconnected systems, such as the high voltage transmission system, system fault current can flow in either direction and the application of such ‘Back Up’ protection is not possible. If a transmission t i i system t f lt is fault i un cleared l d because of the failure of a Circuit Breaker, the effects can be enormous. There would be i di i i indiscriminate tripping i i off transmission i i li lines and d generators, and a power system collapse could easily result. Breaker Failure protection is therefore provided on all circuit breakers on the transmission system.

Breaker Failure Protection A simplified diagram of a typical breaker failure protection scheme for a high voltage circuit breaker is shown below below. This scheme is used by Ontario Hydro, Canada, on all 230 kV and 500 kV circuit breakers.

Tripping When the breaker failure protection operates it must trip ALL of the circuit breakers on BOTH adjacent zones, zones including the breakers at the remote end of associated lines. lines The breaker failure protection tripping relays ‘seal-in’ for 45 seconds This holds the tripping signal seconds. on to all of the tripped breakers and prevents them from auto reclosing. reclosing

SPEED The speed of operation of breaker failure protection i must be b fast f enough h to prevent indiscriminate tripping of power system elements and to prevent the power system from elements, going unstable. Typically a fault would be cleared in 150 to 200 milliseconds 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  b k breaker.

OVERCURRENT SUPERVISION

Breaker failure protection is supervised by  B k f il t ti i i db high‐speed instantaneous over current relays.  Th These relays must have a very fast reset time  l th f t t ti and a high pickup/drop‐out ratio.

Relay Settings INSTANTANEOUS OVERCURRENT SUPERVISION RELAYS

The high high-speed speed instantaneous over current supervision relays are typically set for 1,000 primary amps.

Relay Settings 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. margin Typically this setting would be 4 cycles (or 67 milliseconds for a 60 Hz power system). This leg of the circuit provides id th fastest the f t t operation ti off the th breaker b k failure protection. It will operate if the auxiliary p within 67 milliseconds after switch has not opened the trip signal is sent to the breaker, breaker failure protection is initiated, and fault current is still flowing. flowing

Relay Settings TIMER 62b TIMER 62b The criterion for setting the 62b timing relay is the breaker tripping time, PLUS the reset time of the over current 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 hi h will ill operate t if the th breaker b k auxiliary switch opens, but the main contacts fail to interrupt the fault current. current

Relay Settings TIMER 62c The purpose of this leg of the circuit is to provide breaker failure protection when there are low magnitudes of fault current, current below the 1,000 1 000 amp pickup of the over current supervision relays. (e.g. For faults at the remote end of very long lines). Th contacts The t t off this thi relay l are nott supervised i d by b the over current relay, and the setting is typically 500 milliseconds 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. system

Relay Settings 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.

Relay Settings AUTO-RECLOSING OF CIRCUIT BREAKERS 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 ld be b sett to t auto-reclose t l after ft a time ti d l delay of 0.5 seconds.

End of this End of this Section

Section 7 Bus Protection us otect o

Section 8  Bus Protection ¾Types of Relays Used. ¾T fR l U d ¾High Impedance Differential Protection. ¾Bus Protection Tripping

Bus Protection The main bus in transformer stations is one of the most critical pieces of equipment in our power distribution and transmission systems. 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 d may have h multiple lti l in i feeds. f d Faults F lt on buses b are almost always permanent and auto-reclosing pp is therefore not applicable.

Bus Protection Reliable bus protection is essential for all power systems, systems from the switchboards of industrial plants, to high voltage buses in utility substations. substations The consequences of an un cleared bus fault are enormous. Also, the unnecessary tripping of a bus due to the mal operation of the bus protection scheme p outages. g can cause widespread

Bus Protection The choice of the type of bus protection to apply l for f any particular ti l location l ti is i very largely l l dependent upon the voltage level, and whether the bus is supplied from a radial system, or is part of an interconnected system. F For b buses th t are partt off interconnected that i t t d systems, where there is more than one possible in-feed for fault current,, differential p protection is most appropriate. This is typical for utility substations at voltage levels of about 13.8 13 8 kV and above. above

Bus Protection Bus Protection For buses supplied from radial systems, where h th there i only is l one source off supply, l over current 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. transformer Instantaneous over current and inversetimed over current devices are used, used with settings selected to coordinate with the downstream devices,, as discussed earlier.

Bus Protection BASIC CONCEPT OF DIFFERENTIAL PROTECTION The ideal way to protect any power system element is to compare p the current entering g that element, with the current leaving it. If there is no fault condition, then the two quantities are equal. 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.

Bus Protection The diagram above illustrates the principle of Diff Differential ti l Protection P t ti in i it’s it’ simplest i l t form: f I the In th above example there is through or out of zone fault current of 6,000 6 000 Amps. Amps The currents in the C.T. secondary circuits circulate, and there is no spill p into the relay. y Hence,, the Bus Protection does not operate, and remains stable.

