INDEX

Sl. no.

Topic Page No.

1 Generator Protection 2 – 21

2 Transformer Protection 22 – 30

3 Bus Bar Protection 31 – 41

4 Distance Protection 42 – 80

5 Distance Protection Schemes 81 – 97

6 Generation Technologies 98 – 123

7 Frequency Control 124 – 151

8 Reactive Power management 152 – 227

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TABLE OF CONTENTS

No. Topic

1 Generator Protection

2 Generator Phase faults

3 Generator Phase to Ground Faults

4 Generator Back-up Protection

5 Generator Protection against System Disturbance

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GENERATOR PROTECTION

Synopsis:

The objective of this paper is to review the types of faults that can occur on generators and discuss the various protection schemes that are used on both small and large units. This helps in under standing overall concepts and apply them to day-to-day work activities. The trends in Generator protection are discussed.

1.0 The Generator

Generators are built in an extremely wide range of sizes, depending very much upon the application and the particular type of prime mover.

Typical ratings are as follows:

Diesel generator - 500 KVA - 5MVAGas turbine generator - 10 - 150MVAIndustrial steam turbine generator - 15 - 50 MVAUtility steam turbine generator - 100 - 500MVAUtility hydro turbine generator - 50 - 300MVA

When considering protection of the generator, the prime mover must always be included. For example, in response to a winding failure in the generator, it would not be sufficient just to trip out the main breaker and disconnect the unit from the electrical system. We would also need to trip the stop valves and shut down the prime mover, so as to prevent further damage.

Similarly, if a problem occurs within the prime mover, which necessitates tripping the unit, inter trips must be provided to trip generator breaker as well. When the generator is tripped from the system, its excitation must also be de-energized by tripping the field breaker or equivalent.

Small generators are generally connected to the system through a circuit breaker directly to a common bus as shown in Fig. A-1. Several other generators may also be connected to the same bus. The bus feeds the power system and also supplies the station transformer which provides power for the station auxiliaries. A fault occurring internally on any particular generator should be detected by its protection system and this will cause its specific breaker to open and its own excitation system de-energize. The remaining generators should remain on line.

Fig A1: Connecting Small Generators to the System:

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Fig A2: Large Generator Connected to System

On large generators the terminal voltage, which may be, say, 13.8 to25 KV, is stepped-up by its own unit transformer before feeding into the bus (Fig. A-2). The generator breaker is located after unit transformer.

The unit auxiliaries are fed from the unit station service transformer, which is also connected directly to the generator terminals. The unit auxiliary bus has an alternative feed from general station service transformer, as the unit auxiliaries to be energized during start-up.

In the case of an internal fault developing inside the generator, the main circuit breaker and also the unit auxiliary circuit breaker must be opened so as to completely isolate the generator. It is normal to provide a throw-over arrangement, so that the general service breaker will be closed automatically to continue feed the auxiliaries.

The three separate phase windings of the generator are located around the stator to provide the correct angular phase displacement.

Both ends of each phase winding are brought to a common terminal in order that the phase windings can be connected in either delta or wye, according to system voltage requirements. Fig. A3 shows the wye connection, and also the common diagrammatic representation.

Fig A3: Generator Windings connected in wye

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Fig A4: Generator windings connected in Delta

Similarly, Fig. A-4 shows the delta connection. Obviously, with the delta arrangement, there can be no common neutral and, therefore, no connection to ground.

Certain defects can arise on the generator which are mechanical in nature such as:

1) Bearing problems;2) Lube oil problems;3) Vibration;4) Hydrogen cooling system problems;5) High winding temperature (perhaps due to partial insulation failure)6) Prime mover failures.

Normally, all of these items are continuously monitored by appropriate measuring devices, and attention is drawn to abnormal conditions by alarms and Annunciators. In extreme cases, tripping may be initiated.

Most internal electrical faults in generators are caused by failure of the insulation in the stator winding. This results in a phase-phase short circuit or phase-to-ground fault. An arc will rapidly develop with consequent heavy damage to the stator windings the problem area and also to the stator laminations. It is essential that the generator be isolated from the system immediately and the prime mover stopped as soon as possible.

Another type of internal fault is the ground fault on the rotor, that is, the field windings. The rotor operates at a relatively low DC voltage -- about 500 to 600 Volts -- compared with the stator winding voltage of, say, 15 KV or more. Moreover, the rotor winding is ungrounded, so there is no path for flow of ground fault current. For this reason a ground fault on the rotor will not call immediate tripping, but rather require the scheduling of a convenient outage for inspection of the generator.

Yet another internal fault could be the failure of excitation altogether. This could provide a serious upset to the power system as it attempts to supply the excitation current through the stator .windings. This subject is discussed in

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more detail in later segments.

Other generator problems may be due to system conditions such as:

a) Excessive stator current (i.e. overload). This results in overheating of the stator windings.

b) Over voltage, which may damage insulation.c) Under frequency, which may damage the turbine blades, due to

vibration.

d) Motoring of the generator due to loss of the prime mover. This could result in overheating and consequent damage of the low pressure turbine blades.

e) Unbalanced currents in the generator stator due to serious system unbalance. This will cause overheating of the generator rotor, due to negative sequence components.

f) Loss of synchronism. If the unit tails out of step with the system, this could cause the rotor to slip a pole.

g) Closing the generator breaker with the generator out of phase with the system. This could cause serious mechanical damage to the generator windings and the turbine.

2.0 Generator Phase Faults

For protection against phase-to-phase faults, differential schemes are normally installed.

In small generators, one simple way of achieving this is by installing Toroidal CT’s at the terminals as shown in Fig. B-1.

Fig B-1: Use of Toroidal CTs

On large generators, it is physically impossible to pass both conductors through the window in the Toroidal CT. Therefore, separate CT’s are installed at each end of the winding. CT’ s are normally installed in all six terminal bushings.

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Fig B-2: Wye Connected Generator – Differential Protection

Fig B-2 shows a typical differential protection arrangement for wye connected generator. Note the polarity of the CT connections. This is vital to ensure the correct direction of current flow in the CT secondaries. When there is no fault, and thus no out of balance, no current flows through the operating coils. On the other hand, if a fault occurs, say, between windings A and B, then an out of balance will occur and cause relays A and B to operate.

If generator is delta connected, then the differential CT’s are connected as shown in Fig. B-3. Note that the outboard CT’s are connected in wye. This is important to the operation of the relay. When no fault exists, the sum of the secondary currents IA,IB and IC is equal to zero, and therefore no current flows in the Neutral . If a fault does occur in the generator, phase currents will be out of balance and current will flow in the neutral, thus operating the relay.

On large generators a split winding is sometimes employed as shown in fig. B-4. Differential protection is provided across the generator in the conventional way, but this will be unable to detect insulation failure between turns in the same phase.

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Fig B-3: Delta Connected Generator – Differential Protection

Fig B-4: Differential Protection for a Generator with Split Windings

As shown, additional differential protection may be installed if additional

CT’s are available in one of the halves of each phase winding. Operation of this relay may be connected to provide an alarm to the operator, instead of tripping the unit. This then provides time to arrange an outage to inspect the

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unit. Fig. B-5 shows the single line diagram for differential generator protection.

Fig. B-5 The single line diagram for differential generator protection.

The generator terminals are solidly connected to the primary of the unit transformer, so the generator must also be tripped in the event of a transformer fault. Often separate differential protection is installed across the transformer (87 T in this case). Also separate differential protection (87 ST) is connected across the unit service transformer.

In addition, unit differential protection is provided by linking CT’s across all three items of equipment. Operation of any one of these differential circuits will trip the main breaker, the auxiliary breaker, the field breaker, and the prime mover.

For a small generator which is connected directly to the bus, the arrangement is shown in Fig. B-6. The 87G differential relay is connected across the generator and includes the generator breaker. The outboard CT’s are usually located in the breaker bushings.

Fig B-6: Small Generator Differential Protection

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3.0 Generator Phase To Ground Faults

Large generators are normally grounded through a high impedance in order to limit the value of fault current to under 10 amps. This limits the amount of internal damage that can be caused in the generator by the flow of fault current. As shown in Fig. C-1, ground fault current will flow in the generator neutral, and a CT may be connected into the neutral to measure this flow of current. The CT secondary will be connected to a time over current ground relay(51G).

Figure C1 : Generator Ground Fault Protection

Fig-C-2 shows the more commonly used protection, an inverse time over voltage relay (59G). It is set to pickup at about 10 volts. In this arrangement, instead of a resistance, the impedance in the neutral is provided by a transformer, the secondary of which is connected to the 59G relay. A grounding resistor is connected in the secondary circuit. It is sized so as to limit the magnitude of fault current flowing through the neutral to 10 amps or less.

The 59G relay will operate for ground faults occurring in1. The generator;2. The primary of the unit step-up transformer;3. The primary of the unit station service transformer; and4. The interconnections.

The time delay of the 59G relay must be set to co-ordinate with other protection relays on the system.

A CT is sometimes installed in the secondary circuit, to operate an instantaneous over current relay (50G) and provide back-up for over voltage relay.

Third harmonic components are present in the generators output due to the generator’s construction and due to systems loads. The ground fault relays must be isolated from third harmonic component so as to prevent inadvertent tripping. This is usually achieved by a tuned circuit in the relay itself which blocks these components.

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In contrast to this, we may often encounter, connected in parallel with the 59G, an under voltage relay (27G) which only responds to third harmonic currents and voltage. Under normal operation, where third harmonic voltage is present, this relay does not operate (remember, it is an under voltage relay). However, if a ground fault occurs in the generator windings close to the neutral, then these third harmonic components will be short circuited and the corresponding third harmonic voltage will be considerably reduced, causing operation of the relay. Another arrangement uses a 59D relay to measure the distribution of third harmonics at the terminal.

The addition of the third harmonic relays helps to protect the first 10 - 15 % of the winding generator. This is necessary, because the effect of the impedance in the generator neutral may leave about 10 per cent of the winding unprotected.

Figure C2: Generator Ground Fault Protection

Fig-C3 shows several generators connected to the same bus, with one single common grounding connection connected on the bus. If any particular generator is out of service, or if it is tripped, there will still be a ground for the remaining generators

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Figure C3: Generators with common GroundIn order to provide selectivity, a ground differential relay (87GD) is

installed on each generator. The (87GD) has two operating coils: one feeds from the differential CT’s of its particular generator and the other feeds from the common neutral CT.

The differential component acts as a permissive for the neutral component. It will block tripping of the generator when the fault is external, but will assist tripping for internal faults.

4.0 Generator Back-Up Protection

Fig.D-1 shows a typical back—up protection scheme for a small generator. The 87G differential relay is connected across the generator, and ground protection is provided by the ground differential (87GD). Back-up protection is provided by a negative sequence relay (46), a voltage restraint over current relay (51V), a reverse power relay (32), a loss of field relay (40) and a ground over current relay (51G).

With phase-to-phase fault conditions, the system imbalance creates negative sequence voltage and current. If the primary protection fails to operate, the negative sequence relay will register the continued presence of negative sequence components and trip the generator accordingly. Hence it acts as a back up to the primary protection.

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Figure D1: Small Generator Backup Protection

But the negative sequence relay also has a primary function, which is to prevent overheating of the generator rotor in the event of prolonged out-of-balance operation. The generator designer specifies the negative sequence limit for each particular generator, as shown in Fig. D-2. The limit is expressed as:

K=I 2 2 t , where I2 = negative sequence current and t = time in sec.

Figure D2: Generator Negative Sequence Current Limit

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A lower negative phase sequence current can be tolerated for a much longer time period. On large modern generators the value “K” is between 10 and 20.

The 51V is a time over-current relay with voltage restraint (or voltage control) that operates as a back-up for the differential relay in the case of an internal fault in the generator. In order to make this relay selective, we must take advantage of fact that, when an internal fault occurs in the generator, the terminal voltage falls.

When voltage is normal on the system, the voltage restraint element prevents operation of the time over current relay. Conversely, when the voltage falls, typically below 80 per cent of normal, then the voltage restraint is lifted and the relay will operate in case of over current. Sustained three phase to ground fault current on the generator is actually less than the maximum load current due to the high value of generator synchronous reactance and the high neutral earthing impedance. The current element of this relay will probably be set to a value, which is less than normal rated current, but, of course, operation will be blocked as long as the voltage is normal.

Another back-up relay typically installed on small generators is the reverse power relay (32). This relay will operate when power flows into the generator, attempting to drive it as a motor. This situation can cause serious overheating and damage to the turbine low-pressure blades.

Fig D-3 shows back-up protection for a large generator. For clarity, the primary protection is not shown. Included are: a negative sequence current relay (46), a loss of field relay (40), and a time over current relay with voltage restraint (51V). Quite often, the 51V relay is replaced by a distance relay (21), which is set to reach through the generator and the unit step-up transformer in to the system. As this is a back-up relay, a timer is included to allow co-ordination with the other relays.

Figure D3: Large Generator Backup Protection

A special problem that may occur with the large unit generator is flash over of one breaker pole. This can occur where the generator, through the breaker, is connected to a long high voltage line open

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at the far end, with resultant high capacitance and high voltage as shown in Fig. D-4. When the breaker is opened at no load, one phase may flashover and maintain capacitive current flow out of the Generator. Serious overheating could occur in the stator iron, due to the capacitive current, and also in the rotor due to the high negative sequence components.

The negative sequence current relay may not respond quickly enough to prevent damage. Usually a “breaker pole failure” relay (device 61) is installed (see Fig. D-3) where, the system configuration makes this type of failure possible. When the relay operates it de-energizes the excitation circuit of the generator.

Figure D4 : Breaker Failure

5.0 Generator Protection Against System Disturbances

As the generator is synchronized to the power system, it is responsive to disturbances, which occur on the system. As shown in Fig. E-1, certain protective devices are installed to protect against these conditions. One typical example is that of frequency. Large steam turbines are designed to operate within a very narrow range of speed i.e. between 49.5 And 50.5 Hertz.

“High” frequency can occur as a result of load rejection, perhaps as a consequence of tripping transmission lines or load feeders. However the turbine governor will normally control the turbine speed and maintain frequency close to normal. In case the governor loses control, the turbine is fitted with an over speed trip, which is set to operate at 110 per cent, say, 55 hertz.

“LOW” frequency can occur as a result of system overload. If the turbine generator operates below 49.5 Hertz, serious vibration and consequent damage may occur to the large, low pressure turbine blades. The turbine is permitted to operate at low frequency only for very short periods of time typically:

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48.5 - 49.5 Hz - 60 minutes accumulated

46 - 48.5 - 10 minutes accumulated

A frequency relay (81) is installed to alarm or trip.

In practice, in a large interconnected power system, the frequency rarely falls outside normal limits. However, such an extreme situation can occur, if the power system becomes disconnected into separate areas or islands, so that each generator or group of generators is supplying its own block of load. In some areas we will have too much generation available, hence the frequency will initially rise. In other areas there will be insufficient generation and if load shedding is not rapidly initiated, the generator will become overloaded. The consequences will be:

1) a fall in frequency;2) a fall in voltage;3) a rise in stator current.

The voltage regulator will increase excitation on the generator in order to maintain line voltage, and this may lead to overheating in the rotor. To protect the rotor, over current protection is sometimes installed in the excitation circuit. This relay is set to alarm the operator.

The stator winding may be protected from overheating by the installation of an extremely inverse time over current relay (50/51) set to operate just before the stator winding short time thermal limit is reached. To prevent this relay operating during normal operation, a combined instantaneous element is usually connected as a permissive for the time over current contacts. This will prevent operation of the unit below 115 per cent of normal maximum rated current.

Fig E-1: Generator Protection Against System Disturbances

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During a cold start-up, several hours are required to bring a steam turbine generator unit up to speed. During this low speed period the generator voltage at this low frequency may be high enough to overexcite the main transformer primary. To avoid this problem, an over voltage relay (59F) may be installed to compare voltage and frequency; this is known as a volts-hertz relay. This relay will operate at about 115% of rated voltage when frequency normal. At low frequency the voltage trip point will be proportionally lower. This relay will also protect the stator insulation against over voltage at normal frequency.

Protection against closing the breaker out of phase is provided by connecting a directional time over current relay (67). When power flows into the generator, this relay will operate and trip.

Another type of relay, which is often installed, is a synchronizing relay. This type will not allow the breaker to close unless the phase angle is within a determined range (usually 10 degrees either side of synchronism).

Operation of the generator is subject to the following limits:

1) Minimum excitation;2) Overheating of the stator winding due to overload; and3) Overheating of the rotor winding due to excessive excitation current.

The limits of generator operation are indicated by the unit’s capability curve. A typical unit’s curve is shown in Fig. E-2. This shows the combination of megawatts and mega vars that can be produced by the generator at different power factors. Positive vars are vars supplied by the generator. Negative vars are fed into the generator from the power system.

We cannot maintain the same MVA at lower power factor, due to the temperature limit of the rotor winding. The capability of the generator is reduced at low lagging power factor.

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Fig E-2: Generator Capability Curve of a 180 MW unit

On the leading power factor side, very low excitation current may cause the rotor to fall out of step, due to loss of magnetic torque. This is the steady-state stability limit. There is yet another limit beyond this -- the overheating of stator iron --which results from excessive flow of capacitive currents. Usually the excitation system is fitted with a limiting device to prevent reduction of excitation to a dangerous level.

What would happen if the generator suffered a complete loss of field perhaps due to a defect in the excitation circuit? In this situation, remember, the generator is still connected to the power system, and is still delivering megawatts because it is still being driven by its prime mover. However, it will no longer supply vars. On the contrary, it will draw vars from the system in order to maintain excitation. The power factor will move to, say, 0.5 leading. So the generator will continue running and producing power as an induction generator. However, this will probably lead to low voltage at the generator terminals, and, more importantly, serious overheating will occur in the stator iron. If the field cannot be restored promptly, the unit should be shutdown. The loss of field relay (40) may be used for alarm or to initiate tripping of the unit.

Earlier loss of field relays worked by measuring current in the ‘Excitation circuit. When this fell below a pre-set level, the relay operated after a time delay.

Nowadays, loss of field is detected by measurement on the generator high voltage side. One method is to use a megavar meter set to operate when the imported (that is negative) megavars reach a high level, implying that the unit is operating as an induction generator.

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A more common method is to install an impedance relay. which compares the state of voltage and current. The impedance characteristic is shown in Fig. E-3.

Fig E-3: Loss of Field Impedance Relay Characteristic

Ground detection equipment, Fig. E—4, is usually installed to respond to a ground fault on the rotor or excitation system. As the excitation system is not normally connected to ground at any point, a ground fault does not require immediate tripping of the unit. However, it is advisable to arrange an outage of the unit for inspection as soon as possible. This will avoid damage which could happen it a second ground occurs.

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Fig E-4: Rotor Ground Fault DetectionDevice

Function

21 Distance relay. Backup for system and generator zone phase faults24 Volts/Hz protection for generator over-excitation 32 Reverse power relay. Anti-motoring protection40 Loss- of-field protection 46 Negative sequence unbalance current protection for the generator49 Stator Thermal protection51GN Time overcurrent ground relay51TN Backup for ground faults51V Voltage-controlled or voltage-restrained time overcurrent relay.

Backup for system and generator phase faults59 Over-voltage protection59GN Over-voltage relay. Stator ground fault protection for a generator60 Voltage balance relay. Detection of blown voltage transformer

fuses63 Transformer Fault Pressure Relay62B Breaker Failure timer64F Field ground fault protection71 Transformer oil or gas level78 Loss-of-synchronism protection81 Frequency relay. Both under-frequency and over-frequency

protection86 Hand-reset lockout auxiliary relay87G Differential relay. Primary phase-fault protection for the generator87N Stator ground fault differential protection87T Differential relay. Primary protection for the transformer87U Differential relay for overall generator and transformer protection

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Fig E-5: Protection Schemes for Typical Unit Generator Transformer

Conclusion: This paper discussed regarding the schemes and trends in Generator protection-o0o-

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TABLE OF CONTENTS

No. Topic

1 General

2 Types of Transformers

3 Protection Philosophy

4 Protection of Small Transformers

5 Protection of Medium Size Transformers

6 Protection of Large Size Transformers

7 Monitoring of E/F in Ungrounded Transformers

8 Power Management Concept

9 Grid Islanding and Load Shedding

10 Advantages of Numerical Relays in Transformer Protection

11 Conclusion

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TRANSFORMER PROTECTION

EXISTING PRACTICES AND NEW TRENDS

1.0 General

Transformers are the most important main equipment in any Power Transmission & Distribution network. The performance of the transformers depends upon how well they are maintained & protected against all possible fault conditions that can arise in the installation, in the network and the ambient environment.

The following sections describe the role of Protective relays in assuring the satisfactory performance of transformers both from fault clearance and maintenance point of views.

2.0 Types of Transformers

Transformers in a power system can be divided into three major categories:

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Small size transformers, less than 1 MVA size. These are used mostly at the distribution end with 11kV/415V ratings.

Medium size transformers ( 1 MVA to 10 MVA) : these are used in secondary sub-stations of state utilities and plant incomers. Voltage ratings on the primary side can vary from 220 kV to 33 kV. The secondary side voltages can vary from 33 kV to 3.3 kV.

Large size transformers (above 10MVA): These are used in primary substations of state utilities, incomers of large industries ( like cement plants, fertilizer plants etc). The primary voltages can be either 400 kV or 220 kV. Secondary voltages can vary from 110 kV to 33 kV. Many of these may have three windings.

Apart from the above one may come across special types of transformers like rectifier transformers, reactors etc.

Management of sub-stations with large transformers, from a remote location is becoming a major activity. This function is now being integrated into the protection system of transformers.

3.0 Protection Philosophy

The type and extent of protection for for transformers depends upon :

a) the size and importance of duty performedb) the location of the transformer in the power system

Transformers are two winding machines- hence they will need two sets of protections – one on the primary side and the other on the secondary side.

Transformers have to be protected both for external faults ( faults occurring outside the terminals of the transformer) as well as the Internal faults ( faults occurring within the transformer).

Normal over current + Earth fault relays are adequate for protection against external faults. Special relays like differential and REF relays are required for protection against internal faults. Sections 4,5 &6 explain the types of faults, method of protections for each fault, recommended types of relays etc.

Apart from fault conditions, which are severe abnormalities in electrical parameters, there are three major killers of transformers in the present day transmission system. These are :

a) Over load conditions : These produce excessive heat which causes rise in operation temperature. Every 10 degree rise in temperature ( beyond the withstand limit specified) results in 50% reduction in life of transformer insulation.

b) Single phasing conditions : There are increasing incidences of single phasing in transformers . The main reasons are poor maintenance of transmission lines and circuit breakers.

c) Unbalanced loads : Any unbalance in the three phase currents of a transformer will cause over heating , even if the currents are within rated values. Certain level of unbalance can be tolerated by transformer design – however we have to worry about unbalances more than 20%. Large unbalances can cause neutral shift , which may be harmful to end users. If excessive neutral shift takes place, there can be flashover in sub-station.

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These three conditions are on the rise in many substations – including some of the industrial plants. Necessary care has to be incorporated in the protection systems to handle these situations.

4.0 Protection of Small Transformers (Less than 1MVA)

The following figures show the SLD and the list of protections. Bare

minimum protections are envisaged – since economy of protections is the

major factor in deciding the extent of protection.

a) Low set Over Current Protection (51) : Used to protect the transformer from over currents in Py and Sy side. Pick levels are normally around 140% to 150%. Normal Inverse IDMT characteristics are followed for trip time.

b) Highset Over current Protection (50) : Used to protect from high level fault currents of the order of 300% and above. Always instantaneous trip.