Bus Protection We now consider a fault on the bus, bus of the same 6,000 Amps. The current in both C T ’s C.T. s is now in the same direction, direction and the current in the C.T. secondary circuit no longer circulates. circulates The two C.T. C T secondary currents are summed, and the total of 25 Amps passes through the differential relay. relay For this IN ZONE fault, the relay will operate and initiate tripping. tripping

Bus Protection Bus Protection 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 same.

Bus Protection Application to Various Bus Configurations Application to Various Bus Configurations We can now extend this theory to a bus with many lines connected to it. it Take the following example of a bus with 5 f d feeders connected t d to t it. it For F a total t t l bus b fault f lt current of 18,000 Amps, the fault current in each h feeder f d is: i

Bus Protection Now, as an exercise, draw the C.T. currents if the same 18,000 18 000 Amp fault is on feeder F5. Th C.T. The C T secondary d currents t once again i balance, and the Bus Protection remains stable t bl for f the th THROUGH fault. f lt

NOTE: Differential Bus Protection will never operate as back-up back up protection for un cleared faults on other parts of the power system. For example, p an un cleared 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. C T ’ss MUST be located on the feeder side of the breakers. If the bus p protection C.T.’s are located on the bus side of the breaker, then a protection blind spot exists.

C

D

Bus Protection 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. examples i.e. ie 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 in feed from them for bus faults. For a fault on BUS D, the fault current is supplied through the T2 and BT breakers ONLY. ONLY

Bus Protection Consequently, we can provide BACK-UP protection t ti f the for th feeders f d b using by i the th T2 and d BT breaker C.T.’s. The Back-up protection relay is connected as shown, and will normally be an I Inverse Ti Time O Overcurrent t Relay, R l and d sett to t coordinate with the feeder protection relays. Thus, if there is an uncleared fault on feeder F6 for example l (i.e. (i the th breaker b k fails f il to t clear l th fault, the f lt or the protection fails to operate), then the F6 fault current continues to flow through the T2 and BT C T ’ The C.T.’s. Th sum off these th t two currents t passes through the D BUS back-up relay, which will operate after a time delay, and clear the fault by t i i the tripping th D BUS breakers. b k

Types of Relays Used Various types of fault detecting relays are used in Bus Differential protection schemes. These include instantaneous over current, inverse timed over current and high impedance relays. The high impedance relays are becoming more popular l because b th give they i much h greater t stability under through fault conditions.

Types of Relays Used Bus Protection Relay Settings 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 relayy is set too low, then there is the risk that it will mal-operate for through faults, and cause unnecessary tripping of the bus.

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. 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 Differential Protection High Hi h i impedance d relays l are used d 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 worstt case is i with ith one C.T. C T completely l t l saturated, and the other C.T.’s not saturated.

High Impedance Differential Protection The resulting differential current will cause the maximum 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.

High Impedance Differential Protection For internal faults the high g impedance p of the differential relay forces much of the resulting differential current through the C.T. exciting impedances. impedances The resulting voltage developed across the relay is essentially the open open-circuit circuit voltage of the C.T.’s, and will be well above the voltage setting of the relay. A non-linear resistor, or arrestor t i is connected t d across the th relay l terminals to limit the voltage to a safe value during g fault conditions.

Bus Protection Tripping When a bus fault is detected, detected all of the circuit breakers on that bus are tripped. Bus faults are almost always permanent, permanent rather than transient faults. There must therefore be no auto-reclosing g 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.

Bus Protection Tripping 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, panel rather than test the relays on a bench. By injecting g test links on the the test current through panel, the C.T. secondary wiring as well as the relay is tested.

Bus Protection Tripping It is usual to have one zone of protection for each section of the bus. These are g zones. There known as discriminating is also another zone of differential protection for the entire substation, which i known is k as the th check h k zone. For F tripping ti i 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. operate

End of this End of this Section

Section 8 Motor  Protection & Control

Section 9   Motor Protection, Starting & Control

• • • • • • • • •

Motor Protection and Control. Overload protection Overload protection  Over current Protection. Ground Fault Protection Ground Fault Protection. Under voltage Protection. L Loss of Phase or Single Phasing. f Ph Si l Ph i Motor Winding Temperature. Motor stalling  Motor Differential Protection.

Motor Protection and Control The vast majority of motors in industrial applications are induction motors, 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.

Motor Protection and Control Overload p protection of three-phase p 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 g controllers. When used on manual starters or controllers, the heating elements release a mechanical trip to drop out the line contacts. contacts These bimetallic overload devices have inverse-time characteristics.

Thermal Overload Relays Thermal Overload Relays 

Motor Protection and Control Consequently, Co seque t y, for o a very ey ssmall a percentage overload it may take a considerable time before tripping pp g takes place. However,, for a veryy heavyy overload fast tripping is achieved. Ideally, the timecurrent characteristic of the thermal overload device should coordinate with the damage curve of the motor.

Motor Protection and Control A coordination diagram showing the thermal overload, o erload motor damage curves, and motor currents is included on the next page. page

Motor Protection

Over current Protection Over current p protection is required q for the motor branch circuits. Over current 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. motor, itself Contactors are used to control motor operation. However, contactors have a veryy limited fault interrupting capability, and are not used to clear faults (other than overloads).

Over current protection Over current protection 

Ground Fault Protection Ground fault protection is normally only provided on motors larger than about 200 HP. HP The three phase conductors are passed through a window-type zero sequence current transformer which supplies a ground over current 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, t unequall C.T. C T saturation t ti can cause a residual current to flow in the relay, and appear as a ground fault.

Ground Fault Protection 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 d t determined i d by b the th method th d by b which hi h the th supply transformer neutral is grounded. In many industrial plants the neutral of the supply l transformer t f i grounded is d d through th h a resistor to limit the ground fault current. Typically yp y the neutral of the 600 volt winding g of the transformer is grounded through a 15 Ohm resistor, which limits the maximum ground-fault current to 23.1 amps. g p

Ground Fault Protection Ground Fault Protection For small motors on this system, of less than about 20 HP, motor ground faults will be cleared by the operation of the phase over current device, or the thermal overload device.

Ground Fault Protection

Zero Sequence CT Connection • Best method • Most sensitive 

Under voltage Protection Under voltage 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 under voltage 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 byy properly sized overload devices. Table 25 of the Electrical Safety Code requires that an overload l d device d i b provided be id d in i each h phase. Older installations may have only two overload devices on three-phase three phase motors.

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 t temperature t condition diti and d trip t i the th motor.

Motor Winding Temperature Very large motors, with supply voltages above b 600 Volts, V lt are expensive, i and d it is i usually wise to provide more p protection schemes. Such p comprehensive schemes include: Differential protection Ph Phase unbalance b l or negative i phase h sequence Incomplete start sequence Stall or locked rotor Out of step Out-of-step

Motor Stalling Motor Stalling Motor Stalling: • It happens when motor circuits are energized, but  motor rotor is not rotating. It is also called locked  rotor.  • Effects: this will result in excessive currents flow  given the same load. This will cause thermal  damage to the motor winding and insulation. • Similar types of relays that are used for motor  l f l h df timed overload protection could be used for  motor stalling protection motor stalling protection. 

Out of Step Protection Out‐of‐Step Protection A synchronous motor may decelerate and lose synchronism (fall out out‐of‐step) of step) if a mechanical overload exceeding the peak motor torque occurs. Other Conditions that mayy cause this condition are a fall in the applied voltage to stator or field windings. An out‐of‐step condition causes the motor to draw excessive current and generate a pulsating torque. Even if the cause is removed promptly, the motor will probably not recover synchronism, synchronism but eventually stall. Hence, it must be disconnected from the supply pp y

Out‐of‐Step Protection The current drawn during an out‐of‐step condition is at a very low power factor. Hence a relay element that responds d to low l power factor f can be b used d to provide d protection. The element must be inhibited during starting, when a similar low p power factor condition occurs. This can conveniently be achieved by use of a definite time delay, set to a value slightly in excess of the motor start time. The power factor f t setting tti will ill vary depending d di on the th rated t d power factor of the motor. It would typically be 0.1 less than the motor rated p power factor i.e. for a motor rated at 0.85 power factor, the setting would be 0.75.

Motor Differential Protection Differential Diff ti l protection t ti i often is ft provided id d for f medium and large size motors with supply voltages of greater than about 4 kV, and electrically operated (shunt trip) circuit breakers. breakers The differential protection provides high speed direction and clearance of faults on the motor stator windings. windings Where the power supply system is solidly grounded the differential protection will detect both phase-to-phase and phase-to-ground faults. faults

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

Motor Differential Protection 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 i on C.T.’s C T ’ and d use a single i l C.T. CT per phase. For each phase the connection from each end of the winding is passed th through h the th single i l C.T. C T as shown h above. b Under healthy conditions the C.T. output will be zero. When a fault exists a differential currentt flows fl i the in th C.T. C T secondary, d and d causes the relay to operate.

Motor Differential Protection For very large motors a separate C.T. is used at each end off the winding, for f each off the three phases. The C.T. C T ’ss 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. t

Microprocessor‐Based Control & Protection  Devices Microprocessor-based Mi b d devices d i are now widely id l available to perform many motor control, protection,, metering, p g, and monitoring g functions. These devices are commonly used on larger motors (above about 200 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), thermostats or RTD’s, contactor status, etc.

Microprocessor‐Based Control &  Protection Devices The protection functions available in a typical motor management device include over current with a selection of overload curves available, locked rotor, current unbalance or negative phase sequence, p q ,g ground fault,, under voltage, g , winding and bearing high temperature. These devices provide control of the motor contactors for various starting configurations, configurations such as star delta, autotransformer, part winding, and for two speed and reversing, etc.