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Primary Side :

50 Over Current (Instantaneous)50N Earth Fault (Instantaneous)51 Over Current ( IDMT)51N Earth Fault (IDMT)27 Under Voltage59 Over Voltage

Secondary Side :50 Over Current (Instantaneous)50N Earth Fault (Instantaneous)51 Over Current ( IDMT)51N Earth Fault (IDMT)27 Under Voltage59 Over Voltage64 Restricted Earth Fault

c) Under Voltage protection (27) : This is a bus level protection – pick up levels are normally 85% and below.

d) Over voltage protection (59) : This is a bus level protection – pick up levels are around 110%.

e) Restricted Earth fault protection (64) : Normally provide on the star connected side – for protection transformer from internal faults.

5.0 Protection of Medium Size Transformers (1 To 10 MVA)

Please refer the SLD and the list of protections, shown below:

Since the transformer is handling a higher power and it is in a key location like the incomer of a substation or an industry, following additional protections are advised.

a) Thermal Overload protection (49) : Let us consider a case where a normal over current relay with pick up level of 140% is used. It should be noted that the transformer is in the over load region between 105% to 140%. If the load is around 135%, the O/C relay will not protect – but the transformer will get hot and loose its life. Thermal overload protection will help in this case.

It is also beneficial to monitor the overload conditions in the winding and the core separately. The copper portion will get hot faster – for a given overload current, trip time will have to be faster than that for iron core.

b) Current Unbalance protection (46) : This will protect transformers against heavy unbalances. In case of unbalance currents, the negative sequence component will increase – resulting in over heating of transformers. It is advisable to have two levels of unbalance protection – one for alarm and other for trip.

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d) I2T Protection : This protection is very useful for rectifier transformers – where the currents will be fluctuating . In this case the energy dissipated for given over current condition is set as trip limit. If this energy level is exceeded, the transformer is tripped earlier than the IDMT over current trip for the same value.

6.0 Protection of Large Size Transformers (Above 10 MVA)

What we are talking about here are very large bulk power handling transformers where the criticalities are very high. Consequently more protections , than those listed in section 5 above, are envisaged.

The extra protections are in the form of differential and over fluxing protections which are mainly internal faults.

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Primary Side :50 Over current (Instantaneous)51 Over Current (IDMT)50N Earth Fault (Instantaneous)51N Earth Fault (IDMT)49 Thermal Over Load46 Current UnbalanceI2T Inrush energy27 Under Voltage 59 Over Voltage

Secondary Side:50 Over current (Instantaneous)51 Over Current (IDMT)50N Earth Fault (Instantaneous)51N Earth Fault (IDMT)64 Restricted Earth Fault

a) Differential Protection (87) : This is one of the major protections for large transformers. This protects the transformers whenever there is an internal fault . As shown in the SLD, this protection needs two additional sets of CTs, which are perfectly matched and have adequate knee point voltage to drive a relay measuring circuit. It should be noted that:

- a differential relay should trip only for an internal fault

- a differential relay should never trip for an external/through fault.

For this reason a percentage biased relay, with dual slope facility will be the best choice. This will have a very good through fault stability.

It may so happen that a differential relay can trip whenever the transformer is switched on. This is due to the magnetizing inrush current flowing only in primary side of the transformer. To avoid this , the relay should have a second harmonic restraint facility. Similarly a 5th harmonic restraint facility in the relay will help avoiding a differential trip during temporary over fluxing conditions.

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Primary Side :50 Over current (Instantaneous)51 Over Current (IDMT)50N Earth Fault (Instantaneous)51N Earth Fault (IDMT)49 Thermal Over Load46 Current UnbalanceI2T Inrush energy27 Under Voltage 59 Over Voltage 24 Over Fluxing47V Voltage unbalance

Secondary Side:50 Over current (Instantaneous)51 Over Current (IDMT)50N Earth Fault (Instantaneous)51N Earth Fault (IDMT)64 Restricted Earth Fault

Combined protection:87

Differential Protection

b) Voltage unbalance protection (47V) : Voltage unbalance in large transformers are good indication of a grid disturbance. Can be used as an alarm .

c) Over fluxing protection (24) : This is to monitor the flux levels inside the large transformer. If the per unit ratio of V/Hz goes beyond a value 1.05, the transformer will go into an over fluxing condition – this will cause over heating even when the currents are within limits. Hence the need to monitor separately.

7.0 Monitoring of E/F in ungrounded transformers

In case of transformers, predominantly medium size, there can be installations where the neutral is grounded through an impedance or high resistance. In this when an earth fault occurs, normal E/F relays will not work – since the required relay operating current will not flow in the ground path. Consequently, a different method has to be adopted - monitoring the zero sequence voltage . The zero sequence voltage is a good indication of a neutral shift, which happens when there is an earth fault.

There are two schemes for monitoring the neutral shift –

a) use an open delta transformer + a low cost voltage relay. In this case the open delta transformer may become expensive.

b) use normal star connected bus PT – but with a relay which calculates zero sequence voltage by numerical methods.

8.0 Power Management Concept

One of the main concerns of power transmission is the poor power factor conditions at the HT level. Many substations are resorting to adding HT capacitor banks for improving the pF – particularly at 33kV and 11 kV levels. Special relays like Capacitor bank protection relays, Reactive power measuring relays, Voltage & PF monitoring relays will be required here.

9.0 Grid Islanding & Load Shedding

This requirement is very important to keep power transmission stable, within a specified area where there is a reasonable power generation available, when there is a large scale grid disturbance. In this case the entire grid , under disturbed conditions, is islanded into small networks so that the smaller networks can continue with power availability with their own generation capacities. This way total collapse is avoided.

The key parameters for detecting grid disturbances are:

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- rate of change of frequency (dF/dT) - Over / Under voltage- Over / Under Frequency- Heavy fault current which flows from the substation to grid- reverse power flow from substation to grid - large unbalance in grid voltage- Vector shift in grid voltageIt is advisable to have a protection scheme to monitor all the above parameters – particularly for a transformer close to a generating station. It will help in islanding the power station from grid disturbances.

10.0 Advantages of Numerical Relays in Transformer Protection

It has been a practice to use electro-mechanical / solid state relays relays for all above protections. The present trend is to use Numerical relays which offer many advantages as shown in the following table, over the earlier technology.

The usual worry that Numerical relays are very expensive is now removed- continuous production improvement techniques have made numerical relay affordable – some times cheaper from the over all protection perspective. Above all, with features listed as above, Numerical relays are more user friendly and are gaining popularity every where.

11.0 Conclusion Transformer protection plays a major role in ensuring consistent power transmission and distribution. This paper is a brief attempt to bring out the various protections required for transformers. The protections are based on size and location. Numerical relays offer better solutions for transformer protection.

-o0o-

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TABLE OF CONTENTS

No. Topic

1 Bus Bar protection

2 Protection by Back-up Relays

3 Current Differential Relaying

4 Combined Power transformer and Bus Protection

5 Ring Bus Protection

6 Value of Bus Sectionalizing

7 Back up Protection for Bus Faults

8 Automatic Reclosing of Bus Breakers

9 Practices with regard to Circuit Breaker By-passing

10 Special protection Schemes

11 Frequency instability

12 Voltage Instability

13 Transient Angle Instability

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BUS BAR PROTECTION:A bus has no peculiar fault characteristics, and it would lend itself readily to current-differential protection if its CT’s were suitable.

PROTECTION BY BACK-UP RELAYSThe earliest form of bus protection was provided by the relays of circuits over whichcurrent was supplied to a bus, at locations such as shown by the arrows on Fig. 1. In other words, the bus was included within the back-up zone of these relays. This method was relatively slow speed, and loads tapped from the lines would be interrupted unnecessarily, but it was otherwise effective. Some preferred this method to one in which the inadvertent operation of a single relay would trip all the connections to the bus.

CURRENT-DIFFERENTIAL RELAYING WITH OVERCURRENT RELAYSThe principle of current-differential relaying has been described. Figure 3 shows itsapplication to a bus with four circuits. All the CTs have the same nominal ratio and are interconnected in such a way that, for load current or for current flowing to an external fault beyond the CTs of any circuits, no current should flow through the relay coil, assuming that the CTs have no ratio or phase-angle errors. However, the CTs in the faulty circuit may be so badly saturated by the total fault current that they will have very large errors; the other CTs in circuits carrying only a part of the total current may not saturate so much and, hence, may be quite accurate. As a consequence, the differential relay may get a very large current, and, unless the relay has a high enough pickup or a long enough time delay or both, it will operate undesirably and cause all bus breakers to be tripped.The greatest and most troublesome cause of current-transformer saturation is the transient- component of the short-circuit current. It is easy to determine if the CTs in the faulty circuit will be badly saturated by a fault-current wave having a d-c component, by using the following approximate formula:

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CURRENT-DIFFERENTIAL RELAYING WITHPERCENTAGE-DIFFERENTIAL RELAYSAs in differential relaying for generators and transformers, the principle of percentage differential relaying is a great improvement over overcurrent relays in a differential CT circuit. The problem of providing enough restraining circuits has been largely solved by so called multi restraint relays. By judicious grouping of circuits and by the use of two relays per phase where necessary, sufficient restraining circuits can generally be provided.Further improvement in selectivity is provided by the variable-percentage characteristic, like that described in connection with generator protection; with this characteristic, one should make sure that very high internal-fault currents will not cause sufficient restraint to prevent tripping.This type of relaying equipment is available with operating times of the order of 3 to 6 cycles (60-cycle basis). It is not suitable where high-speed operation is required.As in current-differential relaying with overcurrent relays, the problem of calculating the CT errors is very difficult. The use of percentage restraint and the variable-percentage characteristic make the relay quite insensitive to the effects of CT error. Nevertheless, it is recommended that each application be referred to the manufacturer together with all the necessary data.A disadvantage of this type of equipment is that all CT secondary leads must be run to the relay panel.

COMBINED POWER-TRANSFORMER AND BUS PROTECTIONFigure 9 shows a frequently encountered situation in which a circuit breaker is omitted between a transformer bank and a low-voltage bus. If the low-voltage bus supplies purely load circuits without any back-feed possible from generating sources, the CT’s in all the load circuits may be paralleled and the transformer-differential relay’s zone of protection may be extended to include the bus.Figure 10 shows two parallel high-voltage lines feeding a power-transformer bus with nocircuit breaker between the transformer and the bus. As shown in the figure, a three winding type of percentage-differential relay will provide good protection for the bus and

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the transformer. In Fig. 11, the two high-voltage lines are from different stations and may constitute an interconnection between parts of a system. Consequently, much higher load currents may flow through these circuits than the rated load current of the power transformer. Therefore, the CT ratios in the high-voltage circuits may have to be much higher than one would desire for the most sensitive protection of the power transformer. And therefore, the protective scheme of Fig. 10, though generally applicable, is not as sensitive to transformer faults as the arrangement of Fig. 11. Bushing CT’s can generally be added to most power transformers, but it is considerably less expensive and less troublesome if the power transformers are purchased with the two sets of CT’s already installed. It is almost axiomatic that, whenever circuit breakers are to be omitted on the high-voltage side of power transformers, two sets of bushing CT’s should be provided on the transformer high voltage bushings. The arrangement of Fig. 11 can be extended to accommodate more high-voltage lines or more power transformers, although, as stated in Chapter 11, it is not considered good practice to omit high-voltage breakers when two or more power transformer banks rated 5000 kVA or higher are paralleled.

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RING-BUS PROTECTIONNo separate relaying equipment is provided for a ring bus. Instead, the relayingequipments of the circuits connected to the bus include the bus within their zones ofprotection, as illustrated in Fig. 13. The relaying equipment of each circuit is indicated by a box lettered to correspond to the protected circuit, and is energized by the parallel connected CT’s in the branches that feed the circuit.A separate voltage supply is required for the protective relays of each circuit. Also, the CT ratios must be suitable for the largest magnitude of load current that might flow around the ring, which might be too high for the desired protection of a given circuit.

THE VALUE OF BUS SECTIONALIZINGAlthough the design of busses does not fall in the category of bus relaying, it is well to keep in mind that bus sectionalizing helps to minimize interference with service when a bus fault occurs. For some busses, sectionalizing is an essential feature of design if stability is to be maintained after a bus fault. With bus sectionalizing, each bus section can be protected separately, and the likelihood of a fault in one section interfering with the service of another section is thereby minimized.

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BACK-UP PROTECTION FOR BUS FAULTSIf one or more bus breakers fail to trip in the event of a bus fault, back-up protection is provided by the relaying equipments at the far ends of the circuits that continue to feed current directly to the fault.Occasionally, relaying equipment is provided at a bus location for back-up protection of adjoining circuits. This is done only when it is impossible to provide the desired back-up protection in the conventional manner described in Chapter 1. This matter is treated further under the subject of line protection.

AUTOMATIC RECLOSING OF BUS BREAKERSA few installations of outdoor automatic substations, whose busses are not enclosed,employ automatic reclosing of the bus breakers. In at least one installation, a single circuit connected to a generating source is first reclosed and, if it stays in, the remaining, circuits are then reclosed all automatically. Somewhat the same philosophy applies to outdoor open busses as to transmission lines, namely, that many faults will be non-persisting if quickly cleared, and, hence, that automatic reclosing will usually be successful. However, substations are generally better protected against lightning than lines, and their exposure to lightning is far less. Hence, one can expect that a larger percentage of bus faults will be persisting.

PRACTICES WITH REGARD TO CIRCUIT-BREAKER BY-PASSINGMost users of bus-differential protection take the bus protective-relaying equipment

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completely out of service, either automatically or manually, and do not substitute any other equipment for temporary protection, when circuit breakers are to be by-passed for maintenance purposes or when any other abnormal set-up is to be made. Of course, the bus still has time-delay protection because the back-up equipment in the circuits connected to the bus should function for bus faults. Others use a wide diversity of temporary forms of bus relaying.

SPECIAL PROTECTION SCHEMES:Power systems have originally arisen as individual self-sufficient units, where the power production matched the consumption. In a case of a severe failure, a system collapse was unavoidable and meant a total blackout and interruption of the supply for all customers. But the restoration of the whole system and synchronisation of its generators were relatively easy thanks to the small size of the system. Power systems size and complexity have grown to satisfy a larger and larger power demand. Phenomena, having a system/global nature, endangering a normal operation of power systems have appeared, explicitly:

Frequency Instability – is inability of a power system to maintain steady frequency within the operating limits.

Voltage Instability – is the inability of a power system to maintain steady acceptable voltages at all buses in the system under normal operating conditions and after being subjected to a disturbance. A system enters a state of voltage instability when a disturbance, increase in load demand, or change in system conditions causes a progressive and uncontrollable drop in voltage. A system is voltage unstable if, for at least one bus in the system, the bus voltage magnitude decreases as the reactive power injection in the same bus is increased

Transient Angular Instability (also called Generator’s Out-of-step) – is the inability of the power system to maintain synchronism when subjected to a severe transient disturbance. The resulting system response involves large excursions of generator angles and is influenced by the nonlinear power-angle relationship. Local mode of Small-signal Angular Instability (also mentioned as Generator’s Swinging or Power Oscillations) – is the inability of the power system to maintain synchronism under small disturbances. Such disturbances occur continually on the system because of small variations in loads and generation. The disturbances are considered sufficiently small for linearization of system equations to be permissible for purposes of analysis. Local modes or machine-system modes are associated with the swinging of units at a generating station with respect to the rest of the power system. The term local is used because the oscillations are localized at one station or small part of the power system.

With the rising importance of the electricity for industry (and the entire society), the reliability of supply has become a serious issue. Interconnection of the separated/individual power systems have offered a number of benefits, such as sharing the reserves both for a normal operation and emergency conditions, dividing of the responsibility for the frequency regulation among all

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generators and a possibility to generate the power in the economically most attractive areas, thus providing a good basis for the power trade. Although this has reduced some negative features mentioned above, on the other hand it has created even a new problem:• Inter-area mode of Small-signal Angular Instability – inter-area modes are associated with the swinging of many machines in one part of the system against machines in other parts. They are caused by two or more groups of closely coupled machines being interconnected by weak ties. Nowadays, when environmental and other restrictions make building of new power plants and transmission lines more difficult and utilities face continuous grow of power demand and power market deregulation, power systems are operated closer to their stability limits. When an abnormal condition/failure is not eliminated but spread, it can lead to catastrophic scenarios If this happens, an extremely complicated and complex restoration procedure must take place.In the beginning, attempts to apply local protection devices have been made. To mention some typical ones: under frequency relay, under voltage relay.However, the character of the dangerous stresses mentioned above, is usually global, not local. Therefore the protection systems, using data from more locations as well as acting with a wide area orientation, have been proposed, designed and in some cases installed to handle them. These are most often referred as Special Protection Schemes (SPS) or sometimes System Protection Schemes.

“… a protection scheme that is designed to detect a particular system condition that is known to cause unusual stress to the power system and to take some type of predetermined action to counteract the observed condition in a controlled manner. In some cases, SPSs are designed to detect a system condition that is known to cause instability, overload, or voltage collapse. The action prescribed may require the opening of one or more lines, tripping o generators, ramping of HVDC power transfers, intentional shedding of load, or other measures that will alleviate the problem of concern. Common types of line or apparatus protection are not included in the scope of interest here.”

there are five states of operating conditions – Normal, Alert, Emergency, In Extremis and Restorative. In case of highly reliable SPS with a good performance, a normal power system operation could be shifted from the Normal state to Alert state. This confidence in SPS would allow much better utilization of existing assets (transmission lines etc.).

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Arrows express possible transitions among them.

The four main design criteria, which should be used for SPS, are [CIGRE, 2000]:

Dependability – The certainty that the SPS operates when required, that is, in all cases where emergency controls are required to avoid a collapse.

Security – The certainty that the SPS will not operate when not required, does not apply emergency controls unless they are necessary to avoid a collapse.

Selectivity – The ability to select the correct and minimum amount action to perform the intended function, that is, to avoid using disruptive controls such as load shedding if they are not necessary to avoid a collapse.

Robustness – The ability of the SPS to provide dependability, security and selectivity over the full range of dynamic and steady state operating conditions that it will encounter.

Frequency Instability Keeping frequency within the nominal operating range (ideally at nominal constant value) is essential for a proper operation of a power system. A maximal acceptable frequency deviation (usually 2 Hz) is dictated by an optimal setting of control circuits of thermal power plants. When this boundary is reached, unit protection disconnects the power plant. This makes situation even worse – frequency further decreases and it may finally lead to the total collapse of the whole system. For the correction of small deviations, Automatic Generation Control (AGC) is used and larger deviations require so-called spinning reserves or fast start-up of generators. “When more severe disturbances occur, e.g. loss of a station (all generating units), loss of a major load centre or loss of AC or DC interconnection, emergency control measures may be required to maintain frequency stability. Emergency control measures may include:

Tripping of generators Fast generation reduction through fast-valving or water diversion HVDC power transfer control Load shedding

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Controlled opening of interconnection to neighboring systems to prevent spreading of frequency problems

Controlled islanding of local system into separate areas with matching generation and load” Common practice in utilities is that most of the above actions are executed manually by a dispatcher/operator of the grid.

Automatic local devices used for the load shedding are UFLS (Under Frequency Load Shedding) relays. They are usually triggered when frequency sinks to the predefined level and/or with a predefined rate of change. Their action is disconnection of the load in several steps (5 - 20 % each) from the feeders they supervise. However, their effective use is strongly dependent on their careful tuning based on pre-studies, since there is no on-line coordination between them. Another disadvantage is, that they can only react to the under frequency, increase of frequency is not covered by them at all. In some cases the impact of their operation may be negative, since they are not capable of the adaptability to the present situation (e.g. production of distributed/decentralized generation varies in time so quite often the distribution voltage level feeders feed the energy back into the network. So they don’t appear as loads and their disconnection makes situation even worse).

The mentioned weakness of UFLS relays (in coordination) can be overcome by centralized shedding schemes.

Voltage Instability Voltage instability is basically caused by an unavailability of reactive power support in some nodes of the network, where the voltage uncontrollably falls. Lack of reactive power may essentially have two origins. Gradual increase of power demand which reactive part cannot be met in some buses or sudden change of a network topology redirecting the power flows such a way that a reactive power cannot be delivered to some buses. The relation between the active power consumed in the monitored area and the corresponding voltages is expressed by so called PV-curves (often referred as “nose” curves). The increased values of loading are accompanied by a decrease of voltage (except a capacitive load). When the loading is further increased, the maximum loadability point is reached, from which no additional power can be transmitted to the load under those conditions. In case of constant power loads the voltage in the node becomes uncontrollable and rapidly decreases. However, the voltage level close to this point is sometimes very low, what is not acceptable under normal operating conditions, although it is still within the stable region. But in the emergency cases, some utilities accept it for a short period. There are also other alternative graphical representations, e.g. QV-curves (amount of needed reactive power to keep a certain voltage). The emergency stabilizing actions which might be taken are in principle same as in case of the frequency instability, plus:

Change of the generator voltage set point Automatic shunt switching Control of series compensation

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Blocking of Tap Changer of transformers Fast re-dispatch of generation

Under voltage relays are a conventional local solution. The criterion triggering the load shedding action is a predefined voltage level in the supervised node

Transient Angle Instability In case of transient angle instability, a severe disturbance is a disturbance, which does not allow a generator to deliver its output electrical power into the network (typically a tripping of a line connecting the generator with the rest of the network in order to clear a short circuit). This power is then absorbed by the rotor of the generator, increases its kinetic energy what results in the sudden acceleration of the rotor above the acceptable revolutions and eventually damage of the generator. Therefore the measures taken against this scenario aim mainly to either an intended dissipation of undelivered power:

Braking resistor, FACTS devices etc., or reducing the mechanical power driving the generator:

fast-valving, disconnection of the generator etc.

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TABLE OF CONTENTS

No. Topic

1 Distance Protection Introduction

2 Principles of Distance Relays

3 Relay Performance

4 Relationship between Relay Voltage &ZS/ZL Ratio

5 Voltage Limit for Accurate Reach Point Measurement

6 Zones of Protection

7 Distance Relay Characteristics

8 Distance Relay Implementation

9 Effect of Source Impedance & Earthing Methods

10 Distance Relay Application Problems

11 Other Distance Relay Features

12 Distance Relay Application Examples

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DISTANCE PROTECTION

1. INTRODUCTION

The problem of combining fast fault clearance with selective tripping of plant is a key aim for the protection of power systems. To meet these requirements, highspeed protection systems for transmission and primary distribution circuits that are suitable for use with the automatic reclosure of circuit breakers are under continuous development and are very widely applied. Distance protection, in its basic form, is a non-unit system of protection offering considerable economic and technical advantages. Unlike phase and neutral overcurrent protection, the key advantage of distance protection is that its fault coverage of the protected circuit is virtually independent of source impedance variations. This is illustrated in Figure 1, where it can be seen that overcurrent protection cannot be applied satisfactorily.

Fig. 1 Advantages of Distance Overcurrent Protection

This is illustrated in Figure 1, where it can be seen that overcurrent protection cannot be applied satisfactorily. Distance protection is comparatively simple to apply and it can be fast in operation for faults located along most of a protected circuit. It can also provide both primary and remote back-up functions in a single scheme. It can easily be adapted to create a unit protection scheme when applied with a signaling channel. In this form it is eminently suitable for application with high-speed autoreclosing, for the protection of critical transmission lines.

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2. PRINCIPLES OF DISTANCE RELAYS

Since the impedance of a line up to a predetermined point (the reach point). Such a relay is described as a distance relay and is designed to operate only for faults occurring between the relay location and the selected reach point, thus giving discrimination for faults that may occur in different line sections.

The basic principle of distance protection involves the division of the voltage at the relaying point by the measured current. The apparent impedance so calculated is compared with the reach point impedance. If the measured impedance is less than the reach point impedance, it is assumed that a fault exists on the line between the relay and the reach point.

The reach point of a relay is the point along the line impedance locus that is intersected by the boundary characteristic of the relay. Since this is dependent on the ratio of voltage and current and the phase angle between them, it may be plotted on an R/X diagram. The loci of power system impedances as seen by the relay during faults, power swings and load variations may be plotted on the same diagram and in this manner the performance of the relay in the presence of system faults and disturbances may be studied.