End of this End of this Section

Section 9 Section 9 Transformer Protection Transformer Protection

Section 10   Transformer Protection

¾Differential protection ¾ ff l ¾Over current and ground fault protection ¾Gas pressure relays ¾Oil and winding temperature devices ¾Oil and winding temperature devices ¾Testing of Transformer Protection

Transformer Protection The various types of protection schemes for power system transformers include: Differential protection Over O e cu current e a and dg ground ou d fault au p protection o ec o Gas pressure relays Oil and winding temperature devices

Transformer Protection DIFFERENTIAL PROTECTION 

With Bus Differential protection we saw that we compared d the th currentt entering t i th bus, the b with ith that th t leaving the bus, in order to detect a fault. With Transformer Differential Protection we use the same principle.

f Transformer Protection However, we must make a few changes to adapt that principle for use on transformers: 1. The C.T. ratios on the transformer primary and secondary sides must be chosen to match t h the th transformer t f ratio. ti 2. 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. (This is not necessary with microprocessorbased relays, transformer winding configuration is programmed into the relay)

Transformer Protection 3. Some accommodation must be made for the transformer tap changer, which, of course changes the primary to secondary ratio of the transformer. 4. Some accommodation must also be made for the magnetizing inrush current which flows when the transformer is energized. This inrush current can be as high as ten times the full load current of then transformer, and flows into the transformer but not out. transformer, out

Transformer Protection

Transformer Protection The transformer differential relay rela is designed especially to accommodate this mismatch in the primary and secondary C.T. C T currents. 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, up and the through current flows through the restraint or bias coils and tends to make the relay restrain.

Transformer Protection

Transformer Protection If there is an out of zone fault when the tap changer is away from the neutral tap, then the through C.T. C T secondary current flowing through the restraint coils will overcome the tendencyy for the relayy to operate p byy the spill p current flowing through the operate coil. The differential relay will not operate for this out-of zone fault condition.

Transformer Protection

Transformer Protection For the “In-Zone” fault shown the current th through h the th ‘operate’ ‘ t ’ coilil is i very high hi h and d the th net restraining current is low. Th differential The diff ti l relay l will ill operate t for f this thi “In“I Zone” fault.

Transformer Protection When a transformer is energized, energized there is a magnetizing inrush current, which can be as high as ten times the full load current of the transformer. This high inrush current Last s 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). transformer)

Transformer Protection Microprocessor-based transformer differential relays y the restraint for magnetizing g g inrush is achieved in a different way. The shape of the waveform is analyzed by the microprocessor to determine if magnetizing inrush current is present.

Transformer Protection

Restraint Characteristic

Over current and Ground Fault Protection Over current 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. rela s For transformers of around aro nd 10 MVA and below, primary fuses are normally used.

Over current and Ground Fault Protection

It is desirable to set the relays y or fuses as sensitive as possible. However, they must not operate for any tolerable condition such as magnetizing ti i i inrush, h cold ld load l d pick-up, i k or any emergency operating condition. Over current relays and/or fuses must protect the transformer against damage from ‘through’ g should be coordinated with faults. The settings the transformer damage curves, and with the relay settings on the adjacent elements.

Over current and Ground Fault Protection

Where transformers are operated in parallel it is not possible to adequately apply over current protection for each transformer, transformer and also provide the necessary selectivity. The over current 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.

d d l i Over current and Ground Fault Protection If over current is used as backup protection on transformers operating in parallel, emergency overload conditions must be taken into account when determining the minimum pickup setting. 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 diti f for about b t 2 to t 3 hours, h providing idi a winding temperature of 105ºC is not exceeded.

Over current and Ground Fault Protection 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 i di b become overheated. h t d An over current pickup setting of twice f ll l d is full-load i often ft used d to t allow ll f this for thi emergency situation.

R i dE h f l ( G df l) Restricted Earth‐fault (or Ground‐fault)  Protection Ground-fault protection for each of the windings i di off a transformer t f can be b 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.

l 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 p problems. This is known as GAS ACCUMULATION. A flashover or 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.

Gas Relays Buchholz Relay 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, 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, relay towards the conservator tank.

Gas Relays

Oil and Winding Temperature  Devices Transformers are usually equipped with devices to monitor the temperature of the oil and the windings. The first device monitors oil t temperature, t and d is i connected t d via i a capillary ill tube to a bulb fitted into a pocket surrounded with oil. oil The winding temperature device is similar, except that there is a heater in the pocket with the bulb. p

Oil and Winding Temperature  Devices For transformers equipped with cooling fans and pumps, the temperature devices are used to automatically start and stop the forced cooling. li Th are also They l equipped i d to t initiate i iti t an alarm and a trip for very high transformer temperatures. temperatures

Oil and Winding Temperature Devices Typical settings are: 75ºC 75 C – Start cooling 65ºC – Stop cooling 90ºC – High Temperature Alarm 105ºC- Trip Transformer L.V. Breaker

Microprocessor Based Transformer  Protection/Management Relays Most protective relay manufacturers now have modern microprocessor-based transformer protection/management relays on the market. market These microprocessor -based relays typically have many different protection, control and monitoring functions, such as: Differential protection with harmonic restraint O Over currentt protection t ti f each for h winding i di off the th transformer. Restricted ground fault protection

Microprocessor‐Based Transformer Microprocessor Based Transformer  Protection/Management Relays Over excitation protection, Volts per Hertz & Fifth Harmonic O Over-frequency, f Under-frequency, f and rate off frequency f decay Event recording g Waveform capture Metering T position Tap iti Harmonic analysis Programmable logic

Transformer Protection – Overview

End of this End of this Section

SSection 10 ti 10 Generator Protection

Section 11     Generator Protection ‰ Generator Internal Faults:‐ 1. Phase‐to‐Phase faults on the stator winding 2 Phase to ground 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) ‰ External Power system faults and abnormal operating conditions:‐ 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 U d 3. Under and over frequency d f 4. Loss of excitation (Loss of field) 5. Over‐excitation 6. Reverse power (loss of prime mover) (l f ) 7. Non‐synchronized connection of generator

Generator Protection Generators are the most expensive pieces of equipment i t on our power systems. t R li bl Reliable generator protection schemes are therefore required q to minimize damage g and repair p 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 categorized into two groups: a. Internal faults within the generator zone. b. External power system faults and/or abnormal operating conditions

Generator Protection A. GENERATOR INTERNAL FAULTS 1 Phase-to-Phase faults on the stator winding 1. 2. Phase-to-ground faults on the stator winding 3. INTER-TURN faults on the stator winding 4 G 4. Ground d ffaults lt in i th the rotor t (or ( field fi ld winding) i di )

Generator Protection B. EXTERNAL POWER SYSTEM FAULTS

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

Generator Protection All medium to large generators, i.e. 20 MVA t to 1000 MVA, MVA will ill be b equipped i d with ith protection schemes to detect most, if not all, of tthe o e abo above e co conditions. dto s For small hydraulic generators it may not be cost effective to provide the same number off protection t ti schemes h as larger l units. it Also, many smaller hydraulic generators are better capable of withstanding some of the above adverse conditions, without damage, than the larger units.

Generator Protection

Generator Protection 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 thi arrangementt the this th generator t is i synchronized h i d to t 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. system. above

Generator Protection The generator protection zone one in the above abo e example includes the generator, the main output transformer, the unit station service transformer, and the bus The following protective relaying schemes will normally be applied to most medi m to large size medium si e generators: generators a. Differential Protection (87) To detect phase to phase faults b. Stator Ground Fault Protection (64 or 59N) c. Rotor R t G Ground d Fault F lt Protection P t ti (64)

Generator Protection d. Phase Unbalance Protection (46) ( ) To detect negative phase sequence currents which cause overheating of the rotor work up to the 230 kV circuit i it b breakers. k e. Inter turn Protection of the Stator Winding (60) f Under-Frequency Protection (81) f. g. Out of Step Protection (21-78) To detect g generator p pole slipping pp g due to p power system y disturbances h. Loss of Excitation Protection (40)

Generator Protection i. Over excitation Protection (59) To prevent core saturation due to over excitation during run up and shutdown j. Reverse Power Protection (32) To detect loss of prime mover which causes the machine to motor k Phase k. Ph S Supplementary l t St Startt P Protection t ti (50) To detect a fault condition as the generator is being run up p to synchronous y speed p l. Phase Back-up Protection (21B) To detect un cleared generator, transformer, and bus faults

Generator Protection 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.

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. Thi has This h th effect the ff t off limiting li iti th ground the d fault f lt current to as little as 5 amps. Consequently, ground faults within the g g generator zone will not be detected by the differential protection.

Differential Protection (87) Generator differential protection uses the same principles as those d described ib d earlier li ffor Bus B Diff Differential ti l protection t ti and d Transformer T f Differential protection.

Differential Protection (87) Current transformers are located at each end of the stator t t winding i di as shown h i the in th diagrams. di Th C.T. The CT ratios are the same, and under healthy conditions the C.T. current circulates, with no spill p current flowing g in the differential relay operating coil. With this arrangement of generator differential protection there is no magnetizing inrush current problem. Also, because the currents at each end of the stator windings are exactly equal, equal and the C.T. C T ratios are the same, then there is no need for the differential protection relay to have restraint or biasing coils.

Differential Protection (87)

ff l ( ) Differential Protection (87) Since there is not normally a circuit breaker between the generator and it’s output protection transformer,, a set of differential p is usually provided, especially on large generators, to include the generator and the transformer, transformer as shown above. above This arrangement has three sets of differential protection, covering different parts of the generator and transformer zone. zone It provides duplication such that any fault will be protections. detected byy two of the three p

Differential Protection (87)

d l ( ) Stator Ground Fault Protection (64 or 59n) (Often called Neutral Overvoltage Protection) The stator winding of a typical generator is grounded at its star p g point through g 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-to ground faults on the stator winding, to about 5 amps. A Voltage Relay is connected across the resistor to detect stator ground faults.

Stator Ground Fault Protection (64 or 59n) 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 g is developed p across the grounding transformer secondary terminals, and the voltage relay operates. This condition will usually cause the generator to trip, trip but if the ground fault current is limited to a very low value, such as 5 amps, then it may just annunciate an alarm condition.

Stator Ground Fault Protection (64 or 59n) 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 90% of the winding. winding

Differential Protection (87)

Stator Ground Fault Protection (64 or 59n) To detect faults on the last 10% of the winding g some other type of protection must be used. One type yp of p 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. V T If a stator ground fault occurs, 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 f ground for d faults f lt att the th stator t t terminals. t i l

d l ( ) 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, fault however, however raises the potential of the whole field and exciter system, and the extra voltages induced by opening the field breaker, breaker or the main generator breaker, 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 g unbalance.