3. RELAY PERFORMANCE

Distance relay performance is defined in terms of reach accuracy and operating time. Reach accuracy is a comparison of the actual ohmic reach of the relay under practical conditions with the relay setting value in ohms. Reach accuracy particularly depends on the level of voltage presented to the relay under fault conditions. The impedance measuring techniques employed in particular relay designs also have an impact.

Operating times can vary with fault current, with fault position relative to the relay setting, and with the point on the voltage wave at which the fault occurs. Depending on the measuring techniques employed in a particular relay design, measuring signal transient errors, such as those produced by Capacitor Voltage Transformers or saturating CT’s, can also adversely delay relay operation for faults close to the reach point. It is usual for electromechanical and static distance relays to claim both maximum and minimum operating times. However, for modern digital or numerical distance relays, the variation between these is small over a wide range of system operating conditions and fault positions.

Electromechanical/Static Distance Relays

With electromechanical and earlier static relay designs, the magnitude of input quantities particularly influenced both reach accuracy and operating time. It was customary to present information on relay performance by voltage/reach curves, as shown in Figure 2, and operating time/fault position curves for various values of system impedance ratios (S.I.R.’s) as shown in Figure 3, where:

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andZS - system source impedance behind the relay locationZL - line impedance equivalent to relay reach setting

Figure 2: Typical impedance reach accuracy characteristics for Zone 1

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Fig. 3 : Typical Operation time Characteristics for Zone 1 Phase-Phase FaultsAlternatively, the above information was combined in a family of contour curves, where the fault position expressed as a percentage of the relay setting is plotted against the source to line impedance ratio, as llustrated in Figure 4.

Figure 4: Typical operation-time contours

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Digital/Numerical Distance Relays

Digital/Numerical distance relays tend to have more consistent operating times. They are usually slightly slower than some of the older relay designs when operating under the best conditions, but their maximum operating times are also less under adverse waveform conditions or for boundary fault conditions.

4 RELATIONSHIP BETWEEN RELAY VOLTAGE AND ZS/ZL RATIO

A single, generic, equivalent circuit, as shown in Figure 11.5(a), may represent any fault condition in a three phase power system. The voltage V applied to the impedance loop is the open circuit voltage of the power system. Point R represents the relay location; IR and VR are the current and voltage measured by the relay, respectively.

The impedances ZS and ZL are described as source and line impedances because of their position with respect to the relay location. Source impedance ZS is a measure of the fault level at the relaying point. For faults involving earth it is dependent on the method of system earthing behind the relaying point. Line impedance ZL is a measure of the impedance of the protected section. The voltage VR applied to the relay is, therefore, IRZL. For a fault at the reach point, this may be alternatively expressed in terms of source to line impedance ratio ZS/ZL by means of the following expressions:

Equation 1

The above generic relationship between VR and ZS/ZL, illustrated in Figure 5(b), is valid for all types of shortcircuits provided a few simple rules are observed. These are:

i) for phase faults, V is the phase-phase source voltage and ZS/ZL is the positive sequence source to line impedance ratio. VR is the phase-phase relay voltage and IR is the phase-phase relay current, for the faulted phases

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Equation 2

ii) for earth faults, V is the phase-neutral source voltage and ZS/ZL is a composite ratio involving the positive and zero sequence impedances. VR is the phase-neutral relay voltage and IR is the relay current for the faulted phase

Equation 3

Fig. 5 Relationship between Source to line Ratio and Relay Voltage

5 VOLTAGE LIMIT FOR ACCURATE REACH POINT MEASUREMENT

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The ability of a distance relay to measure accurately for a reach point fault depends on the minimum voltage at the relay location under this condition being above a declared value. This voltage, which depends on the relay design, can also be quoted in terms of an equivalent maximum ZS/ZL or S.I.R.

Distance relays are designed so that, provided the reach point voltage criterion is met, any increased measuring errors for faults closer to the relay will not prevent relay operation. Most modern relays are provided with healthy phase voltage polarization and/or memory voltage polarization. The prime purpose of the relay polarizing voltage is to ensure correct relay directional response for close-up faults, in the forward or reverse direction, where the fault-loop voltage measured by the relay may be very small.

6 ZONES OF PROTECTION

Careful selection of the reach settings and tripping times for the various zones of measurement enables correct coordination between distance relays on a power system. Basic distance protection will comprise instantaneous directional Zone 1 protection and one or more time delayed zones. Typical reach and time settings for a 3-zone distance protection are shown in Figure 6. Digital and numerical distance relays may have up to five zones, some set to measure in the reverse direction. Typical settings for three forward-looking zones of basic distance protection are given in the following sub-sections. To determine the settings for a particular relay design or for a particular distance teleprotection scheme, involving end-to-end signaling, the relay manufacturer’s instructions should be referred to.

Zone 1 Setting

Electromechanical/static relays usually have a reach setting of up to 80% of the protected line impedance forinstantaneous Zone 1 protection. For digital/numerical distance relays, settings of up to 85% may be safe. The resulting 15-20% safety margin ensures that there is no risk of the Zone 1 protection over-reaching the protected line due to errors in the current and voltage transformers, inaccuracies in line impedance data provided for setting purposes and errors of relay setting and measurement. Otherwise, there would be a loss of discrimination with fast operating protection on the following line section. Zone 2 of the distance protectionmust cover the remaining 15-20% of the line.

Zone 2 Setting

To ensure full cover of the line with allowance for the sources of error already listed in the previous section, the reach setting of the Zone 2 protection should be at least 120% of the protected line impedance. In many applications it is common practice to set the Zone 2 reach to be equal to the protected line section +50% of the shortest adjacent line. Where possible, this ensures that the resulting maximum effective Zone 2 reach does not extend beyond the

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minimum effective Zone 1 reach of the adjacent line protection. This avoids the need to grade the Zone 2 time settings between upstream and downstream relays. In electromechanical and static relays, Zone 2 protection is provided either by separate elements or by extending the reach of the Zone 1 elements after a time delay that is initiated by a fault detector. In most digital and numerical relays, the Zone 2 elements are implemented in software.

Zone 2 tripping must be time-delayed to ensure grading with the primary relaying applied to adjacent circuits that fall within the Zone 2 reach. Thus complete coverage of a line section is obtained, with fast clearance of faults in the first 80-85% of the line and somewhat slower clearance of faults in the remaining section of the line.

Fig. 6 Typical time/distance characteristics for three zone distance protection

Zone 3 Setting

Remote back-up protection for all faults on adjacent lines can be provided by a third zone of protection thatis time delayed to discriminate with Zone 2 protection plus circuit breaker trip time for the adjacent line. Zone3 reach should be set to at least 1.2 times the impedance presented to the relay for a fault at the remote end of the second line section.

On interconnected power systems, the effect of fault current infeed at the remote busbars will cause the impedance presented to the relay to be much greater than the actual impedance to the fault and this needs to be taken into account when setting Zone 3. In some systems, variations in the remote busbar infeed can prevent the application of remote back-up Zone 3 protection but on radial distribution systems with single end infeed, no difficulties should arise.

Settings for Reverse Reach and Other Zones

Modern digital or numerical relays may have additional impedance zones that can be utilized to provide additional protection functions. For example, where

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the first three zones are set as above, Zone 4 might be used to provide back-up protection for the local bus bar, by applying a reverse reach setting of the order of 25% of the Zone 1 reach. Alternatively, one of the forward looking zones (typically Zone 3) could be set with a small reverse offset reach from the origin of the R/X diagram, in addition to its forward reach setting. An offset impedance measurement characteristic is nondirectional. One advantage of a non-directional zone of impedance measurement is that it is able to operate for a close-up, zero-impedance fault, in situations wherethere may be no healthy phase voltage signal or memory voltage signal available to allow operation of a directional impedance zone. With the offset-zone time delay bypassed, there can be provision of ‘Switch-on-to-Fault’ (SOTF) protection. This is required where there are line voltage transformers, to provide fast tripping in the event of accidental line energisation with maintenance earthing clamps left in position. Additional impedance zones may be deployed as part of a distance protection scheme used in conjunction with a teleprotection signaling channel.

7 DISTANCE RELAY CHARACTERISTICS

Some numerical relays measure the absolute fault impedance and then determine whether operation is required according to impedance boundaries defined on the R/X diagram. Traditional distance relays and numerical relays that emulate the impedance elements of traditional relays do not measure absolute impedance. They compare the measured fault voltage with a replica voltage derived from the fault current and the zone impedance setting to determine whether the fault is within zone or out-of-zone. Distance relay impedance comparators or algorithms which emulate traditional comparators are classified according to their polar characteristics, the number of signal inputs they have, and the method by which signal comparisons are made. The common types compare either the relative amplitude or phase of two input quantities to obtain operating characteristics that are either straight lines or circles when plotted on an R/X diagram. At each stage of distance relay design evolution, the development of impedance operating characteristic shapes and sophistication has been governed by the technology available and the acceptable cost. Since many traditional relays are still in service and since some numerical relays emulate the techniques of the traditional relays, a brief review of impedance comparators is justified.

7.1 Amplitude and Phase Comparison

Relay measuring elements whose functionality is based on the comparison of two independent quantities are essentially either amplitude or phase comparators. For the impedance elements of a distance relay, the quantities being compared are the voltage and current measured by the relay. There are numerous techniques available for performing the comparison, depending on the technology used. They vary from balanced-beam (amplitude comparison) and induction cup (phase comparison) electromagnetic relays, through diode and operational amplifier comparators in static-type distance relays, to digital sequence comparators in digital relays and to algorithms used in numerical relays.

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Any type of impedance characteristic obtainable with one comparator is also obtainable with the other. The addition and subtraction of the signals for one type of comparator produces the required signals to obtain a similar characteristic using the other type. For example, comparing V and I in an amplitude comparator results in a circular impedance characteristic centred at the origin of the R/X diagram. If the sum and difference of V and I are applied to the phase comparator the result is a similar characteristic.

7.2 Plain Impedance Characteristic

This characteristic takes no account of the phase angle between the current and the voltage applied to it; for this reason its impedance characteristic when plotted on an R/X diagram is a circle with its centre at the origin of the co-ordinates and of radius equal to its setting in ohms. Operation occurs for all impedance values less than the setting, that is, for all points within the circle. The relay characteristic, shown in Figure 7, is therefore nondirectional, and in this form would operate for all faults along the vector AL and also for all faults behind the bus bars up to an impedance AM. It is to be noted that A is the relaying point and RAB is the angle by which the fault current lags the relay voltage for a fault on the line AB and RAC is the equivalent leading angle for a fault on line AC. Vector AB represents the impedance in front of the relay between the relaying point A and the end of line AB. Vector AC represents the impedance of line AC behind the relaying point. AL represents the reach of instantaneous Zone 1 protection, set to cover 80% to 85% of the protected line.

A relay using this characteristic has three important disadvantages:

i) it is non-directional; it will see faults both in front of and behind the relaying point, and therefore requires a directional element to give it correct discrimination.

ii) it has non-uniform fault resistance coverageiii) it is susceptible to power swings and heavy loading of a long line, because

of the large area covered by the impedance circle

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Figure 7: Plain impedance relay characteristic

Figure 8: Combined directional and impedance relays

Directional control is an essential discrimination quality for a distance relay, to make the relay non-responsive to faults outside the protected line. This can be obtained by the addition of a separate directional control element. The impedance characteristic of a directional control element is a straight line on the R/X diagram, so the combined characteristic of the directional and impedance relays is the semi-circle APLQ shown in Figure 8.

If a fault occurs at F close to C on the parallel line CD, the directional unit RD at A will restrain due to current IF1. At the same time, the impedance unit is prevented from operating by the inhibiting output of unit RD. If this control is not provided, the under impedance element could operate prior to circuit breaker C opening. Reversal of current through the relay from IF1 to IF2 when C opens could then result in incorrect tripping of the healthy line if the directional unit RD operates before the impedance unit resets. This is an example of the need to consider the proper co-ordination of multiple relay elements to attain reliable relay performance during evolving fault conditions.

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In older relay designs, the type of problem to be addressed was commonly referred to as one of ‘contact race’.

7.3 Self-Polarised Mho Relay

The mho impedance element is generally known as such because its characteristic is a straight line on an admittance diagram. It cleverly combines the discriminating qualities of both reach control and directional control, thereby eliminating the ‘contact race’ problems that may be encountered with separate reach and directional control elements. This is achieved by the addition of a polarising signal. Mho impedance elementswere particularly attractive for economic reasons where electromechanical relay elements were employed. As a result, they have been widely deployed worldwide for many years and their advantages and limitations are now well understood. For this reason they are still emulated in the algorithms of some modern numerical relays. The characteristic of a mho impedance element, when plotted on an R/X diagram, is a circle whose circumference passes through the origin, as illustrated in Figure 9(b). This demonstrates that the impedance element is inherently directional and such that it will operate only for faults in the forward direction along line AB. The impedance characteristic is adjusted by setting Zn, the impedance reach, along the diameter and ϕ, the angle of displacement of the diameter from the R axis. Angle ϕ is known as the Relay Characteristic Angle (RCA). The relay operates for values of fault impedance ZF within its characteristic.

It will be noted that the impedance reach varies with fault angle. As the line to be protected is made up of resistance and inductance, its fault angle will be dependent upon the relative values of R and X at the system operating frequency. Under an arcing fault condition, or an earth fault involving additional resistance, such as tower footing resistance or fault through vegetation, the value of the resistive component of fault impedance will increase to change the impedance angle. Thus a relay having a characteristic angle equivalent to the line angle will under-reach under resistive fault conditions. It is usual, therefore, to set the RCA less than the line angle, so that it is possible to accept a small amount of fault resistance without causing under-reach. However, when setting the relay, the difference between the line angle θ and the relay characteristic angle ϕ must be known. The resulting characteristic is shown in Figure 9(c) where AB corresponds to the length of the line to be protected. With ϕ set less than θ, the actual amount of line protected, AB, would be equal to the relay setting value AQ multiplied by cosine (θ-ϕ). Therefore the required relay setting AQ is given by:

Due to the physical nature of an arc, there is a non-linear relationship between arc voltage and arc current, which results in a non-linear resistance. Using the empirical formula derived by A.R. van C. Warrington, the approximate value of arc resistance can be assessed as:

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where: Ra = arc resistance (ohms) L = length of arc (metres)I = arc current (A)

On long overhead lines carried on steel towers with overhead earth wires the effect of arc resistance can usually be neglected. The effect is most significant on short overhead lines and with fault currents below 2000A (i.e. minimum plant condition), or if the protected line is of wood-pole construction without earth wires. In the latter case, the earth fault resistance reduces the effective earth-fault reach of a mho Zone 1 element to such an extent that the majority of faults are detected in Zone 2 time. This problem can usually be overcome by using a relay with a cross-polarised mho or a polygonal characteristic. Where a power system is resistance-earthed, it should be appreciated that this does not need to be considered with regard to the relay settings other than the effect that reduced fault current may have on the value of arc resistance seen. The earthing resistance is in the source behind the relay and only modifies the source angle and source to line impedance ratio for earth faults. It would therefore be taken into account only when assessing relay performance in terms of system impedance ratio.

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Figure 9 : Mho Relay Characteristic

7.4 Offset Mho/Lenticular Characteristics

Under close up fault conditions, when the relay voltage falls to zero or near-zero, a relay using a self-polarised mho characteristic or any other form of self-polarised directional impedance characteristic may fail to operate when it is required to do so. Methods of covering this condition include the use of non-directional impedance characteristics, such as offset mho, offset lenticular, or cross-polarised and memory polarised directional impedance characteristics. If current bias is employed, the mho characteristic is shifted to embrace the origin, so that the measuring element can operate for close-up faults in both the forward and the reverse directions. The offset mho relay has two main applications:

Figure 10: Typical applications for the offset mho relay

7.4.1 Third zone and busbar back-up zone

In this application it is used in conjunction with mho measuring units as a fault detector and/or Zone 3 measuring unit. So, with the reverse reach arranged to extend into the busbar zone, as shown in Figure 10(a), it will provide back-up protection for busbar faults. This facility can also be provided with quadrilateral characteristics. A further benefit of the Zone 3 application is for Switch-on-to-Fault (SOTF) protection, where the Zone 3 time delay would be bypassed for a

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short period immediately following line energisation to allow rapid clearance of a fault anywhere along the protected line.

7.4.2 Carrier starting unit in distance schemes with carrier blocking

If the offset mho unit is used for starting carrier signaling, it is arranged as shown in Figure 10(b). Carrier is transmitted if the fault is external to the protected line but inside the reach of the offset mho relay, in order to prevent accelerated tripping of the second or third zone relay at the remote station. Transmission is prevented for internal faults by operation of the local mho measuring units, which allows highspeed fault clearance by the local and remote end circuit breakers.

7.4.3 Application of lenticular characteristic

There is a danger that the offset mho relay shown in Figure 10(a) may operate under maximum load transfer conditions if Zone 3 of the relay has a large reach setting. A large Zone 3 reach may be required to provide remote back-up protection for faults on the adjacent feeder.

Figure 11: Minimum load impedance permitted with lenticular, offset mho and impedance relays

To avoid this, a shaped type of characteristic may be used, where the resistive coverage is restricted. With a ‘lenticular’ characteristic, the aspect ratio of the lens is adjustable, enabling it to be set to provide the maximum fault resistance coverage consistent with non-operation under maximum load transfer conditions. Figure 11.11 shows how the lenticular characteristic can tolerate much higher degrees of line loading than

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offset mho and plain impedance characteristics. Reduction of load impedance from ZD3 to ZD1 will correspond to an equivalent increase in load current.

7.5 Fully Cross-Polarised Mho Characteristic

The previous section showed how the non-directional offset mho characteristic is inherently able to operate or close-up zero voltage faults, where there would be no polarising voltage to allow operation of a plain mho directional element. One way of ensuring correct mho element response for zero-voltage faults is to add a percentage of voltage from the healthy phase(s) to the main polarising voltage as a substitute phase reference. This technique is called cross-polarising, and it has the advantage of preserving and indeed enhancing the directional properties of the mho characteristic. By the use of a phase voltage memory system, that provides several cycles of pre-fault voltage reference during a fault, the cross-polarisation technique is also effective for close-up three-phase faults. For this type of fault, no healthy phase voltage reference is available.

Early memory systems were based on tuned, resonant, analogue circuits, but problems occurred when applied to networks where the power system operating frequency could vary. More modern digital or numerical systems can offer a synchronous phase reference for variations in power system frequency before or even during a fault.

As described in Section 7.3, a disadvantage of the self-polarised, plain mho impedance characteristic, when applied to overhead line circuits with high impedance angles, is that it has limited coverage of arc or fault resistance. The problem is aggravated in the case of short lines, since the required Zone 1 ohmic setting is low. The amount of the resistive coverage offered by the mho circle is directly related to the forward reach setting. Hence, the resulting resistive coverage may be too small in relation to the expected values of fault resistance. One additional benefit of applying cross-polarisation to a mho impedance element is that its resistive coverage will be enhanced. This effect is illustrated in Figure 12, for the case where a mho element has 100% a cross-polarisation. With cross-polarisation from the healthy phase(s) or from a memory system, the mho resistive expansion will occur during a balanced three phase fault as well as for unbalanced faults. The expansion will not occur under load conditions, when there is no phase shift between the measured voltage and the polarising voltage. The degree of resistive reach enhancement depends on the ratio of source impedance to relay reach (impedance) setting as can be deduced by reference to Figure 13.

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Figure 12: Fully cross-polarised mho relay characteristic with variations of ZS/ZL ratio

Figure 13: Illustration of improvement in relay resistive coverage for fully cross polarised characteristic

It must be emphasised that the apparent extension of a fully cross-polarised impedance characteristic into the negative reactance quadrants of Figure 13 does not imply that there would be operation for reverse faults. With cross-polarisation, the relay characteristic expands to encompass the origin of the impedance diagram for forward faults only. For reverse faults, the effect is to exclude the origin of the impedance diagram, thereby ensuring proper directional responses for close-up forward or reverse faults.

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Fully cross-polarised characteristics have now largely been superseded, due to the tendency of comparators connected to healthy phases to operate under heavy fault conditions on another phase. This is of no consequence in a switched distance relay, where a single comparator is connected to the correct fault loop impedance by starting units before measurement begins. However, modern relays offer independent impedance measurement for each of the three earth-fault and three phase-fault loops. For these types of relay, maloperation of healthy phases is undesirable, especially when single pole tripping is required for single-phase faults.

7.6 Partially Cross-Polarised Mho Characteristic

Where a reliable, independent method of faulted phase selection is not provided, a modern non-switcheddistance relay may only employ a relatively small percentage of cross polarisation.

Figure 11.14: Partially cross-polarised characteristic with 'shield' shape

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The level selected must be sufficient to provide reliable directional control in the presence of CVT transients for close-up faults, and also attain reliable faulted phase selection. By employing only partial cross-polarisation, the disadvantages of the fully cross-polarised characteristic are avoided, while still retaining the advantages. Figure 14 shows a typical characteristic that can be obtained using this technique.

7.7 Quadrilateral Characteristic

This form of polygonal impedance characteristic is shown in Figure 15. The characteristic is provided with forward reach and resistive reach settings that are independently adjustable. It therefore provides better resistive coverage than any mho-type characteristic for short lines. This is especially true for earth fault impedance measurement, where the arc resistances and fault resistance to earth contribute to the highest values of fault resistance. To avoid excessive errors in the zone reach accuracy, it is common to impose a maximum resistive reach in terms of the zone impedance reach. Recommendations in this respect can usually be found in the appropriate relay manuals.

Figure 15: Quadrilateral characteristic

Quadrilateral elements with plain reactance reach lines can introduce reach error problems for resistive earth faults where the angle of total fault current differs from the angle of the current measured by the relay. This will be the case where the local and remote source voltage vectors are phase shifted with respect to each other due to pre-fault power flow. This can be overcome by selecting an alternative to use of a phase current for polarisation of the reactance reach line. Polygonal impedance characteristics are highly flexible in terms of fault impedance coverage for both phase and earth faults. For this reason, most digital and numerical distance relays now offer this form of characteristic. A further factor is that the additional cost implications of implementing this characteristic using discrete component electromechanical or early static relay technology do not arise.

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7.8 Protection against Power Swings – Use of the Ohm Characteristic

During severe power swing conditions from which a system is unlikely to recover, stability might only be regained if the swinging sources are separated. Where such scenarios are identified, power swing, or out-of-step, tripping protection can be deployed, to strategically split a power system at a preferred location. Ideally, the split should be made so that the plant capacity and connected loads on either side of the split are matched.

This type of disturbance cannot normally be correctly identified by an ordinary distance protection. As previously mentioned, it is often necessary to prevent distance protection schemes from operating during stable or unstable power swings, in order to avoid cascade tripping. To initiate system separation for a prospective unstable power swing, an out-of-step tripping scheme employing ohm impedance measuring elements can be deployed. Ohm impedance characteristics are applied along the forward and reverse resistance axes of the R/X diagram and their operating boundaries are set to be parallel to the protected line impedance vector, as shown in Figure 16.

The ohm impedance elements divide the R/X impedance diagram into three zones, A, B and C. As the impedance changes during a power swing, the point representing the impedance moves along the swing locus, entering the three zones in turn and causing the ohm units to operate in sequence. When the impedance enters the third zone the trip sequence is completed and the circuit breaker trip coil can be energized at a favourable angle between system sources for arc interruption with little risk of restriking.

Figure 16: Application of out-of-step tripping relay characteristic

Only an unstable power swing condition can cause the impedance vector to move successively through the

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three zones. Therefore, other types of system disturbance, such as power system fault conditions, will not result in relay element operation.

7.9 Other Characteristics

The execution time for the algorithm for traditional distance protection using quadrilateral or similar characteristics may result in a relatively long operation time, possibly up to 40ms in some relay designs. To overcome this, some numerical distance relays also use alternative algorithms that can be executed significantly faster. These algorithms are based generally on detecting changes in current and voltage that are in excess of what is expected, often known as the ‘Delta’ algorithm.