Rotor Ground Fault Protection (64) 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.

Rotor Ground Fault Protection (64)

d l i ( ) Rotor Ground Fault Protection (64) One method of detecting rotor ground faults utilizes a high resistance connected across the rotor circuit, the h centre point i off which hi h is i connected d to ground d 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 d fault f lt conditions. diti Thi blind This bli d spott can be b tested t t d 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. side

Rotor Ground Fault Protection (64) 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.

Rotor Ground Fault Protection (64)

Rotor Ground Fault Protection (64) 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 d t ti detecting relay, l i series in i with ith a currentt limiting resistor. A fault on any part of the field system will pass a current of sufficient magnitude through the relay to cause operation.

Rotor Ground Fault Protection (64)

Rotor Ground Fault Protection (64) The above sketch shows the arrangement of a brushless exciter. With this arrangement there is no external connection to the rotor field winding g and diodes. It is therefore difficult to apply rotor ground fault protection to brushless exciters. O One method th d off applying l i rotor t ground d fault f lt protection uses optical coupling to the rotor.

Phase Unbalance or Negative Phase Sequence Protection  (46)

The function of g generator negative g phase sequence p q protection is to protect the machine against the overheating effects, which occur as a result of unbalance of the stator phase currents. Such unbalance b l i usually is ll due d to t faults, f lt or ‘open-circuits’ ‘ i it ’ on the external high voltage transmission system. This causes a negative phase sequence component in the stator currents, 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, currents which are at twice the system frequency, will produce local overheating at the periphery of the rotor.

Phase Unbalance or Negative Phase Sequence Protection (46) The ability of the machine to withstand this heating p to a large g degree g on it’s effect will depend 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. t i.e. i e The square of the negative phase sequence current multiplied by the time.

Ph U b l N i Ph S P i (46) Phase Unbalance or Negative Phase Sequence Protection (46)

Phase Unbalance or Negative Phase Sequence Protection (46) 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 connected. 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.

Phase Unbalance or Negative Phase Sequence Protection (46)

With today’s modern microprocessorbased multifunction 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.

Inter turn Protection (60)

Inter turn Protection (60) Split Phase Protection can be used to detect Split-Phase 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 g are p passed through g a C.T. in opposite directions as shown above. A sensitive over current relay is connected to the C.T. secondary With no fault on the stator winding, secondary. winding the current in the two halves of the winding will be equal, and no current will flow in the relay.

Inter turn Protection (60) 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. generator

Inter turn Protection (60)

Inter turn Protection (60) On larger generators where it is not practical to use split phase protection, 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 V T’ss. 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. V T phase-to- phase voltage. voltage Under normal healthy conditions the ‘open corner delta’ voltage is zero. If a fault develops there will be an ‘open corner delta delta’ voltage, voltage and the two voltages applied to the relay will produce a torque to operate the relay.

Under frequency and Over frequency  Protection (81)

This protection detects system disturbances, rather than generator faults. 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, over frequency, with possible overvoltage results because of the reduced load demand. demand Operation in this mode will not produce overheating unless rated power and approximately 105% rated voltage is e ceeded The generator controls should exceeded. sho ld be promptly adjusted to match the generator output to the load demand.

Under frequency and Over frequency Protection (81) With insufficient generation for the connected load, under d frequency f results, lt with ith a heavy h l d demand. load d d 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 sho ld ideally ideall adjust adj st the load to match the connected generation before a total power system collapse occurs.

Under frequency and Over frequency Protection (81) generator problems, Under As well as these g frequency and over frequency conditions can cause serious damage to steam turbines. Turbine bl d blades are designed d i d and d tuned t d for f continuous ti operation at normal synchronous speed. At other speeds serious vibrations, vibrations and possibly resonance, can occur and result in blade damage, g , p particularly y on the longer g blades at the low pressure end of the turbine.

Under frequency and Over frequency Protection (81)

Under frequency 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, d or instantaneously i t t l if the th frequency drops to 56 Hz. For a 50 Hz generator typical settings are 47.5 47 5 Hz for 10 seconds, or instantly at 46 Hz.

Under frequency and Over frequency Protection (81) Ideally, automatic load shedding from ‘Frequency Trend Relays’, ‘Rate-of-Change of Frequency’, or Under frequency relays on the Frequency distribution system or transmission system will coordinate with the generator under-frequency protection to match the connected load to the available generation, before generators trip. Under-frequencyy protection trips onlyy the H.V. circuit breaker, and allows the unit to keep running, and available for service when the transmission system is restored. restored

Out-of-Step Protection (21-78) Out-of-Step protection detects a condition caused by power system disturbances, rather than generator faults. An un cleared, 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.