This algorithm detects a fault by comparing the measured values of current and voltage with the values sampled previously. If the change between these samples exceeds a predefined amount (the ‘delta’), it is assumed a fault has occurred. In parallel, the distance to fault is also computed. Provided the computed distance to fault lies within the Zone reach of the relay, a trip command is issued. This algorithm can be executed significantly faster than the conventional distance algorithm, resulting in faster overall tripping times. Faulted phase selection can be carried out by comparing the signs of the changes in voltage and current.

Relays that use the ‘Delta’ algorithm generally run both this and conventional distance protection algorithms in parallel, as some types of fault (e.g. high-resistance faults) may not fall within the fault detection criteria ofthe Delta algorithm.

8 DISTANCE RELAY IMPLEMENTATION

Discriminating zones of protection can be achieved using distance relays, provided that fault distance is a simple function of impedance. While this is true in principle for transmission circuits, the impedances actually measured by a distance relay also depend on the following factors:

1. the magnitudes of current and voltage (the relay may not see all the current that produces the fault voltage)

2. the fault impedance loop being measured 3. the type of fault4. the fault resistance5. the symmetry of line impedance6. the circuit configuration (single, double or multiterminal circuit)

It is impossible to eliminate all of the above factors for all possible operating conditions. However, considerable success can be achieved with a suitable distance relay. This may comprise relay elements or algorithms for starting, distance measuring and for scheme logic.

The distance measurement elements may produce impedance characteristics selected from those described

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in Section 7. Various distance relay formats exist, depending on the operating speed required and cost considerations related to the relaying hardware, software or numerical relay processing capacity required. The most common formats are:

a) ingle measuring element for each phase is provided, that covers all phase faults

b) ore economical arrangement is for ‘starter’ elements to detect which phase or phases have suffered a fault. The starter elements switch a single measuring element or algorithm to measure the most appropriate fault impedance loop. This is commonly referred to as a switched distance relay.

c) a single set of impedance measuring elements for each impedance loop may have their reach settings progressively increased from one zone reach setting to another. The increase occurs after zone time delays that are initiated by operation of starter elements. This type of relay is commonly referred to as a reach-stepped distance relay

d) each zone may be provided with independent sets of impedance measuring elements for each impedance loop. This is known as a full distance scheme, capable of offering the highest performance in terms of speed and application flexibility.

Furthermore, protection against earth faults may require different characteristics and/or settings to those required for phase faults, resulting in additional units being required. A total of 18 impedance-measuring elements or algorithms would be required in a full distance relay for three-zone protection for all types of fault.

With electromechanical technology, each of the measuring elements would have been a separate relay housed in its own case, so that the distance relay comprised a panel-mounted assembly of the required relays with suitable inter-unit wiring. Figure17(a) shows an example of such a relay scheme.

Digital/numerical distance relays (Figure17(b)) are likely to have all of the above functions implemented in software. Starter units may not be necessary. The complete distance relay is housed in a single unit, making for significant economies in space, wiring and increased dependability, through the increased availability that stems from the provision of continuous self-supervision. When the additional features detailed in Section 11 are taken into consideration, such equipment offers substantial user benefits.

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Figure 17 (a): First generation of static distance relay

Figure 17 (b): MiCOM P440 series numerical distance relay

8.1 Starters for switched distance protection

Electromechanical and static distance relays do not normally use an individual impedance-measuring element per phase. The cost and the resulting physical scheme size made this arrangement impractical, except for the most demanding EHV transmission applications. To achieve economy for other applications, only one measuring element was provided, together with ‘starter’ units that detected which phases were faulted, in order to switch the appropriate signals to the single measuring function. A distance relay using this technique is known as a switched distance relay. A number of different types of starters have been used, the most common being based on overcurrent, undervoltage or under-impedance measurement.

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Numerical distance relays permit direct detection of the phases involved in a fault. This is called faulted phase selection, often abbreviated to phase selection. Several techniques are available for faulted phase selection, which then permits the appropriate distance-measuring zone to trip. Without phase selection, the relay risks having over or underreach problems, or tripping threephase when single-pole fault clearance is required. Several techniques are available for faulted phase selection, such as:

a. superimposed current comparisons, comparing the step change of level between pre-fault load, and fault current (the ‘Delta’ algorithm). This enables very fast detection of the faulted phases, within only a few samples of the analogue current inputs

b. change in voltage magnitude c. change in current magnitude

Numerical phase selection is much faster than traditional starter techniques used in electromechanical or static distance relays. It does not impose a time penalty as the phase selection and measuring zone algorithms run in parallel. It is possible to build a full scheme relay with these numerical techniques. The phase selection algorithm provides faulted phase selection, together with a segregated measuring algorithm for each phase-ground and phase to phase fault loop (AN, BN, CN, AB, BC, CA), thus ensuring full scheme operation.

However, there may be occasions where a numerical relay that mimics earlier switched distance protection techniques is desired. The reasons may be economic (less software required – thus cheaper than a relay that contains a full-scheme implementation) and/or technical.

Some applications may require the numerical relay characteristics to match those of earlier generations already installed on a network, to aid selectivity. Such relays are available, often with refinements such as multi-sided polygonal impedance characteristics that assist in avoiding tripping due to heavy load conditions.

With electromechanical or static switched distance relays, a selection of available starters often had to be made. The choice of starter was dependent on power system parameters such as maximum load transfer in relation to maximum reach required and power system earthing arrangements.

Where overcurrent starters are used, care must be taken to ensure that, with minimum generating plant in service, the setting of the overcurrent starters is sensitive enough to detect faults beyond the third zone. Furthermore, these starters require a high drop-off to pick-up ratio, to ensure that they will drop off under maximum load conditions after a second or third zone fault has been cleared by the first zone relay in the faulty section. Without this feature, indiscriminate tripping may result for subsequent faults in the second or third zone. For satisfactory operation of the overcurrent starters in a switched distance scheme, the following conditions must be fulfilled:

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a. the current setting of the overcurrent starters must be not less than 1.2 times the maximum full load current of the protected line

b. the power system minimum fault current for a fault at the Zone 3 reach of the distance relay must not be less than 1.5 times the setting of the overcurrent starters

On multiple-earthed systems where the neutrals of all the power transformers are solidly earthed, or in powersystems where the fault current is less than the full load current of the protected line, it is not possible to useovercurrent starters. In these circumstances underimpedance starters are typically used.

The type of under-impedance starter used is mainly dependent on the maximum expected load current and equivalent minimum load impedance in relation to the required relay setting to cover faults in Zone 3. This is illustrated in Figure 11 where ZD1, ZD2, and ZD3 are respectively the minimum load impedances permitted when lenticular, offset mho and impedance relays are used.

9. EFFECT OF SOURCE IMPEDANCE AND EARTHING METHODS

For correct operation, distance relays must be capable of measuring the distance to the fault accurately. To ensure this, it is necessary to provide the correct measured quantities to the measurement elements. It is not always the case that use of the voltage and current for a particular phase will give the correct result, or that additional compensation is required.

9.1 Phase Fault Impedance Measurement

Figure 18 shows the current and voltage relations for the different types of fault. If ZS1 and ZL1 are the source and line positive sequence impedances, viewed from the relaying point, the currents and voltages at this point for double phase faults are dependent on the source impedance as well as the line impedance. The relationships are given in Figure 19.

Applying the difference of the phase voltages to the relay eliminates the dependence on ZS1. For example:

(For Double- Phase Faults )

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Figure 18: Current and voltage relationships for some shunt faults

Figure 19: Phase currents and voltages at relaying point for 3-phase and double-phase faults

Distance measuring elements are usually calibrated in terms of the positive sequence impedance. Correct measurement for both phase-phase and three-phase faults is achieved by supplying each phase-phase measuring element with its corresponding phase-phase voltage and difference of phase currents. Thus, for the B-C element, the current measured will be:

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and the relay will measure ZL1 in each case.

9.2 Earth Fault Impedance Measurement

When a phase-earth fault occurs, the phase-earth voltage at the fault location is zero. It would appear that the voltage drop to the fault is simply the product of the phase current and line impedance. However, the current in the fault loop depends on the number of earthing points, the method of earthing and sequence impedances of the fault loop. Unless these factors are taken into account, the impedance measurement will be incorrect. The voltage drop to the fault is the sum of the sequence voltage drops between the relaying point and the fault. The voltage drop to the fault and current in the fault loop are:

and the residual current I’N at the relaying point is given by:

where I’a, I’b, I’c are the phase currents at the relaying point. From the above expressions, the voltage at therelaying point can be expressed in terms of:

1. the phase currents at the relaying point,2. the ratio of the transmission line zero sequence to positive sequence

impedance, K, (=ZL0/ZL1),3. the transmission line positive sequence impedance

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Figure 20: Effect of infeed and earthing arrangements on earth fault distance measurement

The voltage appearing at the relaying point, as previously me ntioned, varies with the number of infeeds, the method of system earthing and the position of the relay relative to the infeed and earthing points in the system. Figure 20 illustrates the three possible arrangements that can occur in practice with a single infeed. In Figure 20(a), the healthy phase currents are zero, so that the phase currents Ia, Ib and Ic have a 1-0-0 pattern. The impedance seen by a relay comparing Ia and Va is:

In Figure 20(b), the currents entering the fault from the relay branch have a 2-

1-1 distribution, so:

Z=ZL1

In Figure 20(c), the phase currents have a 1-1-1 distribution, and hence:

Z=KZL1

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If there were infeeds at both ends of the line, the impedance measured would be a superposition of any two of the above examples, with the relative magnitudes of the infeeds taken into account.

This analysis shows that the relay can only measure an

impedance which is independent of infeed and

earthing arrangements if a proportion of the residual current In=Ia+Ib+Ic is

added to the phase current Ia. This technique is known as ‘residual

compensation’.

Most distance relays compensate for the earth fault conditions by using an additional replica impedance ZN within the measuring circuits. Whereas the phase replica impedance Z1 is fed with the phase current at the relaying point, ZN is fed with the full residual current. The value of ZN is adjusted so that for a fault at the reach point, the sum of the voltages developed across Z1 and ZN

equals the measured phase to neutral voltage in the faulted phase.

The required setting for ZN can be determined by considering an earth fault at the reach point of the relay. This is illustrated with reference to the A-N fault with single earthing point behind the relay as in Figure 20(a).

Voltage supplied from the VT’s:

= I1(Z1+Z2+Z0) = I1(2Z1+Z0)

Voltage across the replica impedances:

= IaZ1+INZN

= Ia(Z1+ZN)

= 3I1(Z1+ZN)

Hence, the required setting of ZN for balance at the reach point is given by equating the above two expressions:

With the replica impedance set to earth fault measuring elements

will measure the fault impedance correctly, irrespective of the number of

infeeds and earthing points on the system.

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10 DISTANCE RELAY APPLICATION PROBLEMS

Distance relays may suffer from a number of difficulties in their application. Many of them have been overcome in the latest numerical relays. Nevertheless, an awareness of the problems is useful where a protection engineer has to deal with older relays that are already installed and not due for replacement.

10.1 Minimum Voltage at Relay Terminals

To attain their claimed accuracy, distance relays that do not employ voltage memory techniques require a minimum voltage at the relay terminals under fault conditions. This voltage should be declared in the data sheet for the relay. With knowledge of the sequence impedances involved in the fault, or alternatively the fault MVA, the system voltage and the earthing arrangements, it is possible to calculate the minimum voltage at the relay terminals for a fault at the reach point of the relay. It is then only necessary to check that the minimum voltage for accurate reach measurement can be attained for a given application. Care should be taken that both phase and earth faults are considered.

10.2 Minimum Length of Line

To determine the minimum length of line that can be protected by a distance relay, it is necessary to check first that any minimum voltage requirement of the relay for a fault at the Zone 1 reach is within the declared sensitivity for the relay. Secondly, the ohmic impedance of the line (referred if necessary to VT/CT secondary side quantities) must fall within the ohmic setting range for Zone 1 reach of the relay. For very short lines and especially for cable circuits, it may be found that the circuit impedance is less than the minimum setting range of the relay. In such cases, an alternative method of protection will be required.

A suitable alternative might be current differential protection, as the line length will probably be short enough for the cost-effective provision of a high bandwidth communication link between the relays fitted at the ends of the protected circuit. However, the latest numerical distance relays have a very wide range of impedance setting ranges and good sensitivity with low levels of relaying voltage, so such problems are now rarely encountered. Application checks are still essential, though. When considering earth faults, particular care must be taken to ensure that the appropriate earth fault loop impedance is used in the calculation.

10.3 Under-Reach - Effect of Remote Infeed

A distance relay is said to under-reach when the impedance presented to it is apparently greater than theimpedance to the fault. Percentage under-reach is defined as:

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where:ZR = intended relay reach (relay reach setting)ZF = effective reach

The main cause of under reaching is the effect of fault current infeed at remote busbars. This is best illustrated by an example.

Figure 21: Effect on distance relays of infeed at the remote busbar

In Figure 21, the relay at A will not measure the correct impedance for a fault on line section ZC due to current infeed IB. Consider a relay setting of ZA+ZC. For a fault at point F, the relay is presented with an impedance

So, for relay balance:

Therefore the effective reach is

It is clear from Equation 11.8 that the relay will under reach. It is relatively easy to compensate for this by increasing the reach setting of the relay, but care has to be taken. Should there be a possibility of the remote infeed being reduced or zero, the relay will then reach further than intended. For example, setting Zone 2 to reach a specific distance into an adjacent line section under parallel circuit conditions may mean that Zone 2 reaches beyond the Zone 1 reach of the adjacent line protection under single circuit operation. If IB=9IA and the relay reach is set to see faults at F, then in the absence of the remote infeed, the relay effective setting becomes ZA+10ZC. Care should also be

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taken that large forward reach settings will not result in operation of healthy phase relays for reverse earth faults, see Section 10.5.

10.4 Over-Reach

A distance relay is said to over-reach when the apparent impedance presented to it is less than the impedance to the fault.

Percentage over-reach is defined by the equation:

where:ZR = relay reach settingZF = effective reach

An example of the over-reaching effect is when distance relays are applied on parallel lines and one line is taken out of service and earthed at each end.

10.5 Forward Reach Limitations

There are limitations on the maximum forward reach setting that can be applied to a distance relay. For example, with reference to Figure 6, Zone 2 of one line section should not reach beyond the Zone 1 coverage of the next line section relay. Where there is a link between the forward reach setting and the relay resistive coverage (e.g. a Mho Zone 3 element), a relay must not operate under maximum load conditions. Also, if the relay reach is excessive, the healthy phase-earth fault units of some relay designs may be prone to operation for heavy reverse faults. This problem only affected older relays applied to three-terminal lines that have significant line section length asymmetry. A number of the features offered with modern relays can eliminate this problem.

10.6 Power Swing Blocking

Power swings are variations in power flow that occur when the internal voltages of generators at different points of the power system slip relative to each other. The changes in load flows that occur as a result of faults and their subsequent clearance are one cause of power swings. A power swing may cause the impedance presented to a distance relay to move away from the normal load area and into the relay characteristic. In the case of a stable power swing it is especially important that the distance relay should not trip in order to allow the power system to return to a stable conditions. For this reason, most distance protection schemes applied to transmission systems have a power swing blocking facility available. Different relays may use different principles for detection of a power swing, but all involve recognising that the movement of the measured impedance in relation to the relay measurement characteristics is at a rate that is significantly less than the rate of change that occurs during fault conditions. When the relay detects such a condition, operation of the relay elements can be blocked. Power swing

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blocking may be applied individually to each of the relay zones, or on an all zones applied/inhibited basis, depending on the particular relay used. Various techniques are used in different relay designs to inhibit power swing blocking in the event of a fault occurring while a power swing is in progress. This is particularly important, for example, to allow the relay to respond to a fault that develops on a line during the dead time of a single pole auto reclose cycle. Some Utilities may designate certain points on the network as split points, where the network should be split in the event of an unstable power swing or poleslipping occurring. A dedicated power swing tripping relay may be employed for this purpose (see Section 7.8). Alternatively, it may be possible to achieve splitting by strategically limiting the duration for which the operation a specific distance relay is blocked during power swing conditions.

10.7 Voltage Transformer Supervision

Fuses or sensitive miniature circuit breakers normally protect the secondary wiring between the voltage transformer secondary windings and the relay terminals. Distance relays having:

a. self-polarised offset characteristics encompassing the zero impedance point of the R/X diagram

b. sound phase polarisationc. voltage memory polarization

may maloperate if one or more voltage inputs are removed due to operation of these devices.

For these types of distance relay, supervision of the voltage inputs is recommended. The supervision may be provided by external means, e.g. separate voltage supervision circuits, or it may be incorporated into the distance relay itself. On detection of VT failure, tripping of the distance relay can be inhibited and/or an alarm is given. Modern distance protection relays employ voltage supervision that operates from sequence voltages and currents. Zero or negative sequence voltages and corresponding zero or negative sequence currents are derived. Discrimination between primary power system faults and wiring faults or loss of supply due to individual fuses blowing or MCB’s being opened is obtained by blocking the distance protection only when zero or negative sequence voltage is detected without the presence of zero or negative sequence current. This arrangement will not detect the simultaneous loss of all three voltages and additional detection is required that operates for loss of voltage with no change in current, or a current less than that corresponding to the three phase fault current under minimum fault infeed conditions. If fast-acting miniature circuit breakers are used to protect the VT secondary circuits, contacts from these may be used to inhibit operation of the distance protection elements and prevent tripping.

11 OTHER DISTANCE RELAY FEATURES

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A modern digital or numerical distance relay will often incorporate additional features that assist the protection engineer in providing a comprehensive solution to the protection requirements of a particular part of a network.

Fault Location Instantaneous Overcurrent Protection Tee’d feeder protection Alternative setting groups CT supervision Check synchronizer Auto0reclose CB state monitoring CB condition monitoring CB control Measurement of voltages, currents, etc. Event recorder Disturbance recorder CB failure detection/ logic Directional/ Non-directional phase fault overcurrent protection (backup

to distance protection) Directional/ Non-directional earth fault overcurrent protection (backup to

distance protection) Negative sequence protection Under/ Overvoltage Protection Stub-bus Protection Broken conductor detection User-programmable scheme logic

12 DISTANCE RELAY APPLICATION EXAMPLE

The system diagram shown in Figure 22 shows a simple 230kV network. The following example shows the calculations necessary to apply three-zone distance protection to the line interconnecting substations ABC and XYZ. All relevant data for this exercise are given in the diagram. The MiCOM P441 relay with quadrilateral characteristics is considered in this example. Relay parameters used in the example are listed in Table 2. Calculations are carried out in terms of primary system impedances in ohms, rather than the traditional practice of using secondary impedances. With numerical relays, where the CT and VT ratios may be entered as parameters, the scaling between primary and secondary ohms can be performed by the relay. This simplifies the example by allowing calculations to be carried out in primary quantities and eliminates considerations of VT/CT ratios.

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Figure 22: Example network for distance relay setting calculation

For simplicity, it is assumed that only a conventional 3-zone distance protection is to be set and that there is no teleprotection scheme to be considered. In practice, a teleprotection scheme would normally be applied to a line at this voltage level.

12.1 Line Impedance

The line impedance is:

ZL = (0.089 + j0.476) x 100 = 8.9 + j47.6Ω = 48.42 ∠79.410Ω

Use values of 48.42Ω (magnitude) and 800 (angle) as nearest settable values.

12.2 Residual Compensation

The relays used are calibrated in terms of the positive sequence impedance of the protected line. Since the zero sequence impedance of the line between substations ABC and XYZ is different from the positive sequence impedance, the impedance seen by the relay in the case of an earth fault, involving the passage of zero sequence current, will be different to that seen for a phase fault.

Hence, the earth fault reach of the relay requires zero sequence compensation (see Section 9.2).

For the relay used, this adjustment is provided by the residual (or neutral) compensation factor KZ0, set equal to:

For each of the transmission lines:

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12.3 Zone 1 Phase Reach

The required Zone 1 reach is 80% of the line impedance.

Therefore,

12.4 Zone 2 Phase Reach

Ideally, the requirements for setting Zone 2 reach are:

1. at least 120% of the protected line2. less than the protected line + 50% of the next line

Sometimes, the two requirements are in conflict. In this case, both requirements can be met. A setting of thewhole of the line between substations ABC and XYZ, plus 50% of the adjacent line section to substation PQR is used. Hence, Zone 2 reach:

Use 62.95∠800 Ω nearest available setting.

12.5 Zone 3 Phase Reach

Zone 3 is set to cover 120% of the sum of the lines between substations ABC and PQR, provided this does not result in any transformers at substation XYZ being included. It is assumed that this constraint is met. Hence, Zone 3 reach:

Use a setting of 83.27∠80 0Ω, nearest available setting.

12.6 Zone Time Delay Settings

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Proper co-ordination of the distance relay settings with those of other relays is required. Independent timers are available for the three zones to ensure this. For Zone 1, instantaneous tripping is normal. A time delay is used only in cases where large d.c. offsets occur and old circuit breakers, incapable of breaking the instantaneous d.c. component, are involved. The Zone 2 element has to grade with the relays protecting the line between substations XYZ and PQR since the Zone 2 element covers part of these lines. Assuming that this line has distance, unit or instantaneous high-set overcurrent protection applied, the time delay required is that to cover the total clearance time of the downstream relays. To this must be added the reset time for the Zone 2 element following clearance of a fault on the adjacent line, and a suitable safety margin. A typical time delay is 350ms, and the normal range is 200-500ms. The considerations for the Zone 3 element are the same as for the Zone 2 element, except that the downstream fault clearance time is that for the Zone 2 element of a distance relay or IDMT overcurrent protection. Assuming distance relays are used, a typical time is 800ms. In summary:

TZ1 = 0ms (instantaneous)TZ2 = 250msTZ3 = 800ms

12.7 Phase Fault Resistive Reach Settings

With the use of a quadrilateral characteristic, the resistive reach settings for each zone can be set independently of the impedance reach settings. The resistive reach setting represents the maximum amount of additional fault resistance (in excess of the line impedance) for which a zone will trip, regardless of the fault within the zone.

Two constraints are imposed upon the settings, as follows:

i) it must be greater than the maximum expected phase-phase fault resistance (principally that of the fault arc)

ii) it must be less than the apparent resistance measured due to the heaviest load on the line

The minimum fault current at Substation ABC is of the order of 1.8kA, leading to a typical arc resistance Rarc using the van Warrington formula of 8Ω. Using the current transformer ratio as a guide to the maximum expected load current, the minimum load impedance Zlmin will be 130Ω. Typically, the resistive reaches will be set to avoid the minimum load impedance by a 40% margin for the phase elements, leading to a maximum resistive reach setting of 78Ω.

Therefore, the resistive reach setting lies between 8Ω and 78Ω. Allowance should be made for the effects of any remote fault infeed, by using the maximum resistive reach possible. While each zone can have its own resistive reach setting, for this simple example they can all be set equal. This need not always be the case, it

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depends on the particular distance protection scheme used and the need to include Power Swing Blocking. Suitable settings are chosen to be 80% of the load resistance:

R3ph = 78ΩR2ph = 78ΩR1ph = 78Ω

12.8 Earth Fault Impedance Reach Settings

By default, the residual compensation factor as calculated in Section 12.2 is used to adjust the phase fault reach setting in the case of earth faults, and is applied to all zones.

12.9 Earth Fault Resistive Reach Settings

The margin for avoiding the minimum load impedance need only be 20%. Hence the settings are:

R3G = 104ΩR2G = 104ΩR1G = 104Ω

This completes the setting of the relay. Table 2 also shows the settings calculated.-o0o-

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TABLE OF CONTENTS

No. Topic

1 Introduction

2 Zone 1 Extension Scheme

3 Transfer Tripping Schemes

4 Blocking Over-Reaching Schemes

5 Directional Comparison Unblocking Schemes

6 Comparison of Transfer Trip and Blocking Relaying Schemes

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DISTANCE PROTECTION SCHEMES

1. INTRODUCTION

Conventional time-stepped distance protection is illustrated in Figure 12.1. One of the main disadvantages of this scheme is that the instantaneous Zone 1 protection at each end of the protected line cannot be set to cover the whole of the feeder length and is usually set to about 80%. This leaves two 'end zones', each being about 20% of the protected feeder length. Faults in these zones are cleared in Zone 1 time by the protection at one end of the feeder and in Zone 2 time (typically 0.25 to 0.4 seconds) by the protection at the other end of the feeder.

Fig. 1 Conventional Distance Scheme

This situation cannot be tolerated in some applications, for two main reasons:

a. faults remaining on the feeder for Zone 2 time may cause the system to become unstable

b. where high-speed auto-reclosing is used, the non-simultaneous opening of the circuit breakers at both ends of the faulted section results in no 'dead time' during the auto-reclose cycle for the fault to be extinguished and for ionised gases to clear. This results in the possibility that a transient fault will cause permanent lockout of the circuit breakers at each end of the line section.

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Even where instability does not occur, the increased duration of the disturbance may give rise to power quality problems, and may result in increased plant damage.

Unit schemes of protection that compare the conditions at the two ends of the feeder simultaneously positively identify whether the fault is internal or external to the protected section and provide high-speed protection for the whole feeder length. This advantage is balanced by the fact that the unit scheme does not provide the back up protection for adjacent feeders given by a distance scheme.

The most desirable scheme is obviously a combination of the best features of both arrangements, that is, instantaneous tripping over the whole feeder length plus back-up protection to adjacent feeders. This can be achieved by interconnecting the distance protection relays at each end of the protected feeder by a communications channel. Communication techniques are described in detail in Chapter 8.

The purpose of the communications channel is to transmit information about the system conditions from one end of the protected line to the other, including requests to initiate or prevent tripping of the remote circuit breaker. The former arrangement is generally known as a 'transfer tripping scheme' while the latter is generally known as a 'blocking scheme'. However, the terminology of the various schemes varies widely, according to local custom and practice.

2. ZONE 1 EXTENSION SCHEME (Z1X SCHEME)

This scheme is intended for use with an auto-reclose facility, or where no communications channel is available, or the channel has failed. Thus it may be used on radial distribution feeders, or on interconnected lines as a fallback when no communications channel is available, e.g. due to maintenance or temporary fault. The scheme is shown in Figure 12.2.

The Zone 1 elements of the distance relay have two settings. One is set to cover 80% of the protected line length as in the basic distance scheme. The other, known as 'Extended Zone 1'or 'Z1X', is set to overreach the protected line, a setting of 120% of the protected line being common. The Zone 1 reach is normally controlled by the Z1X setting and is reset to the basic Zone 1 setting when a command from the auto-reclose relay is received.

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Fig. 2 Zone 1 Extension Scheme

On occurrence of a fault at any point within the Z1X reach, the relay operates in Zone 1 time, trips the circuit breaker and initiates auto-reclosure. The Zone 1 reach of the distance relay is also reset to the basic value of 80%, prior to the auto-reclose closing pulse being applied to the breaker. This should also occur when the auto-reclose facility is out of service. Reversion to the Z1X reach setting occurs only at the end of the reclaim time. For interconnected lines, the Z1X scheme is established (automatically or manually) upon loss of the communications channel by selection of the appropriate relay setting (setting group in a numerical relay). If the fault is transient, the tripped circuit breakers will reclose successfully, but otherwise further tripping during the reclaim time is subject to the discrimination obtained with normal Zone 1 and Zone 2 settings.

The disadvantage of the Zone 1 extension scheme is that external faults within the 1X reach of the relay result in tripping of circuit breakers external to the faulted section, increasing the amount of breaker maintenance needed and needless transient loss of supply to some consumers. This is illustrated in Figure 12.3(a) for a single circuit line where three circuit breakers operate and in Figure 12.3(b) for a double circuit line, where five circuit breakers operate.

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Fig. 3 Performance of Zone 1 Extension Scheme in Conjunction with auto-reclose Relays

3. TRANSFER TRIPPING SCHEMES

A number of these schemes are available, as described below. Selection of an appropriate scheme depends on the requirements of the system being protected.

3.1 Direct Under-reach Transfer Tripping Scheme

The simplest way of reducing the fault clearance time at the terminal that clears an end zone fault in Zone 2 time is to adopt a direct transfer trip or intertrip technique, the logic of which is shown in Figure 4.

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Fig. 4 Logic for Direct under-reach transfer tripping scheme

A contact operated by the Zone 1 relay element is arranged to send a signal to the remote relay requesting a trip. The scheme may be called a 'direct under-reach transfer tripping scheme', 'transfer trip under-reaching scheme', or 'intertripping under-reach distance protection scheme', as the Zone 1 relay elements do not cover the whole of the line.

A fault F in the end zone at end B in Figur 1(a) results in operation of the Zone 1 relay and tripping of the circuit breaker at end B. A request to trip is also sent to the relay at end A. The receipt of a signal at A initiates tripping immediately because the receive relay contact is connected directly to the trip relay. The disadvantage of this scheme is the possibility of undesired tripping by accidental operation or maloperation of signalling equipment, or interference on the communications channel. As a result, it is not commonly used.

3.2 Permissive Under-reach Transfer Tripping (PUP) Scheme

The direct under-reach transfer tripping scheme described above is made more secure by supervising the received signal with the operation of the Zone 2 relay element before allowing an instantaneous trip, as shown in Figure 5.

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Fig. 5 Permissive under-reach transfer tripping scheme

The scheme is then known as a 'permissive under-reach transfer tripping scheme' (sometimes abbreviated as PUP Z2 scheme) or 'permissive under-reach distance protection', as both relays must detect a fault before the remote end relay is permitted to trip in Zone 1 time.

A variant of this scheme, found on some relays, allows tripping by Zone 3 element operation as well as Zone 2, provided the fault is in the forward direction. This is sometimes called the PUP-Fwd scheme.

Time delayed resetting of the 'signal received' element is required to ensure that the relays at both ends of a single-end fed faulted line of a parallel feeder circuit have time to trip when the fault is close to one end. Consider a fault F in a double circuit line, as shown in Figure 6. The fault is close to end A, so there is negligible infeed from end B when the fault at F occurs. The protection at B detects a Zone 2 fault only after the breaker at end A has tripped. It is possible for the Zone 1 element at A to reset, thus removing the permissive signal to B and causing the 'signal received' element at B to reset before the Zone 2 unit at end B operates. It is therefore necessary to delay the resetting of the 'signal received' element to ensure high speed tripping at end B.

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Fig. 6 PUP Scheme Single end fed close-up fault on double circuit line

The PUP schemes require only a single communications channel for two-way signalling between the line ends, as the channel is keyed by the under-reaching Zone 1 elements.

When the circuit breaker at one end is open, or there is a weak infeed such that the relevant relay element does not operate, instantaneous clearance cannot be achieved for end-zone faults near the 'breaker open' terminal unless special features are included, as detailed in section 3.5.

3.3 Permissive Under-reaching Acceleration SchemeThis scheme is applicable only to zone switched distance relays that share the same measuring elements for both Zone 1 and Zone 2. In these relays, the reach of the measuring elements is extended from Zone 1 to Zone 2 by means of a range change signal immediately, instead of after Zone 2 time. It is also called an 'accelerated underreach distance protection scheme'.

The under-reaching Zone 1 unit is arranged to send a signal to the remote end of the feeder in addition to tripping the local circuit breaker. The receive relay contact is arranged to extend the reach of the measuring element from Zone 1 to Zone 2. This accelerates the fault clearance at the remote end for faults that lie in the region between the Zone 1 and Zone 2 reaches. The scheme is shown in Figure 17. Modern distance relays do not employ switched measuring elements, so the scheme is likely to fall into disuse.

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Fig. 7 Permissive under reaching acceleration scheme

3.4 Permissive Over-Reach Transfer Tripping (POP) Scheme

In this scheme, a distance relay element set to reach beyond the remote end of the protected line is used to send an intertripping signal to the remote end. However, it is essential that the receive relay contact is monitored by a directional relay contact to ensure that tripping does not take place unless the fault is within the protected section; see Figure 8. The instantaneous contacts of the Zone 2 unit are arranged to send the signal, and the received signal, supervised by Zone 2operation, is used to energise the trip circuit. The scheme is then known as a 'permissive over-reach transfer tripping scheme' (sometimes abbreviated to 'POP'), 'directional comparison scheme', or 'permissive overreach distance protection scheme'.

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Fig. 8 Permissive Over-reach Transfer Scheme

Since the signalling channel is keyed by over-reaching Zone 2 elements, the scheme requires duplex communication channels - one frequency for each direction of signalling.

If distance relays with mho characteristics are used, the scheme may be more advantageous than the permissive under-reaching scheme for protecting short lines, because the resistive coverage of the Zone 2 unit may be greater than that of Zone 1. To prevent operation under current reversal conditions in a parallel feeder circuit, it is necessary to use a current reversal guard timer to inhibit the tripping of the forward Zone 2 elements. Otherwise maloperation of the scheme may occur under current reversal conditions. It is necessary only when the Zone 2 reach is set greater than 150% of the protected line impedance.

Fig. 9 Current reversal guard logic permissive over-reach scheme

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The timer is used to block the permissive trip and signal send circuits as shown in Figure 9. The timer is energised if a signal is received and there is no operation of Zone 2 elements. An adjustable time delay on pick-up (tp) is usually set to allow instantaneous tripping to take place for any internal faults, taking into account a possible slower operation of Zone 2. The timer will have operated and blocked the 'permissive trip' and 'signal send' circuits by the time the current reversal takes place.

The timer is de-energised if the Zone 2 elements operate or the 'signal received' element resets. The reset time delay (td) of the timer is set to cover any overlap in time caused by Zone 2 elements operating and the signal resetting at the remote end, when the current in the healthy feeder reverses. Using a timer in this manner means that no extra time delay is added in the permissive trip circuit for an internal fault.

The above scheme using Zone 2 relay elements is often referred to as a POP Z2 scheme. An alternative exists that uses Zone 1 elements instead of Zone 2, and this is referred to as the POP Z1 scheme.

3.5 Weak Infeed Conditions

In the standard permissive over-reach scheme, as with the permissive under-reach scheme, instantaneousclearance cannot be achieved for end-zone faults under weak infeed or breaker open conditions. To overcome this disadvantage, two possibilities exist.

The Weak Infeed Echo feature available in some protection relays allows the remote relay to echo the trip signal back to the sending relay even if the appropriate remote relay element has not operated. This caters for conditions of the remote end having a weak infeed or circuit breaker open condition, so that the relevant remote relay element does not operate. Fast clearance for these faults is now obtained at both ends of the line. The logic is shown in Figure 10. A time delay (T1) is required in the echo circuit to prevent tripping of the remote end breaker when the local breaker is tripped by the busbar protection or breaker fail protection associated with other feeders connected to the busbar. The time delay ensures that the remote end Zone 2 element will reset by the time the echoed signal is received at that end.

Figure 10 Weak Infeed Echo logic circuit

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Signal transmission can take place even after the remote end breaker has tripped. This gives rise to the possibility of continuous signal transmission due to lock-up of both signals. Timer T2 is used to prevent this. After this time delay, 'signal send' is blocked.

A variation on the Weak Infeed Echo feature is to allow tripping of the remote relay under the circumstances described above, providing that an undervoltage condition exists, due to the fault. This is known as the Weak Infeed Trip feature and ensures that both ends are tripped if the conditions are satisfied.

4 BLOCKING OVER-REACHING SCHEMES

The arrangements described so far have used the signalling channel(s) to transmit a tripping instruction. If the signalling channel fails or there is no Weak Infeed feature provided, end-zone faults may take longer to be cleared.

Blocking over-reaching schemes use an over-reaching distance scheme and inverse logic. Signalling is initiated only for external faults and signalling transmission takes place over healthy line sections. Fast fault clearance occurs when no signal is received and the over-reaching Zone 2 distance measuring elements looking into the line operate. The signalling channel is keyed by reverse-looking distance elements (Z3in the diagram, though which zone is used depends on the particular relay used). An ideal blocking scheme is shown in Figure 11.

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Fig. 11 Ideal Distance Protection Blocking Scheme

The single frequency signalling channel operates both local and remote receive relays when a block signal is initiated at any end of the protected section.

4.1 Practical Blocking Schemes

A blocking instruction has to be sent by the reverse-looking relay elements to prevent instantaneous tripping of the remote relay for Zone 2 faults external to the protected section. To achieve this, the reverse-looking elements and the signalling channel must operate faster than the forward-looking elements. In practice, this is seldom the case and to ensure discrimination, a short time delay is generally introduced into the blocking mode trip circuit. Either the Zone 2 or Zone 1 element can be used as the forward-looking element, giving rise to two variants of the scheme.

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4.1.1 Blocking over-reaching protection scheme using Zone 2 element

This scheme (sometimes abbreviated to BOP Z2) is based on the ideal blocking scheme of Figure 11, but has the signal logic illustrated in Figure 12. It is also known as a 'directional comparison blocking scheme' or a 'blocking over-reach distance protection scheme'.

Fig. 12 Signal logic for BOP Z2 Scheme

Operation of the scheme can be understood by considering the faults shown at F1, F2 and F3 in Figure 11 along with the signal logic of Figure 12.

A fault at F1 is seen by the Zone 1 relay elements at both ends A and B; as a result, the fault is cleared instantaneously at both ends of the protected line. Signalling is controlled by the Z3 elements looking away from the protected section, so no transmission takes place, thus giving fast tripping via the forward-looking Zone 1 elements.

A fault at F2 is seen by the forward-looking Zone 2 elements at ends A and B and by the Zone 1 elements at End B. No signal transmission takes place, since the fault is internal and the fault is cleared in Zone 1 time at end B and after the short time lag (STL) at end A.

A fault at F3 is seen by the reverse-looking Z3 elements at end Band the forward looking Zone 2 elements at end A . The Zone 1 relay elements at end B associated with line section B – C would normally clear the fault at F3. To prevent the Z2 elements at end A from tripping, the reverse-looking Zone 3 elements at end B send a blocking signal to end A . If the fault is not cleared instantaneously by the protection on line section B-C, the trip signal will be given at end B for section A – B after the Z3 time delay.

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The setting of the reverse-looking Zone 3 elements must be greater than that of the Zone 2 elements at the remote end of the feeder, otherwise there is the possibility of Zone 2 elements initiating tripping and the reverse looking Zone 3 elements failing to see an external fault. This would result in instantaneous tripping for an external fault. When the signalling channel is used for a stabilising signal, as in the above case, transmission takes place over a healthy line section if power line carrier is used. The signalling channel should then be more reliable when used in the blocking mode than in tripping mode.

It is essential that the operating times of the various relays be skilfully co-ordinated for all system conditions, so that sufficient time is always allowed for the receipt of a blocking signal from the remote end of the feeder.If this is not done accurately, the scheme may trip for an external fault or alternatively, the end zone tripping times may be delayed longer than is necessary.

If the signalling channel fails, the scheme must be arranged to revert to conventional basic distance protection. Normally, the blocking mode trip circuit is supervised by a 'channel-in-service' contact so that theblocking mode trip circuit is isolated when the channel is out of service, as shown in Figure 12.

In a practical application, the reverse-looking relay elements may be set with a forward offset characteristic to provide back-up protection for busbar faults after the zone time delay. It is then necessary to stop the blocking signal being sent for internal faults. This is achieved by making the 'signal send' circuit conditional upon non-operation of the forward-looking Zone 2 elements, as shown in Figure 13.

Fig. 13 Blocking Scheme using Reverse Looking Relays with Offset

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Blocking schemes, like the permissive over-reach scheme, are also affected by the current reversal in the healthy feeder due to a fault in a double circuit line. If current reversal conditions occur, as described in section 9.9, it may be possible for the maloperation of a breaker on the healthy line to occur. To avoid this, the resetting of the 'signal received' element provided in the blocking scheme is time delayed.

The timer with delayed resetting (td) is set to cover the time difference between the maximum resetting time of reverse-looking Zone 3 elements and the signalling channel. So, if there is a momentary loss of the blocking signal during the current reversal, the timer does not have time to reset in the blocking mode trip circuit and no false tripping takes place.

4.1.2 Blocking over-reaching protection scheme using Zone 1 element

This is similar to the BOP Z2 scheme described above, except that an over-reaching Zone 1 element is used in the logic, instead of the Zone 2 element. It may also be known as the BOP Z1 scheme.

4.2 Weak Infeed Conditions

The protection at the strong infeed terminal will operate for all internal faults, since a blocking signal is not received from the weak infeed terminal end. In the case of external faults behind the weak infeed terminal, the reverse-looking elements at that end will see the fault current fed from the strong infeed terminal and operate, initiating a block signal to the remote end. The relay at the strong infeed end operates correctly without the need for any additional circuits. The relay at the weak infeed end cannot operate for internal faults, and so tripping of that breaker is possible only by means of direct intertripping from the strong source end.

5 DIRECTIONAL COMPARISON UNBLOCKING SCHEME

The permissive over-reach scheme described in Section 12.3.4 can be arranged to operate on a directional comparison unblocking principle by providing additional circuitry in the signalling equipment. In this scheme (also called a 'deblocking overreach distance protection scheme'), a continuous block (or guard) signal is transmitted. When the over-reaching distance elements operate, the frequency of the signal transmitted is shifted to an 'unblock' (trip) frequency. The receipt of the unblock frequency signal and the operation of over-reaching distance elements allow fast tripping to occur for faults within the protected zone. In principle, the scheme is similar to the permissive over-reach scheme.

The scheme is made more dependable than the standard permissive over-reach scheme by providing additional circuits in the receiver equipment. These allow tripping to take place for internal faults even if the transmitted unblock signal is short-circuited by the fault. This is achieved by allowing aided tripping for a short time interval, typically 100 to 150 milliseconds, after the loss of both the block and the unblock frequency signals. After this time

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interval, aided tripping is permitted only if the unblock frequency signal is received.

This arrangement gives the scheme improved security over a blocking scheme, since tripping for external faults is possible only if the fault occurs within the above time interval of channel failure. Weak Infeed terminal conditions can be catered for by the techniques detailed in Section 3.5.

In this way, the scheme has the dependability of a blocking scheme and the security of a permissive over-reach scheme. This scheme is generally preferred when power line carrier is used, except when continuous transmission of signal is not acceptable.

6 COMPARISON OF TRANSFER TRIP AND BLOCKING RELAYING SCHEMES

On normal two-terminal lines the main deciding factors in the choice of the type of scheme, apart from the reliability of the signalling channel previously discussed, are operating speed and the method of operation of the system. Table1 compares the important characteristics of the various types of scheme.

Criterion Transfer tripping scheme

Blocking scheme

Speed of operation Fast Not as fastSpeed with in-service testing

Slower As fast

Suitable for auto reclose Yes YesSecurity against maloperation due toCurrent reversal Special features

requiredSpecial features required

Loss of Communications Poor GoodWeek infeed/ Open CB Special features

requiredSpecial features required

Table 1

Modern digital or numerical distance relays are provided with a choice of several schemes in the same relay. Thus scheme selection is now largely independent of relay selection, and the user is assured that a relay is available with all the required features to cope with changing system conditions.

****

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TABLE OF CONTENTS

No. Topic

1 Introduction

2 Basic Concepts

3 Distribution of Generation Resources in India

4 Coal-Fired Thermal Power Generation

5 Combined Cycle Gas Power Generation

6 Nuclear Power Generation

7 Hydro Generation

8 Wind Energy Generation

9 Expectations from a Generator connected to the Grid

10 Important Terms and definitions

11 References

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1.INTRODUCTIONElectric power generation is simply the conversion of energy from one form to another. The major sources for power generation are hydro, fossil, nuclear, wind solar, geothermal, biomass, municipal waste etc. Each type of generation technology has its own complexity. However from the perspective of the grid, one needs to focus mainly on the process, conversion efficiency, variable cost, peaking capability, maximum continuous rating under different conditions, reactive capability, loading restrictions, ramp-up/ramp-down rates, start-up time-cold/hot. Besides, the impact of voltage and frequency on the generator output also needs to be understood.

2.BASIC CONCEPTSThe fundamental laws that govern electric power generation are the Faraday’s law and the Ampere’s law. Faraday’s law states that electromotive force (EMF) produced around a closed path is proportional to the rate of change of the magnetic flux through any surface bounded by that path. In practice, this means that an electric current will be induced in any closed circuit when the magnetic flux through a surface bounded by the conductor changes. This applies whether the field itself changes in strength or the conductor is moved through it. The Ampere’s law states that the magnetic field in space around an electric current is proportional to the electric current which serves as its source, just as the electric field in space is proportional to the charge which serves as its source.

PRIME MOVERSVirtually all generators have armature coils mounted on stationary housing called the stators, where voltage (EMF) is produced due to the rotating magnetic field produced by the rotor [Faraday’s law]. The amplitude of the generator’s output voltage can be changed by changing the strength of the rotor’s magnetic field [Ampere’s and Lenz’s law]. The mechanical means of turning the generator’s rotor is called the prime mover. The source of energy for prime mover could be fossil fuels (coal, gas, oil), nuclear, geothermal, solar, hydro, wind etc.

SYNCHRONOUS GENERATOR CAPABILITY CURVESynchronous generators are rated in terms of maximum MVA output at a specified voltage and power factor (usually 0.85 or 0.9 p.f. lagging) which they can carry without over-heating.

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Figure 1: Typical capability curve of a synchronous generatorThe active power is limited by the prime mover capability to a value within Synchronous generators are rated in terms of the maximum MVA output at a specified voltage and power factor (usually 0.85 or 0.9 lagging) which they can carry continuously without overheating. The active power output is limited by the prime mover capability to a value within the MVA rating. The continuous reactive power output capability is limited by three considerations: armature current limit, field current limit, and end region heating limit. A typical generator capability curve is shown in figure-1.

3. DISTRIBUTION OF GENERATION RESOURCES IN INDIAThe distribution of generation resources in India is shown in the figure-2.

NR

WR

SR

ER

NER

Ennore

Kudankulam

Kayamkulam

Partabpur

Talcher/Ib Valley

Vindhyachal

Korba

LEGEND

Coal

Hydro

Lignite

Coastal

Nuclear

Vizag

Simhadri

Kaiga

Tarapur

Mangalore

Krishnapatnam

RAPP

SIKKIM

CHICKEN NECK

Cuddalore

SRI LANKACOLOMBO

NEPALBHUTAN

DESHBANGLA

South Madras

Pipavav

Generation Load-Centre

Kolkata

Bhubaneswar

Patna

Lucknow

Delhi

Mumbai

Chennai

Bangalore

Bhopal

Guwahati

Jammu

Ludhiana

Jaipur

Gandhinagar

Indore

Raipur

Thiruvananthapuram

Kozhikode

Hyderabad Coal

Hydro

Figure 2: Distribution of generation resources in India

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COAL–FIRED THERMAL POWER GENERATIONIn a coal fired thermal power station, the heat produced by burning the pulverised coal transforms the water into high pressure steam, which is then superheated to about 550o C. This superheated, high-pressure steam is then passed through the turbine, which converts steam energy into rotating mechanical energy. The steam turbine drives the generator which converts the mechanical energy into electrical energy. The steam leaving the turbine is passed through a condenser, where it is converted back to water.