Out-of-Step Protection (21-78) Such S h a condition di i i undesirable is d i bl because b 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 itit’s s first pole, and causes the generator breakers to trip. The turbine is not tripped, enabling the machine hi t be to b re-synchronized h i d after ft th the system disturbance is cleared

Out-of-Step Protection (21-78) This protection can be considered complementary to ‘Loss Loss of Excitation Excitation’ protection. The ‘out-of-step’ condition occurs with the generator at full field, field and the loss of synchronism due to under excitation occurs when the generator has no field.

Out-of-Step Protection (21-78)

Out-of-Step p Protection (21-78) ( )

Out-of Step protection uses three impedance measuring relays. These relays are supplied by the generator C.T.’s C T ’s and V.T.’s, V T ’s and measure the generator load impedance. y detect a p power swing g condition These relays if the three relays operate in the correct sequence, and will initiate tripping of the H V circuit breakers. H.V. 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. p

Out-of-Step Protection (21-78)

f ( ) 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, t above b synchronous h speed. d 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 stable, and the machine will continue to put out MW.

f ( ) Loss of Excitation Protection (40) 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 Mho relay, and is supplied from the generator C.T.’s and V.T’s.

Loss of Excitation Protection (40) 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. second

Loss of Excitation Protection (40)

Over excitation Protection (59) The purpose of over-excitation protection is to prevent the core of the main output transformer from being saturated during generator start-up or shutdown. h td O Over excitation it ti can be b explained l i d by the following expression:

Over excitation Protection (59) 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. increased If the excitation is increased too rapidly, then this over excitation condition must be detected, and the field breaker tripped. Over excitation it ti protection t ti schemes h use Volts V lt per Hertz relays. These relays have a linear characteristic, and will operate if V, the Voltage, divided by the frequency exceeds the set value.

Over excitation Protection (59)

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 coolant, 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.

Reverse Power Protection (32) IIn such h cases the h Reverse R P Power protection i will annunciate an alarm condition, to allow corrective action to be taken without tripping the generator. Reverse Power protection uses a power di ti directional l relay l t monitor to it th generator the t load. The relay is supplied from the generator C.T.’s and V.T’s as shown,, and g will operate when any negative power flow is detected.

Reverse Power Protection (32)

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 p prevent this,, a scheme of protection is used that switches into service low-set over current relays ONLY if the frequency is below 52 Hz on 60 Hz power systems, and 42 Hz on 50 H systems. Hz t Wh the When th generator t is i ready d to t pick i k up load the Over current trip must, of course, be disabled. This is accomplished by a contact of an under frequency relay which opens when the under-frequency generator approaches synchronous speed.

Supplementary Start Protection (50)

Phase Back‐up Protection (21B) Back-up protection is provided to detect un cleared faults in the generator, generator the transformer, transformer or the H.V. bus work. A typical phase back-up protection scheme, shown above, uses three impedance relays, relays supplied by the generator C.T. C T ’ss 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, circular or MHO, MHO charactecharacte ristic of, say, 7 ohms radius, and tripping occurs if the minimum load impedance falls within the circle. circle

Generator Over current Protection Voltage Controlled & Voltage Restrained

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

Generator Over current Protection Voltage Controlled & Voltage Restrained

The over current protection C.T.s 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 phase-to-phase to phase faults may be undetected. There is difficulty in applying inverse time over current protection to generators because a phase-to-phase phase to phase fault near the terminals of the generator will cause the terminal voltage to decrease.

Generator Short‐Circuit Current In the event of a short short-circuit 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 value, shot circuit current, as shown in the typical generator decrement curve. curve

Generator Short‐Circuit Current To a close approximation the generator short‐ circuit current can be divided into three components: ¾S b ¾Subtransient Component i C ¾Transient Component ¾Continuous Component

Generator Short‐Circuit Current This p progression g of the short-circuit current is determined by the electromagnetic process that occurs within the generator and d the th resulting lti effect ff t on the th voltage. lt In practice, however, it is usual for the representation t ti and d calculation l l ti off shorth t circuit characteristics to be based on a constant voltage, voltage and on an assumption that the decay of fault current is due to an increase in the reactance of the generator. generator

Generator Short‐Circuit Current

I the th eventt off a short-circuit h t i it close l t the th In to 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, To a close approximation the generator short circuit current can be divided into three short-circuit components: Subtransient Component Transient Component Continuous Component p

Generator Short‐Circuit Current Corresponding to the above postulated current components, components the associated reactances are: S bt Subtransient i t Reactance R t X”d. X”d Transient Reactance X’d. Synchronous Reactance Xd.

Generator Short‐Circuit Current The Subtransient Reactance influences the fault current for only about the first 0.2 seconds. For a typical yp value of X”d of 0.11 p.u. the sub transient symmetrical short circuit current is:

Generator Short‐Circuit Current The Transient Reactance influences the fault current for about the first 1 second. For a typical value of X X’d d of 0.19 0 19 p.u. p u the transient symmetrical short-circuit current is:

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

Generator Short‐Circuit Current

G t P t ti S t Generator Protection System

End of this End of this Section

Section 11 High‐Voltage Transmission Line Protection

Section 13  High‐Voltage Transmission Line Protection

• Interconnected Systems with Two‐Way Flow of  Fault Current. • Distance or Impedance Protection Schemes. Distance or Impedance Protection Schemes. • Phase Comparison Protection Schemes. • Line Differential Protection. Li Diff ti l P t ti • Communication Channel Requirements  Between Terminals.

Interconnected Systems with Two Way Flow of Fault Interconnected Systems with Two‐Way Flow of Fault  Current Time-graded over current protection cannot be successfully f applied to high voltage transmission lines because there are usually many interconnected sources of fault current. 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 di i i t between discriminate b t faults f lt on the th protected t t d line li and faults on adjacent lines, buses, transformers, etc.

Interconnected Systems with Two‐Way Flow  of Fault Current The protection system must be able to clear  p y faults very quickly, (i.e. in less than 0.1  ) p y g seconds) before the power system goes  unstable. The protection system must be dependable The protection system must be dependable,  and must be capable of clearing faults when  any single piece of equipment has failed any single piece of equipment has failed.

Interconnected Systems with Two‐Way Flow of  Fault Current Protection schemes on high-voltage transmission lines are usually duplicated to ensure that th t no single i l componentt failure f il will ill 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. batteries The high voltage circuit breakers have duplicate trip coils, and breaker failure protection is applied. applied

Distance or Impedance Protection 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, current and the line voltage falls. The relay therefore measures line impedance Z.

The relay operates if the ratio setting g of the relay y in OHMS.

falls below the

Distance or Impedance Protection 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. C T /V T Ratio Ratio. Secondary OHMS = 3 x 500 / 2000 = 0.75 OHMS

Distance or Impedance Protection 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 ’ are located) C.T.’s l t d) to t the th fault f lt will ill always l b less be l than 3 Primary OHMS, or 0.75 Secondary OHMS and the relay will operate. OHMS, operate For any fault beyond the end of the transmission line, the impedance p will be g greater than 3 Primaryy OHMS, and therefore the relay will not operate.

Distance or Impedance Protection The relay 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. line

Di I d P i h Distance or Impedance Protection scheme Almost all modern Distance or Impedance protection t ti schemes h use relays l with ith MHO directional impedance characteristics as shown above. 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 i value l off Z for f operation ti i is represented by the diameter of the circle which is shown at 75 75º to the R axis. axis

Distance or Impedance Protection 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. conditions. ie Phase‐to‐Phase Faults     

A to B  B to C C to A C to A 

Phase‐to‐Ground Faults

A to Grnd B to Grnd C to Grnd C to Grnd

Distance or Impedance Protection Other fault conditions, such as two phases-toground, or three-phase faults can be considered as combinations of these basic fault conditions. It is i nott practical ti l to t sett an impedance i d relay l t to measure exactly the impedance of the line up to the breaker at the remote end. end This is because of errors in such things as C.T.’s, V.T.’s, Relays, calculation of line impedance, p , etc.

Distance or Impedance Protection Schemes 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% off the th line li impedance, i d and d is i called ll d ZONE 1. We must be certain that the ZONE 1 reach does not extend beyond the remote end of the line. line

Distance or Impedance Protection  Schemes A second relay, or relay element, is used to cover the remainder of the line. 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 off the h line. li

Distance or Impedance Protection Schemes The complete scheme therefore comprises the following  relays, or relay elements, to detect all of the various line fault  conditions: 

Distance or Impedance Protection Schemes The ZONE 1 relays cause the local circuit p with no intentional time delay. y breaker to trip The ZONE 2 relays cause tripping after a time delay of typically 0.4 seconds.

Distance or Impedance Protection Schemes 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 0 4 seconds. seconds

Distance or Impedance Protection Schemes If station B has similar relays to station A, faults F1 and F2 will both be detected by the ZONE 1 relays at B. The relays will therefore trip the station B breaker without intentional time delay for both faults. With this scheme of protection we can see that we do not get high-speed clearance for all faults. i.e. Faults within 25% of either terminal are cleared at the far terminal after a time delay.

Distance or Impedance Protection Schemes 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 p g 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, by-passes delay and makes ONE 2 tripping instantaneous.

Line Differential Protection The line differential relays at each end of the transmission line compare data that is exchanged g via a fiber-optic p link between the two terminals. Many utilities have a fiber-optic cable embedded in the grounded shielding conductor off H.V. H V transmission t i i li lines. Th relays The l compare the magnitude and phase angle of the current entering the line at one end, end with the current leaving the line at the other end.

Line Differential Protection If the two are not equal, within a reasonable tolerance, then a fault condition is detected, and the line is tripped. pp The relayy also has various other protection elements, such as instantaneous over current, timed over current, phase h and d ground d directional di ti l over current, t and d 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.

Communication Channel Requirements Between Terminals

In order to achieve high high-speed speed tripping for faults on transmission lines, reliable communication channels are required between the protective relaying equipment at each terminal of the line.

Communication Channel Requirements Between Terminals 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. schemes Communication channel for Phase-Comparison p protection. Direct Tripping channel between terminals of the line. Communication channel for Pilot-Wire protection

L90 Line Differential System

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