Figure 3: Simplified Steam power plant cycleThis water, known as condensate, is then pumped back into the boiler to complete the cycle. This process improves the efficiency of the steam cycle.The main parameters to be controlled in a thermal generating unit are turbine speed/MW, steam pressure, steam temperature, drum level, furnace draft, air-fuel ratio, condenser level, de-aerator level and voltage /MVAr.Large steam turbine generators are sensitive to rapid temperature and pressure changes. This means that they may take some hours to start up a unit from a cold condition, bring it up to speed, synchronize, and to load to maximum. However, when online, they can typically respond to load changes in the order of tens of MW per minute without damage.The overall efficiency of a fossil-fired power plant is 30-35 %. Oil support may be required below about 60% MCR, depending on which mills are operating. The turbine blades overheat if load is less than 20% MCR. Start-ups and controlled shut-offs require a few hours each, considerable operator effort &

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alertness, extra cost and reduce life. Daily shut-off are not recommended, but units with high fuel cost can be boxed up by turn.

IMPORTANT COMPONENTS OF A STEAM POWER PLANTA brief description of the important components of a steam power plant is given below.S No. Component Descriptioni Boiler Used for converting water into steam

at required temperature and pressureii Turbine Turbine converts the thermal energy

of steam into mechanical energy and drives the generator

iii Condenser Placed immediately below the turbine. Serves the purpose of reducing the turbine exhaust pressure and of recovery of boiler feed water

iv Boiler feed pump Provides continuous supply of feed water to boiler at all times at pressures in excess of the boiler pressure

v Governor A device which automatically controls the speed and regulates the output of turbine in all types of power plants. Consists of speed sensitive device

vi Circulating water pump The cooling water requirement in steam generators is large (5-8 litres/m/kW) and the availability of circulating water is essential for continuous operation of a steam plant.

vii Economizer Used for increasing thermal efficiency by causing the heat in exhaust gases to be absorbed by feed water

viii Air heater Used to preheat the air used for combustion in order to raise thermal efficiency by causing air to absorb as much heat as possible from the flue gases. It is installed after Economizer. The hot flue gases pass within the tubes while air is made to pass on the outside over the tubes.

ix Soot Blower Adherence of ash to the heating surface of the boiler can plug the spaces between the water tubes and increase draft resistance to such as extent that the stoppage of boiler for cleaning operations becomes necessary. Soot blowers are used to

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remove the ash adhering to the water tubes during operation periodically.

x Forced draft fan Used to force air into combustion chamber of boiler

xi Induced draft fan Used to provide suction pressure to remove the exhaust gases from the chamber of boiler

xii Bowl mill (Ball Mill) Used to pulverise the coal into powder for sending it to furnace

xiii Dust extraction or precipitating equipment

Used for removal of dust and fly ash from the exhaust gases either mechanically or by a combination of mechanical and electrostatic precipitating equipment.

xiv Feed water treatment Water supplied to Boilers must be of such a purity so as not to cause scale formation, corrosion and accumulation of solids within the boiler drums tubes. The extraction of impurities is done under water treatment plant.

xv Generator cooling Hydrogen cooling is a standard practice in all steam turbine generators above 20 MW. The advantages of hydrogen cooling are high efficiency, increased output, low windage loss and longer life for machine. Hydrogen is used at pressure up to 3kg/cm2.Because of the explosive nature of the hydrogen gas, the pressure and purity of the hydrogen are automatically controlled

xvi Exciters Exciters are used to create magnetic flux in the air gap.

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4.COAL FIRED THERMAL STATIONS IN INDIAThe total installed capacity of coal fired thermal stations in India may be seen from (http://www.cea.nic.in/executive_summary.html). The largest unit size is 660 MW. The major coal fired thermal stations in India are tabulated below.Table 1: Installed Capacity of major thermal power stations in India

S No.

Station State Commissioned Capacity (MW)

1 Singrauli Uttar Pradesh 20002 Korba Chhatisgarh 26003 Ramagundam Andhra

Pradesh2600

4 Farakka West Bengal 21005 Vindhyachal Madhya

Pradesh3260

6 Rihand Uttar Pradesh 20007 Kahalgaon Bihar 23408 NCTPP Dadri Uttar Pradesh 18209 Talcher

KanihaOrissa 3000

10 Unchahar Uttar Pradesh 105011 Simhadri Andhra

Pradesh1500

12 Sipat Chhatisgarh 166013 Anpara Uttar Pradesh 163014 Ropar Punjab 126015 Neyveli-II Tamil Nadu 147016 Suratgarh Rajasthan 150017 Wanakbori Gujarat 147018 Panipat Haryana 136019 Dr. N. Tata

RaoAndhra Pradesh

1760

20 Rayalasema Andhra Pradesh

1050

21 Barkeshwar West Bengal 105022 Mundra Gujarat 198023 Kota Rajasthan 1240

THERMAL GENERATOR TRIPPINGTripping of a thermal unit causes thermal shocks and reduces plant life. A full-load trip of combined cycle unit causes high thermal stresses and reduces GT life by 500 hours.Thus tripping of thermal units should be avoided / prevented as long as possible. The common reasons for outage of thermal units are described in the section below.

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PROBLEMS IN BOILER SIDE THAT MAY CAUSE OUTAGE OF A THERMAL UNIT

a) Drum level high or lowb) Fire out/Flame failure:c) Furnace pressure high/lowd) Induced draft (I.D.) fan outagee) Forced draft (F.D.) fan outagef) Primary air (P.A.) fan outageg) Boiler tube leakages h) Bowl mill/ball mill outagei) Air pre heater (APH) problemj) Bottom ash disposal system (BADS) problem

PROBLEMS IN TURBINE SIDE THAT MAY CAUSE OUTAGE OF A THERMAL UNIT

a) Axial shaft high b) Lube oil pressure lowc) Tripping of circulating water (CW) pumps/low vacuum in condenserd) Steam temperature high/lowe) Steam pressure highf) Boiler feed pump tripg) Problem in main steam valve/control valve/emergency stop valveh) Over speed tripi) Abnormal vibrationsj) Eccentricity highk) Condenser tube leakage/chokingl) Governing system problemm) H.P. heater outagen) Dearerator level low

OUTAGE DUE TO GENERATOR PROBLEMSa) Generator differential protection: This is the main protection for the

stator winding against phase-to-phase faults and trips the generator immediately. Usually an overall differential protection for the generator and generator transformer is provided.

b) Rotor earth fault protection: A single earth fault on the field winding or in the excitation system of a generator is not dangerous to the machine and the unit may be taken out at an opportune time. However a second earth fault will result in a part of the field winding being short circuited resulting in magnetic unbalance of the field system with subsequent mechanical damage to the machine bearings. The unit trips under these conditions.

c) Loss of field protection: Failure of the field system results in the generator operating as an induction generator, drawing magnetizing current from the system. This will result in overloading of the stator and overheating of the rotor and the unit is tripped in case the field supply is not restored within a set time.

d) Negative Sequence protection: Unbalanced loadings on the three phases causes negative sequence current to flow in the stator winding. These result in severe heating of the rotor due to the double frequency

105

currents induced in it. If the negative sequence current exceeds a particular limit, the unit trips after a time delay.

e) Low forward power/reverse power relay: In case the steam supply to the turbine gets cut off and the generator will start acting as a motor. This may result in overheating and distortion of the turbine blades. Unit is set to trip with a time delay.

f) Hydrogen leakage: Unit is set to trip if hydrogen pressure goes below a particular limit.

g) D.M. water conductivity high: Demineralized water is used to cool the stator winding bars. Unit is set to trip in case of low flow or in case when conductivity is above a particular limit.

h) Overfluxing in generator/transformer i) Undervoltage on 6.6 kV auxiliary supply or station supply failure: An

under voltage relay with a time delay is provided to trip the power station 6.6 kV and 415 V auxiliaries whenever the voltage goes below 70%. This results in tripping of the entire power station. This protection is necessary to avoid stalling of the A.C. motors and consequent damage to the power station auxiliaries.

j) Generator transformer outage: Tripping of the generator transformer due to any of the reasons (operation of Buchholz relay, differential protection, winding/oil temperature high, back-up over current and earth fault protection, over fluxing etc.) will result in tripping of the unit.

HOUSE LOAD OPERATIONHouse load operation means that the generating unit is operating in isolation to the grid and generating electric power to cater to its own auxiliaries.

5.COMBINED CYCLE GAS POWER GENERATIONGas turbines, also known as combustion turbines, use combustion products directly. The gaseous products of combustion pass directly through turbine, where the heat energy is converted into rotating mechanical energy. The fuel burned could be natural gas, high speed diesel, naptha etc. The term ‘combined cycle’ implies any heat and power producing process where the prime movers employ more than one working fluid in combination of turbines. The most common and practical form of such plant is the combination of one or more gas turbines with a steam turbine. The combined cycle uses the inherent characteristics of the gas turbine process, where combustion takes place and, following expansion in the turbine, the heat rejected is utilized for steam generation. Typically the steam turbine output will be about 50% of the gas turbine output.

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Figure 4: Simplified combined cycle plant employing one gas turbine and one steam turbine

The overall efficiency of a gas power station is 45-50 %. The efficiency of the Gas Turbine is maximum when it is operating at MCR. The heat rate of the plant remains nearly same up to 80% load and then deteriorates rapidly. Therefore utility operators hesitate to bring down the load to below 80% for sake of efficiency. However the combined cycle plant can easily run at part loads though frequent ramp up and down increases the maintenance requirements. Under low demand conditions, it is advisable to close down one GT in a module and load the remaining units on full load. If required combined cycle power plants may be operated in 2 - shifts may be module-wise by turn. The firing temperature of the gas turbine is the most critical parameter as it has a direct effect on MW, efficiency, life and cost. The maximum continuous rating goes up (down) considerably when ambient temperature goes down (up).COMBINED CYCLE POWER STATIONS IN INDIAThe major combined cycle power stations in India are given in table below

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Table 2: Installed Capacity of major combined cycle power station in India

S No.

Station Commissioned Capacity (MW)

1 Anta 4132 Auraiya 6523 Kawas 6454 Dadri 8175 Jhanor-

Gandhar648

6 Kayamkulam 3507 Faridabad 4308 Ratnagiri 19409 Uran 67210 Pragati 33011 Essar 51512 Gautam 46413 Pragati-II 50014 Peguthan 65515 Sugen 114716 Vemagiri 37017 Kondapalli 350

6.NUCLEAR POWER GENERATIONIn a nuclear plant, the basic cycle is similar to that of a fossil plant- that is, steam is used to run the turbine-generators. However the heat is obtained from the fission of nuclear fuel such as uranium instead of burning fossil fuel. The difference is that the heat necessary to change the water into steam comes from a nuclear reaction-not from burning fossil fuels. The various designs for nuclear generators include the Boiling Water Reactor (BWR) and the Pressurized Water Reactor (PWR).

108

Figure 5: Reactor layout and containment system of Boiling Water ReactorDue to stringent government requirements concerning the safety of nuclear plants, design requirements for a nuclear reactor are far more complicated than for the fossil-fired or hydro units. They are also more complicated to operate, when one considers such items as waste disposal, safety, licensing etc. Nuclear power stations are normally operated as base load plants. The reactor power is controlled by inserting / withdrawing the control rods. The temperature differential of coolant across the reactor is the most critical parameter for stable reactor control.

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Figure 6: Simplified flow diagram of PHWR

NUCLEAR POWER GENERATING STATIONS IN INDIA The list of nuclear power stations in India is given in table below:Table 3: Installed Capacity of nuclear power stations in India

S No.

Reactor type

Commissioned Capacity (MW)

1 TAPS-1&2 BWR 3202 TAPS-3&4 PHWR 10803 RAPS-A PHWR 3004 RAPS-B PHWR 4405 RAPS-C PHWR 4406 MAPS PHWR 4407 KAIGA PHWR 8808 NAPS PHWR 4409 KAPS PHWR 440

REACTOR POISONING The principal nuclear processes occurring during irradiation which affect reactor operation are

1. the burn-up of fissile isotopes2. the build up of transuranic* elements, some of which are fissionable

110

3. the build up of fission products which absorb neutrons to varying degrees

*Transuranic elements are elements with atomic number greater than 92 that do not exist in nature but are produced artificially.

U-235 Te-135 Xe-135 Cs-135 Ba-135

Xenon Production Xenon Destruction

I-135

Figure 7: Production and destruction of XenonXenon (Xe-135) is one such fission product. It has a fairly short half-life but a high neutron absorption capability. The Xenon produced during nuclear fission is destroyed by neutron absorption as well as radioactive decay. During normal operation the production and removal of Xenon is in perfect equilibrium. However when a nuclear reactor is suddenly shutdown, the removal of Xenon (by neutron absorption) is reduced to zero but the production of Xenon by radioactive decay of iodine (one of the fission product) does not immediately reduce and the net result is an increase in xenon level. A peak in xenon level is reached after about ten hours and then decays over two or three days (refer figure below). In order to override the xenon build-up extra reactivity is needed. Without it the reactor may not be capable of achieving criticality and starting up during few days immediately following a reactor shutdown. During grid operation it has been observed that the reactor shut down may be caused by outage of evacuating feeders. From the figure it may be inferred that under such conditions it is important that evacuation is extended within 30 minutes else the reactor would achieve criticality after 36 hours.

Figure 8: Xenon reactivity load

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ISLANDING SCHEME FOR NUCLEAR GENERATORSConsidering the stringent safety requirements and the complexities associated with reactor poisoning, the nuclear generating plants are operated with a carefully designed islanding scheme. Whenever the grid parameters are unfavourable the nuclear generators are designed to island themselves.

7.HYDRO GENERATIONIn hydro plants, electric power is generated by water flowing through turbine, which is coupled solidly to a generator. The amount of power produced is proportional to the flow and the “head”, or the height of the reservoir above the tail race. The “head” is usually provided by building a dam. In the design of a hydro power plant, consideration must be given to the seasonal variations in water flow. Thus the hydro station could be of run-of-the river type and storage type. During the high inflow period the hydro plants are generally operated at steady power output. However during the lean period the hydro plants are generally operated as peaking plants. An example of a hydro peaking plant is the pumped storage system. In this system, use is made of two reservoirs—one upper and one lower. During the off-peak periods when the demand is low, water is pumped from the lower to the upper reservoir. Then during peak periods when power demand is high, the same water is allowed to flow down through the hydro turbine generators, and therefore, produce power at the time when it is most required on the system. Normally both the machine does both jobs—pumping and generating. Hydro turbine generators rotate at relatively slow speed in the range of 100 to 250 revolutions per minute. One advantage of the hydro unit is that it can be started up synchronized and loaded within few minutes. The CERC tariff regulations recognize three types of hydro stations: run-of-river hydro stations; run-of-river with pondage; and storage. Each of these is defined below:

a) ‘Run-of-river generating station’ means a hydro generating station which does not have upstream pondage;

b) ‘Run –of-river generating station with pondage’ means a hydro generating station with sufficient pondage for meeting the diurnal variation of power demand;

c) ‘Storage type generating station’ means a hydro generating station associated with large storage capacity to enable variation of generation of electricity according to demand;

The reservoir level in a hydro station must be maintained between the Full Reservoir Level (FRL) and the Minimum Draw Down Level (MDDL). The FRL is the maximum height of the water in the reservoir. It is typically reached at the peak of the rainy season. If water rises above FRL, it is let out through gates to protect the dam. The MDDL is the minimum permissible level in the reservoir. The difference levels of water at the storage reservoir and the turbine is called the ‘Head’. Head is measure in metres and is like pressure. When water flows down through the penstock and valves, some pressure is lost due to friction. This friction head is around 5% and the remaining ‘net head’ contributes to power generation. The rate of flow of water is measured in cubic metres/second. One cubic metre is equal to 1000 litres.

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DIFFERENT TYPES OF HYDRO TURBINEWater flows from the reservoir through the penstock to the turbine to generate power. The water flowing in the penstock has some pressure (because of the height difference between the reservoir and turbine) and some speed (because water will be flowing at an increasing speed as it comes down the penstock). At the turbine, if the water is converted to jets of water, then all the potential energy will be converted into kinetic energy. This jet can be made to turn a wheel producing rotational mechanical energy and such turbines are called impulse turbines. Such turbines are used where the flow is generally low but head is large. On the other hand, if the water is made to flow through an enclosed space in the turbine, making the turbine blades turn, the water will have both pressure energy and kinetic energy. Both these types of energy are converted into rotational mechanical energy by the turbine. Such turbines are called pressure turbine or reaction turbines. In reaction turbines the pressure drop takes place in both fixed and rotating parts of the machine. The reaction turbine range from radial flow turbines (such as Francis turbine) to axial or propeller types (such as Kaplan turbine).

Figure 9: Pelton wheel turbine

The Pelton turbine is like a water wheel. A jet of water hits the bucket like turbine blades at a tangent, making the wheel turn. This is used when the head is large (more than 250 metres).

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Figure 10: Francis turbine

In Francis turbine, water flows into the turbine along the blades in a radial direction and flows out along the axis. It is used when the head is medium (16-70 metres). The flow of water in a Kaplan turbine is like the airflow in a plane propeller. Water enters along the axis from one side and leaves from the other side along the axis.

Figure 11: Kaplan turbine

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POWER GENERATION BY HYDRO POWER STATIONPower generated by the turbine is related to the head, water flow rate and efficiency of the turbine. The higher the head or the water flow rate, the higher the power generation possible. Considering the turbine efficiency of 90 % and generator efficiency of 85-90%, an approximate formula for electric power output by a hydro generator is:Power = 8 x Net Head x Flow rate/1000; Power in kW, Net head in metres and flow rate in litres/second.

MAJOR HYDRO GENERATING POWER STATIONS IN INDIAMajor hydro electric power stations in India are tabulated below:Table 4: Installed Capacity of major hydro stations in India

S No.

Station Units Commissioned Capacity (MW)

1 Bhakra (Right) 5x157 785 2 Dehar 6x165 9903 Chamera-I 3x180 5404 Nathpa Jhakri 6x250 15005 Tehri 4x250 10006 Ranjit Sagar Dam 4x150 6007 Baghlihar 3x150 4508 Sadar Sarovar-

RBPH6x200 1200

9 Koyna 4x250 100010 Bhira PSS 1x150 15011 Srisailam LBPH 6x150 90012 Kalinadi 3x135+3x15

0855

13 Upper Indravati 4x150 60014 Purulia PSS 4x225 90015 Teesta 3x170 51016 Ranganadi 3x135 405

SYNCHRONOUS CONDENSER MODE OF OPERATIONSome hydro stations can generate only reactive power. This is known as ‘condenser mode of operation. In this mode, a minimum water flow is to be maintained and the unit will consume some active power from the grid (around 8-10% of its capacity).Table 5: List of Hydro Generators Capable of running in Synchronous Condenser ModeSl. No. Utility SubStation Capacity (MW)

1 BBMB Pong 6 X 66 = 3962 HPSEB Larji 3 X 42 = 1263 PSEB Ranjit Sagar HEP

(RSD)4 X 150 = 600

4 RVUN Rana Pratap Sagar (RPS)

4 X 43 = 172

5 RVUN Jawahar Sagar (JS) 3 X 33 = 996 THDC Tehri 2 X 250 = 500

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Tehri HEP units in Northern Region were tested for operating as a synchronous condenser mode on 7th April 2008, 09th April 2008, 3rd August 2009 and 4th August 2009. The plots are shown below.

380

385

390

395

400

405

410

415

420

425

430

435

-40

-20

0

20

40

60

80

100

120

4:00:00 4:16:40 4:33:20 4:50:00 5:06:40 5:23:20 5:40:00 5:56:40

kV

MW

/MV

AR

Time(PM)

Tehri Synchronous Condenser mode of Operation on 7th April 2008

Unit 3 MW

Unit 3 MVAR

TEHRI kV

Meerut kV Mandaula kV

Figure 12: Synchronous Condenser Operation at Tehri on 27th April 2008

385

390

395

400

405

410

415

420

425

-150

-100

-50

0

50

100

150

4:30:00 4:46:40 5:03:20 5:20:00 5:36:40 5:53:20 6:10:00 6:26:40

kV

MW

/MV

AR

Time(PM)

Tehri Synchronous Condenser mode of Operation on 9th April 2008

Unit 3 MW

Unit 3 MVAR

TEHRI kV

Meerut kV

Mandaula kV

Figure 13: Synchronous Consenser Operation at Tehri on 27th April 2008

116

-1

166 MVAR

374 KV

384 KV

370

375

380

385

390

395

-20

30

80

130

180

230

2809:

00

9:30

10:0

0

10:3

0

11:0

0

11:3

0

12:0

0

12:3

0

13:0

0

13:3

0

14:0

0

14:3

0

15:0

0

15:3

0

16:0

0

16:3

0

17:0

0

kV

MW

/MV

AR

Time

Synchronous Condenser Mode of Tehri HEP on 3-Aug-2009

UNIT 4 MVAR

MERRUT BUS VOLTAGE

UNIT 4 MW

Figure 14: Synchronous Condenser Operation at Tehri on 03rd Aug 2009

0

161 MVAR

371KV

382 KV

365

370

375

380

385

390

395

-20

30

80

130

180

230

280

9:00

9:30

10:0

0

10:3

0

11:0

0

11:3

0

12:0

0

12:3

0

13:0

0

13:3

0

14:0

0

14:3

0

15:0

0

15:3

0

16:0

0

16:3

0

17:0

0

kV

MW

/MV

AR

Time

Synchronous Condenser Mode of Tehri HEP on 4-Aug-2009

UNIT 1 MVAR

MERRUT BUS VOLTAGE

UNIT 1 MW

Figure 15: Synchronous condenser Operation at Tehri on 04th Aug 2009

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Table 6: Synchronous condenser operation at Tehri HEP

DateMode of Operation

Energy Consumed (-ve)/ Generated (+ve) by the Unit

Active Energy

Reactive Energy

MWh MVArhA B

07-Apr-08MVARGeneration

-92 1004

09-Apr-08MVARAbsorption

-122 -2674

03-Aug-09MVARGeneration

-28 481

04-Aug-09MVARGeneration

-16 311

Average -64 1118

PUMPED STORAGE OPERATION IN HYDRO STATIONSPumped Storage type hydro generation comprises cyclic/daily conversion of the off-peak surplus capacity in a given power system into on-peak power. The surplus power which may come from run-of-river type hydro, thermal, nuclear or renewable energy sources is used to pump water from lower (tail) pool to the head reservoir and utilizing the stored water (hydro) potential to generate power to supply the system peak load period. Pumped storage operation could be utilized for frequency control in the grid. However it involves a net loss of energy in each cycle of operation. Therefore for its economics and competiveness, it has to take all the above factors into account.Pumped storage power stations in operation in India are tabulated below.

Table 7: Pumped Storage Plants in IndiaS No.

Station Location Commissioned Capacity

1 Kadamparai PSS

Tamil Nadu 4 x 100 MW

2 Srisailam L.B. PSS

Andhra Pradesh

6 x 150 MW

3 Purulia PSS West Bengal 6 x 150 MW4 Ghatgar PSS Gujarat 250 MW5 Bhira PSS Maharashtra 1 x 150 MW

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KADAMPARAI GENERATION/PUMP Vs FREQUENCY FOR

-300

-200

-100

0

100

200

300

400

500

0:00

1:00

2:00

3:00

4:00

5:00

6:00

7:00

8:00

9:00

10:0

011

:00

12:0

013

:00

14:0

015

:00

16:0

017

:00

18:0

019

:00

20:0

021

:00

22:0

023

:00

0:00

TIME ---->

IN M

W --

-->

48.50

49.00

49.50

50.00

50.50

51.00

FR

EQU

ENC

Y IN

HZ

----

>

GENERATOR MODE

PUMP PUMP

Figure 16: Typical operation of Kadamparai PSP

Figure 17: Kadamparai pump operation (Million Units) 2008-09 to 2010-11

8.WIND ENERGY GENERATIONWind power plants use large spinning blades to capture the kinetic energy in moving wind, which then is transferred to rotors that produce electricity. The power extracted from wind by a wind turbine may be given by the equation P= (½) ρ v3π r2 Cp(λ)

119

whereP = mechanical powerρ = air densityv = wind speedr = wind turbine rotor radiusCp = coefficient of efficiencyλ = tip-speed ratio (i.e. the ratio of blade tip speed to wind speed)It is clear that air density, the speed of the air and the radius of the wind turbine rotor are not controllable. Thus, to maximize energy output from a wind turbine, based on (1), the only parameter that can be controlled is the coefficient of efficiency (Cp). The theoretical maximum value of Cp is 0.593 (Betz’s Law). In practice, Cp values close to 0.4 are achievable. For a given blade pitch and rotation speed, Cp is a non-linear function of wind speed and will peak at a given turbine tip-speed to wind speed ratio (called the ‘tip-speed ratio’), and will drop off again to zero at higher tip-speed ratios. A good wind site may have an average wind speed ranging around 7 to 10 m/s. Very high wind speeds occur seldom and also tend to put significant stress on the turbine. Thus, the turbine would be typically designed to extract the maximum amount of wind energy possible at wind speeds between 10 to say 15 m/s, and to start to spill away some of the power at wind speeds in excess of 15 m/s until they shut-down at relatively high wind speed – typically, in excess of 20 to 25 m/s. That is, a mechanism is required to control the turbine power once wind speeds increase beyond a certain amount, in order to avoid increasing the turbine power above its rating. To achieve this necessitates a form of power control on the turbine.Wind turbines are manufactured by many companies around the world. There are essentially three major types of wind turbine designs:

1. Constant speed turbines2. Variable speed turbines3. Gearless turbines

Constant speed turbines employ conventional induction generators while variable speed designs are based either on doubly-fed asynchronous generators or conventional generators connected to the grid through a full back-to-back frequency converter. Gearless turbines typically use conventional or permanent magnet generators connected to the grid through a full back-to-back frequency converter.

WIND GENERATION CAPACITY IN INDIAAs per the website of Ministry of New and Renewable Energy up to 31st March 2011 a total capacity of 14156 MW of wind energy has been installed, as per following break-up.Table 8: Wind Generation Installed Capacity

S No. State Capacity (MW)

1 Tamil Nadu 59042 Maharashtra 23173 Karnataka 17274 Rajasthan 15255 Madhya Pradesh 2766 Andhra Pradesh 192

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7 Kerala 358 Others 4

VOLTAGE RIDE THROUGH

It is now widely accepted that for large wind farms connected to the bulk transmission system, it is expected that the wind turbines should be able to ride through a normally cleared single or multi-phase fault that occurs at the transmission voltage level (not within the wind farm collector system).

Figure 18: Schematic for explaining fault ride through

To illustrate the point consider the figure of a hypothetical system give above. In this case, if a fault were to occur at F3 or F4 it is clear that wind farms 1 or 2, respectively, would be essentially disconnected from the system and thus would not be expected to ride through the disturbance – for these disturbances wind farm 3 should remain connected to the system. However, for all the other faults shown (F1, F2, F5, F6 and F7) it is quite reasonable to expect that all three wind farms ride-through the fault while line relays clear the particular faults. Otherwise, one might experience the loss of several hundred megawatts of generation together with the loss of the faulted line. This would further aggravate the problem and lead to potential stability concerns system wide. This is particularly true if a single disturbance should lead to a total loss of wind generation equal to or greater than the single largest generating facility on the system – most systems will carry enough spinning reserve to accommodate for the forced outage of the largest unit on the system.

9.EXPECTATIONS FROM A GENERATOR CONNECTED IN THE GRIDVarious technical standards to be complied by a generator connected in the Grid may be referred to in the Central Electricity Authority (Technical Standards for Construction of Electrical Plants and Electric Lines) Regulations,

121

2010 ; CEA (Technical Standards for Connectivity to the Grid) Regulations, 2010; Indian Electricity Grid Code.

10.IMPORTANT TERMS AND DEFINITIONSa) ‘Maximum Continuous Rating' or MCR in relation to a unit of the

thermal generating station means the maximum continuous output at the generator terminals, guaranteed by the manufacturer at rated parameters, and in relation to a block of a combined cycle thermal generating station means the maximum continuous output at the generator terminals, guaranteed by the manufacturer with water or steam injection (if applicable) and corrected to 50 Hz grid frequency and specified site conditions; [‘block’ in relation to a combined cycle thermal generating station includes combustion turbine-generator, associated waste heat recovery boiler, connected steam turbine- generator and auxiliaries;]

d) 'Auxiliary Energy Consumption' or AUX in relation to a period in case of a generating station means the quantum of energy consumed by auxiliary equipment of the generating station, and transformer losses within the generating station, expressed as a percentage of the sum of gross energy generated at the generator terminals of all the units of the generating station. Auxiliary Energy Consumption (AUX) for coal fired stations may be in the range of 6% to 12%. AUX in lignite fired stations is usually higher. For gas power stations the AUX may typically be 3% in combined cycle operation and 1% in open cycle operation. AUX for hydro stations is usually in the range of 0.7% (for rotating exciter) to 1.2% (static exciter).

e) 'Design Energy' means the quantum of energy which can be generated in a 90% dependable year with 95% installed capacity of the hydro generating station;

f) `Gross Calorific Value’ or GCV in relation to a thermal generating station means the heat produced in kCal by complete combustion of one kilogram of solid fuel or one litre of liquid fuel or one standard cubic meter of gaseous fuel, as the case may be;

g) `Gross Station Heat Rate’ or GHR means the heat energy input in kCal required to generate one kWh of electrical energy at generator terminals of a thermal generating station; Typical Gross Station Heat Rate (GHR) for coal fired 200/210/250 MW set is 2500 kCal/KWh. Typical GHR for coal fired 500 MW Sets (Sub-critical) is 2425 kCal/kWh. For old thermal units GHR may be higher. Typical GHR for gas power station in combined cycle may be in the range of 2040 to 2400 kCal/kWh while in open cycle it may be in the range of 2960-3500 kCal/kWh.

h) 'Plant Availability Factor (PAF)' in relation to a generating station for any period means the average of the daily declared capacities (DCs) for all the days during that period expressed as a percentage of the installed capacity in MW reduced by the normative auxiliary energy consumption.

i) 'Unit' in relation to a thermal generating station other than combined cycle thermal generating station means steam generator, turbine-generator and auxiliaries, or in relation to a combined cycle thermal

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generating station, means turbine-generator and auxiliaries; and in relation to a hydro generating station means turbine-generator and its auxiliaries;

11.REFERENCES[1]. Central Electricity Authority (Technical Standards for Construction of

Electric Plants and Electric Lines) Regulations 2010[2]. Central Electricity Authority (Technical Standards for Connectivity to the

Grid) Regulations 2010[3]. Central Electricity Regulatory Commission (Terms and Conditions of

Tariff) Regulations, 2009[4]. CBIP Publication No. 288, Hydroelectric Power Stations in Operation in

India, 2003[5]. Guthrie-Brown, J. (Ed), Hydro-Electric Engineering Practice’, Blackie

and Son[6]. CIGRE Technical Brochure No. 328, ‘Modeling Wind Generation’[7]. Power point presentation by Sh Bhanu Bhushan, in the classroom

session, on ‘Generation Technologies’ held at PSTSI Bangalore[8]. PRAYAS (Energy) Group, ‘Know Your Power-A Citizen’s Primer on the

Electricity Sector’,2nd Edition, May 2006[9]. British Electricity International Limited, ‘Modern Power Station Practice-

Turbines, Generators and Associated Plants, Volume C’, 3rd edition, March 1990

[10]. British Electricity International Limited, ‘Modern Power Station Practice-Nuclear Power Generation, Volume J’, 3rd edition, March 1990

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TABLE OF CONTENTS

No. Topic

1. Introduction

2. Power Supply Frequency

3. Adverse Effects Of Frequency Fluctuations

4. Frequency Standards

5. Frequency Control

6. Primary Response from Generators

7. Primary Response from Load / Load Damping

8. Equilibrium Frequency

9. Frequency Response Characteristics

10. Rate of Change of Frequency

11. Frequency Control Through Market Mechanism

12. Defense Mechanism

13. Monitoring Frequency Profile

14. Reference

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1. INTRODUCTION

Frequency is the number of occurrences of a repeating event per unit time. For cyclical processes, such as rotation, oscillations, or waves, frequency is defined as a number of cycles per unit time. In physics and engineering disciplines, frequency is usually denoted by a Latin letter f or by a Greek letter ν (nu). In SI units, the unit of frequency is the hertz (Hz), named after the German physicist Heinrich Hertz: 1 Hz means that an event repeats once per second. It is sometimes also referred as cycles per second.

A traditional unit of measure used with rotating mechanical devices is revolutions per minute, abbreviated RPM.

The period, usually denoted by T, is the length of time taken by one cycle, and is the reciprocal of the frequency f:

The SI unit for period is the second.

2. POWER SUPPLY FREQUENCY

In a power system, the frequency indicates the number of times the voltage reverses in half a second. The rated frequency of power supply in India (as in many other countries) is 50 Hz (or cycles per second). This implies that all electrical equipment to be used in India has to be designed for a power supply frequency of 50.0 Hz. Not only this, all mechanical equipment driven by electric motors has to be designed for running at a speed corresponding to its motor’s speed when power supply frequency is 50.0 Hz. Likewise at 50 Hz, a two pole turbine generator would run at 50 rps or 3000 rpm at 50 Hz while at 49 Hz it would run at 2940 rpm. The relationship between the mechanical speed and the power supply frequency is as under:

f : Frequency in Hz P : Number of polesN : Rotor revolutions per minute

In a synchronous system the frequency must be same at every point in the grid because the polarity of voltage produced by all generators must be same at a particular time and must reverse together.

The frequency does not remain constant because the consumer load keeps changing from time to time and the generation is not changing in step with the load. The normal operating frequency range allowed by the Indian Electricity Grid Code w.e.f 3rd May 2010 is 49.5-50.2 Hz.

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3. ADVERSE EFFECTS OF FREQUENCY FLUCTUATIONS

Lighting and heating appliances are generally insensitive to supply frequency. Most of other equipment is sensitive to frequency in one manner or the other.

Performance of the rotating load is influenced by power supply frequency. Low frequency would generally reduce the efficacy of a motorized appliance, whereas high frequency can cause overloading. At frequency lower than the rated value, the output of the motor would reduce. At frequency higher than the rated value, the motor may get overloaded. Abnormal speed may cause heating, damage rotor shaft, bearings etc.

The power generating capability of the turbine is directly proportional to its speed, which is proportional to grid frequency. The total generating capability of a power plant is however dependent on the performance of the auxiliaries (i.e. the pumps and fans in the power plant). At low frequency, the output of the auxiliaries decrease and thus reduce the output of the generating unit.

The last stage blades of large steam turbines are sensitive to resonant vibrations at both high and low frequencies. Abnormal frequency has adverse impact on the turbine blade life. Different turbine manufacturers specify somewhat different ranges of frequency in which their turbine can operate without risk to their blades. Operation at frequencies outside this range can result in fatigue and breaking of turbine blades and can cause serious damage to the turbine generator.

The gas turbines are prone to compressor surging at low frequencies, which are very damaging. Further the manufacturers stipulate tripping of a gas turbine when frequency moves out of the permissible range. Such trippings have a very serious effect on gas turbine life because of the sudden quenching, differential expansion/contraction and thermal/mechanical stresses.

Frequency fluctuations mean corresponding changes in the speed of coolant pumps, and consequent changes in coolant flow through the reactor. This leads to fluctuations in the differential temperature (between coolant at outlet and inlet), even when generating a constant amount of heat. This gives an erroneous control signal and causes unnecessary perturbations in the reactor control system which calls for stresses to fuel rods and reduction of their useful life.

Low frequency may cause over fluxing in transformers due to core saturation. This can be easily inferred if one refers the relationship between the induced EMF, frequency and the Flux generated in the core of any electrical machine.

Voltage = 4.44 x Frequency x Number of turns x Flux in the core

This implies that the flux generated in the core would be very high if high voltage and low frequency occur simultaneously.

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Effectiveness of shunt capacitors and reactors fall with frequency. The capacitance and reactance of transmission lines vary with frequency. A reduction in frequency will result in instrument errors of approximately 1%. Voltage is proportional to the frequency. At reduced frequency the magnetizing current of transformers, motors and other inductive equipment is increased, thereby increasing the system reactive load. The kVArs supplied by shunt capacitors overhead lines and underground cables vary directly as frequency. Also a 10% reduction in voltage will reduce the kVArs by 10%. In a nutshell low frequency may result into low voltage and high frequency may result into high voltage in the power system.

4. FREQUENCY STANDARDS

Selection of a power frequency is a matter of considerable importance. During the development of commercial electric power systems in the late 19th and early 20th centuries, many different frequencies (and voltages) had been used. Efforts were directed towards standardization because generators could be interconnected to operate in parallel only if they are of the same frequency and wave-shape. By standardizing the frequency used, generators in a geographic area could be interconnected in a grid, providing reliability and cost savings. It was also realized that international trade in electrical equipment would be possible only after standardization. However it wasn't until after World War II with the advent of affordable electrical consumer goods that more uniform standards were enacted.

Large investment in equipment at one frequency made standardization a slow process. In Britain, a standard frequency of 50 Hz was adopted in 1904. Most parts of the United States of America used 60 Hz as standard frequency. The standard frequency in the SAARC countries including India is 50.0 Hz. Thus both 50 Hz and 60 Hz frequencies co-exist today (some countries such as Japan use both) with no technical reason to prefer one over the other and no apparent desire for complete worldwide standardization.

Operation at the rated frequency is most desirable. Permissible band of frequency would be determined by the obligations to the consumers, requirements of power plants, and requirement of power system. The present Indian Electricity Rules permit a frequency variation of +/- 3%, i.e. from 48.5 Hz to 51.5 Hz. This implies that no consumer can complain if the supply frequency is in this range, which means that all equipment has to be designed to be capable of (i) delivering the necessary output even when the frequency is down to 48.5 Hz, and (ii) withstanding the overloading when frequency rises to 51.5 Hz. Designing the equipment for such requirements does increase its cost, but these are the statutory requirements. This however has a beneficial side effect: additional margins in equipment design, which means extra efficacy and more life in case the frequency remains closer to 50.0 Hz.

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PERMISSIBLE FREQUENCY RANGES FOR OPERATION OF VARIOUS MAKES OF STEAM TURBINESS. No.

TurbineFrequency (Hz)

Time for Operation

1

100 MW, 200 MW, 210 MW of Russian Design

49.0 to 50.5 Continuous unrestricted operation

50.5 to 51.03 minutes at a stretch and 500 minutes in whole life

48.0 to 49.03 minutes at a stretch and 500 minutes in whole life

47.0 to 48.01 minutes at a stretch and 180 minutes in whole life

46.0 to 47.010 seconds at a stretch and 30 minutes in whole life

2210 MW, 500 MW of KWU Design

47.5 to 51.5 Continuous unrestricted operationBelow 47.5 2 hours in whole lifeAbove 51.5 2 hours in whole life

3200 MW of GE (ANSALDO) Design

48.5 to 50.5 Continuous unrestricted operation50.5 to 51.0 90 minutes in whole life48.0 to 48.5 90 minutes in whole life51.0 to 51.5 15 minutes in whole life47.5to 48.0 15 minutes in whole life51.5 to 52.0 1 minute in whole life47.0 to 47.5 1 minute in whole life

4RAPS/NAPS2x220 KWEnglish Electric

48.5 Operating Frequency

Summation in lifetimet<= 3 minutes where ‘t’ is the operating time for incidents of frequency excursion below 48.5 Hz

> 51.5 Not recommended

5110 MW of Skoda Design

49.0 – 51.0 Continuous unrestricted operation48.0 - 49.0 2 Hours at a stretch and 30 hours in a year47.0 – 48.0 30 minutes at a stretch and 2 hours in a

year Source : Extracts from the report of “Task Force on Frequency Control” NREB, 1992 in the PSEB letter dated 06.10.1998.

Figure 1: Permissible range of frequency for steam turbine

The frequency standard, permissible frequency band and the permissible deviation as a percentage of standard frequency in various countries are shown in the table below.

Country/AreaStandard Frequency

Permissible Frequency Band (Hz)

Permissible Deviation (%)

Eastern-Interconnection US

60 Hz 59.95 – 60.05 +/- 0.00083%

Western-Interconnection US

60 Hz 59.856 – 60.144 +/- 0.0024%

Nordic countries 50 Hz 49.9 – 50.1 +/- 0.02%Europe 50 Hz 49.8 – 50.2 +/- 0.004%

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Bangladesh 50 Hz 49.5 – 51.0 +/- 2%Bhutan 50 Hz 49.2 – 50.3 +/- 2%India 50 Hz 49.5 – 50.3 - 1.6%/+0.6%Maldives 50 Hz 49.5 – 50.5 +/- 1%Nepal 50 Hz 49.5 – 50.5 +/- 1%Pakistan 50 Hz 49.5 – 50.5 +/- 1%Sri Lanka 50 Hz 49.5 – 50.5 +/- 1%

Table 1 : Frequency Standard Adopted in Various Countries

The regulations regarding frequency standard adopted in India may be referred in IEGC 5.2(m).

5. FREQUENCY CONTROL

Frequency control is an essential requirement of reliable electric power system operations. At the most basic level, the input energy of a generator must balance. If more mechanical energy is being delivered to a generator than electrical energy is being removed from the electrical terminals then the excess energy will be stored in the generator’s rotation (kinetic energy), resulting in acceleration of the generator. Likewise, if more electrical power is taken out of the generator than mechanical power is put into it, then the generator will decelerate. The magnitude of acceleration depends upon the quantity of the power mismatch, and the inertia of the turbine – generator. Inertia is a physical constant of each turbine-generator that defines its ability to store rotational kinetic energy, and is analogous to mass. Power system frequency responds to a generation and load imbalance in the same manner. The rate at which frequency moves depends upon the magnitude of the energy imbalance and the inertia of all of the generators and loads within the system.

Steam input to turbo-generators (or water input to hydro generators) must be continuously regulated to match the active power demand

Fig. 2 : Energy Conversion in Power System

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Chemical Energy (Coal)

Potential Energy (Water)

Kinetic Energy

Steam/Water

Mechanical Energy Heat EnergyLight Energy

Electrical Energy

Frequency provides an indication of the interconnection’s generation/load balance. It is instantly available everywhere within the interconnection without the need for additional communications. This facilitates dispensed, autonomous response to system casualties by generators and loads. Frequency response is classified into three categories – primary, secondary, and tertiary control.

5.1 Primary Frequency Control

Primary frequency control involves autonomous and automatic actions to arrest deviations in power system frequency whenever imbalances arise between load and generation. Primary frequency control actions are fast; they are measured in MW/seconds. Primary frequency control actions include governor response, load damping, and more recently voluntary frequency responsive load control, all of which contribute to frequency response.

The rate of frequency decline is slowed by “load rejection”. Motor load in particular is affected by frequency. When frequency drops, the motors slow down and they produce less work and therefore consume less energy.

All generators have some type of governor control. The governor on a generator is basically identical to cruise control on an automobile. The governor senses a change in speed and allows more energy to be delivered to the generator’s prime mover (more water in a hydro station, more steam to a turbine, more fuel to a combustion turbine).

5.2 Secondary Frequency Control

Secondary frequency control involves centrally coordinated actions to return frequency to its scheduled value. Secondary frequency control actions are slower than primary frequency control actions; they are measured in MW/min. They are deployed both during normal operations and after primary frequency control resources have arrested frequency following major disturbances. Secondary frequency control actions include generation (or load) that responds to automatic generation control (AGC) signals or to operator dispatch commands. AGC is often referred to as “regulation” service.

In line with regulation 6.4.5 of IEGC, the regional grids shall be operated as power pools with decentralized scheduling and despatch, in which the States shall have operational autonomy. Further in line with regulation 6.4.6, the regional entities are allowed to deviate from their interchange schedule as long as such deviations do not cause system parameters to deteriorate beyond permissible limits and/or do not lead to unacceptable line loading. Thus there is no provision for secondary frequency control in India.

5.3 Tertiary Frequency Control

Tertiary frequency control involves centrally coordinated actions to dispatch generation (or load) to move to a new operating point while maintaining balanced operation. They include coordinated dispatch changes in opposite directions, raise and lower as well as increasing generation to replace

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generation losses. Tertiary frequency control actions are the slowest of frequency control actions although, like secondary control actions, they are also measured in MW/min. They include coordinated changes in dispatch to follow load, implement interchange transactions or coordinated changes in generating unit loading to redistribute reserves. Tertiary control is often referred to as “ramping” or “load-following” service.

In India all regional entities have to abide by the concept of frequency-linked load despatch and pricing of deviations from schedule. This is explained in sections ahead. In line with IEGC regulation 5.4.2 SLDC/SEB/Distribution Licensee and bulk consumer have to initiate action to restrict the drawal of its control area, from the grid, within the net drawal schedule whenever the system frequency falls to 49.7 Hz. Each SLDC shall regulate the load/own generation under its control so that it may not draw more than its net drawal schedule during low frequency conditions and less than its drawal schedule during high frequency conditions.

The Regional entity generating stations have to maintain generation such that it may not generate less than its generation schedule during low frequency conditions and more than its generation schedule during high frequency conditions. In case any state constituent is likely to face power shortage situation despite requisitioning its full entitlement from long term bilateral contracts, then it shall endeavour to enter into a bilateral agreement with the other state constituents having surplus power and vice-versa. In any case, during low frequency conditions no state would carry out over-drawals.

Further sudden reduction in generator output by more than one hundred (100) MW unless, under an emergency condition or, to prevent an imminent damage to the equipment, is to be avoided, particularly when frequency is falling below 49.5 Hz. Sudden increase in load by more than 100 MW by any regional entity, particularly when frequency is falling below 49.5 Hz and reduction in load by such quantum when frequency is rising above 50.2 Hz is also to be avoided.

6. PRIMARY RESPONSE FROM GENERATORS

When a generator synchronizes to the interconnection, it couples itself to hundreds of other machines rotating at the same electrical speed. Each generator in the system has a turbine governor. The purpose of the governor is to maintain load-generation balance and hence stop the frequency from rising or falling as a result of imbalance. The governor on each unit continuously monitors turbine-generator speed and sends signal to the control valve to adjust the amount of energy input to the turbine. This energy input could be steam flow for a steam turbine, water flow for hydro turbine, or fuel oil or gas for a gas turbine. The contribution by a generator depends upon the droop setting, load limiter setting and dead band of the governor.

6.1 Speed Droop

Speed droop is the amount of speed (or frequency) change that is necessary to cause the main prime mover control mechanism to move from fully closed

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to fully open. Speed droop is used to control the magnitude of governor response for a given frequency change so all generators will share response after a disturbance. In general, the percent movement of the main prime mover control mechanism can be calculated as the speed change (in percent) divided by the per unit droop.

When the load on a system generator increases such as when a consumer switches on a large motor or heater, the generator begins to slow down because the additional load is met by conversion of some stored kinetic energy into electrical energy. This causes the electrical frequency to drop. The governor, sensing the speed change, opens the main steam-valve wider until the speed (and hence frequency) decay is arrested. When the frequency decay is arrested the generator will be operating at a frequency lower than scheduled, but at a higher output. The frequency will remain at a lower level until the governor set points are adjust by the plant operator.

As per the IEGC regulation 5.2 (f)(ii)(c), all governors shall have speed droop between 3 – 6%. For example, a 5% speed droop means that if the electrical frequency drops by 5%, the unit is loaded from zero to full load or vice versa. Speed droop is a method of controlling how load change is apportioned among units in parallel. Without droop, the unit whose governor responds the fastest would pick up the total load change.

Two generators of same rating and have equal droop operating in parallel share the additional load equally. However, The additional load is shared in inverse proportion to their unit size if the droop is equal but the unit rating is unequal.

Illustration

Consider the case of two generating units of 100 MW capacity each with speed regulation of 5% and 2% operating in parallel and operating at 50% of load. If the initial system load is 100 MW and an additional load of 35 MW results in a drop in system frequency by 0.5% from normal then the change in the output of the units would be computed as shown below :

Unit 1 : 0.5 x 100/5 = 10%Unit 2 : 0.5 x 100/2 = 25%

This is shown in Figure 3.

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Fig. 3: Response of two units operating in parallel but having different speed droop

Subsequently the plant operator may change the dispatch of the system by moving the droop curve up or down on a number of units. This would effectively change the set point of the unit as shown in Fig. 4. The re-despatch is generally based on the merit order of the unit.

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Fig. 4 : Supplementary Regulation

As per the IEGC regulation 5.2 (h), the rate for changing the governor setting, i.e. supplementary control for increasing or decreasing the output (generation level) for all generating units, irrespective of their type and size, would be one (1.0) per cent per minute or as per manufacturer’s limits.

6.2 Frequency Linked Despatch Guidelines for Supplementary Regulation

All thermal generating units of 200 MW and above as well as all hydro units of 10 MW and above are mandated to participate in primary regulation wherein the output of the generator increases or decreases without any manual action when the frequency decreases or increases respectively. However, as per IEGC regulation 6.4.15, all regional entities should abide by the frequency linked dispatch guidelines. This implies that each generating stations will maintain its scheduled generation till a threshold frequency where the Unscheduled Interchange (UI) rate is more than the variable cost of generation of that unit. Therefore, when the output of the generating unit has changed as a result of mandatory primary response, its output may be readjusted (known as supplementary regulation) depending upon the system frequency and the variable change of the station.

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For this purpose, the threshold frequency for the generating unit shall be determined from the prevailing design of the Unscheduled Interchange vector and the variable energy rate of the station. The generator on its own can reduce generation when frequency goes above this cut-off frequency. For frequency below cut-off frequency, the generator would respond to frequency changes but would come back to its set point in a slow manner with ramp rates of 1% MW per minute.

Figure 5 illustrates the frequency linked dispatch guidelines. The generator whose variable cost is about ‘X’ paise per unit and can maintain at set point given by RLDC/SLDC till frequency reaches 50.2 Hz. At 50.2 Hz, the cost of UI power from the regional pool is also equal to ‘X’ paise per unit.

Fig. 5 : Frequency linked despatch for supplementary regulation

Suppose a generator (say 500 MW) capacity is operating at ‘A’ with 5% droop and contributing to primary regulation and the set point given is 100% i.e. 500 MW. If frequency falls from 49.8 Hz to 49.6 Hz and the generator would pick up load upto 105% of the set point (525 MW and limited by load limiter set at 525 MW) instantaneously and the operating point would be at ‘B’. The load on this generator may be reduced in a slow manner back to the set point that is 500 MW in about 5 minutes time through supplementary regulation. The new operating point would now be ‘C’. The machine can once again respond to frequency changes from ‘C’ with a droop of 5% (dotted line CD). The frequency may stabilize at say 49.6 Hz.

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In case of frequency rise, the machine output would reduce from ‘A’ to ‘E’ instantaneously. The load on the generator may once again be increased to ‘F’ in a slow manner and the frequency may stabilize at 49.8 Hz.

At point ‘G’ corresponding to 500 MW load and 50.2 Hz, the machine is operating at cut-off frequency. In case of frequency rises, the machine can drop generation and can operate at reduced level of generation and need not come to the original set point that is 500 MW. The generator can also choose to further reduce its set point from ‘G’ as for frequency above 50.2 Hz, the cost of UI generation is lower than the generator’s variable cost of generation.

Typical primary response alongwith supplementary regulation is shown in Figures below.

Fig. 6: Primary response demonstrated by Ropar Unit 2 on 23rd

October 2003

FREQUENCY RESPONSE IN BHAKRA RIGHT 5 ON 23/01/2004

Fig. 7 : Primary response demonstrated by Bhakra Unit 5 on 23rd Jan 2004

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Fig. 8 : Primary response demonstrated by Dadri Unit 2 on 25th Jan 2004

If the governor is tuned to be "isochronous" (i.e. zero droop), it will keep opening the valve until the frequency is restored to the original value. This type of tuning is used on small, isolated power systems, but would result in excess governor movement on large, interconnected systems. This setting is also used during black start of a generating unit.

6.3. Load Limiter Load limiter is the maximum permissible output from a generator. It is generally considered as 105% of Maximum Continuous Rating of the generator. The load limit is adjustable and sometime it is used to limit the output of the generator to some level below the true full load output. As per

IEGC regulation 5.2 (h), all thermal generating units of 200 MW and above and all hydro units of 10 MW and above operating at or up to 100% of their Maximum Continuous Rating (MCR) shall normally be capable of (and shall not in any way be prevented from) instantaneously picking up to 105% and 110% of their MCR, respectively, when frequency falls suddenly. After an increase in generation as above, a generating unit may ramp back to the original level at a rate of about one percent (1%) per minute, in case continued operation at the increased level is not sustainable.

6.4. Governor Response Time There is a time lag between a change in generator speed and the change in turbine power. The governor time lag has several components. The first component is the dead band of the governor. It is inherent in the governor due to mechanical linkages involved. Therefore, the governor may not move for small frequency changes, typically less than +/-0.02 Hz. For frequency excursions larges than the dead band, the governor reacts with a small time delay of about 0.25 seconds. This dead band is the amount of frequency

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change a governor must see before it starts to respond. It prevents governors from continuously “hunting” as frequency varies ever so slightly. As per IEGC 5.2 (f) ii (b), dead band of +/ -0.03 Hz is permissible. The next component of the time lag comes from the steam throttle valve mechanism and the hydraulic power unit which moves it. The valves are large and heavy and thus have considerable inertia to overcome, so it is not possible to move the valve instantaneously. It takes about 0.5 second to move the valve by a significant amount.

The steam flow itself also contributes to the total lag, particularly in the reheat turbine sections, where the flow must accelerate or decelerates to the new flow rate following a change in the valve position. There is a slight delay before equilibrium is reached at the new steam flow rate. The time lags are additive, since they occur one after the other (i.e., valve position is changed first then steam accelerates or decelerates to achieve the new flow rate. The result is that it takes a few seconds for the turbine power to change once a speed change is detected by the governor. For a hydro turbine, this delay may be 5 to 10 seconds.

6.5. Transient Stability And Governor Response

During steady state operation any load generation imbalance and consequent frequency change occurs gradually. Therefore, in the steady state, this governor time lag is barely noticeable. However immediately following a disturbance, this time lag is significant. During the transient period following a fault, the stability or instability of the system will be determined within the first 0.25 to 0.5 seconds while the governor response may take a few seconds. Therefore, during the transient period, the governor does not appreciably help the system.

6.6. Boiler Turbine Control System

There are three basic types of control systems used for boiler and turbine output control. They are boiler follow turbine system, turbine follow boiler system and integrated or Coordinated Control system. The names for each mode listed above refer to the sequence of events that occur in restoring load-generation balance following a disturbance.

In the “boiler follow turbine” system, the speed change is first detected by the speed control (governor). Thus if there is a drop in frequency the turbine valves open. The steam rushes into the turbine and the pressure in the steam system starts to drop as the steam is drawn out of the piping and the boiler system. When the pressure drops, the boiler controls detect it and allow more fuel to enter the boiler. This raises steam generation and the steam pressure recovers. In this method the turbine controls act first and the boiler controls “follow”.

In the “turbine follow boiler” system the load controls detect a speed change but do not directly change the turbine valve position. Instead, the fuel, air, and feed water into the boiler are changed. As a consequence, the steam generation is changed. The turbine valves are controlled to maintain a

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constant boiler pressure and thus, as pressure tend to raise, the valve opens and more steam flows, raising the power output. Boiling water nuclear plants are of this type.

The third system is a combination or “integrated control” system. The signals for increased load go to both the turbine valve control and the boiler control. The valves are opened and more fuel starts flowing in some relationship that depends on the particular boiler turbine system.

Fig. 9 : Boiler Turbine Control System Schematic

The response characteristics of different boiler-turbine systems are shown in figure 10. It would be seen that the boiler following system supplies the extra MW with the smallest time lag because energy is drained from piping and boiler. However its boiler goes through the largest pressure excursion and the output is often oscillatory.

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Fig. 10 : Response Characteristics under different Boiler-Turbine Control System The turbine following system goes through almost no pressure deviation but takes about 3 minutes to supply the extra MW. The integrated system has a response time between that of the others. It also tends to arrive at the desired output more quickly and with less variation.

6.7. Blocked Governors

Blocking the governor of a generator essentially bypasses the governing feedback mechanisms and maintains the generator at a fixed output level. Under such conditions the output of the generator remains constant irrespective of the change in the system frequency. A typical case is shown in figure 11. Although blocking of governor action may facilitate generator control for plant personnel, serious system problems may arise if too many generators are operating with blocked governors. These problems include:

a) system instability can occur since fewer units will be capable of reacting to system frequency deviations

b) restoration of system frequency to normal following a disturbance may take longer

c) loading on interties can be further aggravated during system disturbances

Fig. 11: Typical response of Generator when Governors are blocked

As per IEGC regulation 5.2 (g), the facilities available with/in load limiters, Automatic Turbine Run up System (ATRS), Turbine supervisory control, coordinated control system, etc., shall not be used to suppress the normal

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governor action in any manner and no dead bands and/or time delays shall be deliberately introduced except the permissible ripple filter of +/-0.03 Hz.

6.8. Restricted Governor Mode Of Operation

The normal operation is generally termed as Free Governor Mode of Operation or FGMO. The IEGC mandated a slightly modified version which is referred to as Restricted Governor Mode of Operation or RGMO. A generator in RGMO should not reduce generation in case of any rise in frequency up to 50.2 Hz. (for example if grid frequency changes from 49.3 to 49.4 Hz. then there shall not be any reduction in generation). Whereas for any fall in grid frequency, generation from the unit should increase by 5% limited to 105 % of the MCR of the unit subject to machine capability.

6.9. Exemption From Governor Operation

The Indian Electricity Grid Code regulations 5.2 (f) mandates that all thermal generating units of 200 MW and above and all hydro units of 10 MW and above, which are synchronized with the grid, irrespective of their ownership, shall have their governors in operation at all times. If any of these generating units is required to be operated without its governor in operation as specified above, the RLDC shall be immediately advised about the reason and duration of such operation. As per regulation 5.2 (f) (iii) all other generating units including the hydro stations with pondage up to 3 hours, Gas turbine/Combined Cycle Power Plants, wind and solar generators and Nuclear Power Stations have been exempted from governor operation till the Commission reviews the situation.

7. PRIMARY RESPONSE FROM LOAD / LOAD DAMPING

It is a common experience that induction motors/ synchronous motors and other rotating load draw less power from the system if frequency goes below rated value. The decline in load demand with decline in frequency is referred to as Load damping. In the figure below, curve A, indicates the variation in load demand with variation in frequency for motors / rotating loads. Typically a 1 % decline in frequency would cause a 2% decline in power drawn by the rotating load from the system. On the other hand resistance type loads such as lighting and heating load (shown as curve B) are not sensitive to frequency at all.

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Fig. 12: Load Damping Exhibited by different category of Load

For these loads, power demand remains constant throughout all frequency deviations. Curve C, represents the composite load damping curve for a power system having a mix of rotating loads and lighting / heating loads. Typically, a 1% reduction in frequency would result in 1.5% reduction in load demand for the entire power system. During frequency dynamic conditions, the load damping effects help in stabilization of frequency.

7.1. Estimation Of Connected Load

Considering the frequency dependence of load, assessment of true demand in any system would have to consider the frequency at which all loads are being recorded. For instance if the actual connected load at 50 Hz is P50 MW and if frequency drops to f Hz then

Reduction in demand due to reduction in frequency (assuming 1.5% load damping) would be P.

P = P50 x [(50-f) / 50] x 1.5

The demand recorded at changed frequency i.e. ‘f’ would be Pf and can be computed as follows:

Pf = P50 -P

= P50 – {P50 x [(50-f)/50] x 1.5}

= P50 {1-[(50-f)/50] x 1.5} Thus P50 = Pf / {1-[(50-f)/50] x 1.5}

In the present monitoring system, all MW recordings (i.e. P f) are at frequency ‘f’ and do not therefore represent the true indication of the connected load or the system demand. For estimating the connected load, the above formula has

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to be applied. P50 is also understood as frequency corrected load. The above formula however neglects the effect of voltage dependence of load.

8. EQUILIBRIUM FREQUENCY

Consider an isolated system with total load of 9850 MW (L= 9850 MW) operating initially at 50 Hz with all speed governors disabled. Suppose the load increases from 9850 MW to 10000 MW (i.e. L =150 MW). Since the governor droop line is vertical, the combined output of all the units remains constant at 9850 MW. Because of the imbalance, the frequency would drop. As the frequency declines the effective load in the system would decline and the operating point would start to slide down the load damping line. This would continue till the point where the effective load in the system is once again equal to the total generation at point C. If one assumes a load damping of 1.5% the frequency at point C would be 49.5 Hz (1% drop). So at point C, while the connected load is still 10000 MW, the actual load at this point is only 9850 MW.

Fig. 13: Equilibrium Frequency with Load Damping and Governor Response

With composite governor droop characteristics the load generation balance shall be reached by intersection of curve BC with AE at D. The frequency at point D would be lower than 50 Hz but higher than the frequency at point C.

The worst case scenario would be all speed governors disabled and only heating / lighting load is persisting in the system (zero rotating load). The frequency dip in such cases due to any load increase or tripping of unit would be very sharp and of very large magnitude. However, the above situation is unlikely as there is always some amount of rotating load in the system and the presence of such loads help in arresting the frequency dip to some extent.

Thus the equilibrium frequency after a disturbance would depend upon the amplitude of disturbance, primary response from the generators and the dynamic characteristics of connected load.

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Typical profile of the grid frequency in Northern Region with (27-Oct 2003) and without (27-Oct-2002) governor response is shown in figures below.

Fig. 14: Frequency Profile with and without Governor Response

Similar charts for Southern and Eastern Region when governor was in service are shown in Figures below:

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The above charts clearly indicate that with governors in service the frequency is more steady as the frequency fluctuations reduce drastically. 9. FREQUENCY RESPONSE CHARACTERISTICS

Primary Response is the characteristic displayed by load and generation within control areas, and therefore an Interconnection, in response to a

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significant change in load-resource balance. Because the loss of a large generator is much more likely than a sudden loss of load, primary response is typically discussed in the context of a loss of a large generator. The frequency response of a control area may be computed with the help of following steps.

• Actual net interchange immediately before disturbance = PA

• Actual net interchange immediately after disturbance = PB

• Change in net interchange = PB-PA

• Load (+) or generator (-) loss causing the disturbance = PL

• Control Area response = PB-PA-PL

• Change in Frequency = fA-fB

• Frequency Response Characteristics = p/f

The frequency response characteristic is known as stiffness constant or the system inertia. It is the ability of power system to oppose changes in frequency. Physically, the system inertia is loosely defined by the mass of all the synchronous rotating generators and motors connected to the system. If system inertia is high, then frequency will fall slowly during a system casualty such as a generator tripping off line. If system inertia is low, then frequency will fall faster during this casualty. Thus higher system inertia is better than lower system inertia because it will provide more time for operators to respond to the change in system frequency.

10. RATE OF CHANGE OF FREQUENCY

The general equation of the system behaviour following a loss of generation or load is as below.

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If the damping effect is neglected then the above equation gets simplified as below.

Therefore, df/dt can be computed if we have the value the system inertia constant (H). The system inertia constant is defined as the kinetic energy stored in the system per MVA. The system inertia constant on system base may be in the range of 3 to 10 seconds.

Assuming inertia constant as 8 seconds, the rate of change of frequency for a loss of 1500 MW in the system size of 60,000 MW operating at 50 Hz can be computed as below:

PL = 60000

PG = 60000-1500 = 58500 MW

P = 1500/58500 = 0.0256

fo = 50

H = 8

Df/dt = 0.0256 x{ 50/(2x8)}= 0.080 Hz/second

Fig. 17: Typical pattern of rate of change of frequency in the grid during a disturbance

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11. FREQUENCY CONTROL THROUGH MARKET MECHANISM

There is coupling between the reliability requirements of maintaining frequency and the commercial interest in Unscheduled Interchange energy. Frequency deviates when generation and load are not in balance. The interconnection does not “care” how load and generation are rebalanced as long as it is done quickly and accurately and that transmission constraints are respected. In India, the frequency linked Unscheduled Interchange mechanism has been devised for energy balance in real-time. It works on the basic principle that the settlement rate for any unscheduled interchange with the grid is high when the frequency is low (indicative of a generation shortage in the grid). Likewise the settlement rate for any interchange with the grid is low when the frequency is high (indicative of surplus generation in the grid). In the UI mechanism there are commercial incentives and disincentives so that the generators and load serving entities are encouraged so that the frequency is controlled collectively.

Fig. 18: Typical relationship between the system frequency and System Marginal Price12. DEFENSE MECHANISM

The defense mechanism for frequency control include flat frequency load shedding schemes, rate of change of frequency linked load shedding schemes and generator tripping. The present setting adopted for shedding load through Under Frequency Relay (UFR) and df/dt relays are shown in tables below.

Table 2: Setting of Under frequency Relay adopted in the regional grids

Region UFR Stage-I UFR Stage-II UFR Stage-IIINorthern Region 48.8 Hz 48.6 Hz 48.2 HzWestern Region 48.8 Hz 48.6 Hz 48.2 HzEastern Region 48.5 Hz 48.2 Hz 48.0 HzSouthern Region 48.5 Hz 48.2 Hz 48.0 HzNorth-eastern region

48.4 Hz - -

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Table 3: Setting of Rate of Change of Frequency adopted in regional grids

Df/Dt relay setting Stage-I Stage-II Stage-IIIEnabling frequency 49.9 Hz 49.9 Hz 49.9 HzRate of change 0.1 Hz/sec 0.2 Hz/sec 0.3 Hz/sec

There may be instances in the grid when the frequency may deviate to levels that may not be safe for the generating units. The typical setting in generating unit against abnormal frequency operation is shown in table below.

Table 4: Typical setting in generators against operation under abnormal frequency

Station Low Frequency setting in Hz High frequency settingNAPS 47.7 (Islanding) 51.5 Hz tripping (with 15 sec

time delay)RAPS-B 47.7 instantaneous 51.5 Hz tripping (with 10 sec

time delay) Ropar 47.5 Hz, 5 seconds time delay -Suratgarh 47.5 Hz, hand tripped -Kota 47.5 Hz, hand tripped - -Singrauli 47.5 Hz, alarm, hand tripped -Tanda 47.5 Hz, alarm, hand tripped - -Unchahar 47.5 Hz, Alarm, hand tripped -Rihand 47.5 Hz, alarm, hand tripped -Anpara 47.2 Hz, 5 sec, auto 51.8 Hz, run back to house

load (26 MW)Chamera-I 45.4 Hz -Chakera – II 46.0 Hz -

13. MONITORING FREQUENCY PROFILE

The power system frequency is continuously monitored in the control room of the State, regional and National Load Despatch Centre. There are digital as well as trend displays. At the end of the day the frequency profile is analyzed. Maximum frequency, minimum frequency, average frequency, standard deviation, frequency variation index, number of excursions outside the IEGC band and the % of time for which the frequency remained within/outside the IEGC band is computed and analyzed.

Frequency Variation Index = S { [( fn – 50 )2] / N } x 10

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14. REFERENCE

1. Central Electricity Authority, “Indian Electricity Rules, 1956” 2. Central Electricity Authority (Grid Standards) Regulation, 2010 3. Central Electricity Regulatory Commission, (Indian Electricity Grid Code)

Regulations, 2010 4. Central Electricity Regulatory Commission, (Unscheduled Interchange

charges and related matters) Regulations, 2010 5. Bauman, Hahn, Metcalf, “The effect of reduction on plant capacity and on

system operation”, Symposium on Plant Capability at Low frequencies and load relief, February 1955

6. Bhushan B., “Disadvantages of deviation from rated frequency”, Letter dated 22 Oct 1999 addressed to Secretary CERC

7. Kirby B.J., Dyer J., Martinez C., Rahmat A. Shoureshi, R. Guttromson J. Dagle, “Frequency Control Concerns in the North American Electric Power System”, Report by Consortium for Electric Reliability Technology Solutions, December 2002

8. Illian H. F., “Frequency Control Performance Measurement and Requirements”, Energy Marc Inc., December 2010

9. Cohn N., “Control of Generation and Power flow on interconnected systems”, John Wiley and sons, Inc., 1971

10. WECC control working group, “WECC Tutorial on Speed Governors”, February 1998

11. NERC Training Resources Working Group, “NERC Training Document Understand and Calculate Frequency Response”, February 2003

12. Video training workbook-Power System Operation -13,14 &15, Equipment response to abnormal conditions-I

13. Module on load frequency control in the PTI Advanced System Operator Courseware

14. NERC, ‘Frequency Response Standard Whitepaper’, April 2004 15. UCTE, ‘Operation handbook Annex-I Load frequency control

performance’, 2004 16. British Electricity International, Modern Power Station Practice-System

Operation Volume-L’ 17. Kundur P., ‘Power System Stability and Control’, McGraw Hill, 1994 18. Nicoud G.,‘System Operational Procedures-Reviewing procedures and

philosophies in the Indian practice for more coordinated and integrated operation’ 1988

19. Nagrath I.J., Kothari D.P. ‘Power System Engineering’ Tata McGraw Hill 1999

20. Narasimhan S.R., “Effect of System frequency on consumer demand” (Notes)

21. Berger A. W., Schweppe F.C., “Real-time pricing to assist in Load Frequency control, IEEE transactions on Power System, Vol. 4, No. 3, August 1989

22. Bhushan B., ‘A primer on Availability Tariff’, June 2005 23. Soonee S K., ‘Realising A Collective Vision through Non-Cooperation’,

Workshop on Electricity Market in India and learning from developed markets”, Delhi, March, 2005

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24. Soonee S.K., Narasimhan S.R., Pandey V., ‘Significance of Unscheduled Interchange Mechanism in the Indian Electricity Supply Industry’, International Conference on System Operation under deregulated Regime, 2006

25. Soonee S.K., S.C.Saxena, ‘Frequency Response Characteristics of an interconnected power system-A case study of regional grids in India’6th International R&D conference on sustainable development of water and energy resources-needs and challenges, Lucknow, February 2007

26. Dwarkanath, “Under Frequency Trend Relay as Power System Savior”, International Seminar on “Grid Stability and Load Management”, GRIDSAFE –1995, 12-14 January, 1996, I.E. (I), Nagpur, India

27. Report of the sub-group constituted by NR-OCC to Review the df/dt or rate of change of frequency relay setting In Northern Region, May 2007.

-o0o-

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TABLE OF CONTENTS

No. Topic Page No.

1 Reactive Power Fundamentals 153-166

2 Reactive Power Sources and Sinks 167-184

3 Capacitors 185-200

4Reactive Power Compensation in Transmission System

201-212

5Reactive Power Compensation in Distribution System

213-227

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CHAPTER - 1

REACTIVE POWER FUNDAMENTALS

1.0 Introduction

Voltage is proportional to the magnetic flux in the power system element. Most of the Power System elements are reactive in nature. They absorb / generate reactive power depending on system loading conditions. The balance in reactive power availability and requirement at a node indicates steady voltage. Drawal of reactive power leads to reduction in voltage and supply of reactive power leads to increase in voltage at the node. Ideally, the reactive power balance should be effected within each region, within each distribution system.

Excess of MVAr high voltageDeficit of MVAr Low VoltageMVAR balance Good voltage low system losses

A great many loads consume not only active but also reactive power. The electric network itself both consumes and produces reactive power. Transmission and distribution of electric power involve reactive power losses due to the series inductance of transformers, overhead lines and underground cables. Lines and cables also generate reactive power due to their shunt capacitance; this generation of reactive power is, however, only of significance at high system voltages.

During the steady-state operation of an AC power system the active power production must match the consumption plus the losses, since otherwise the frequency will change. There is an equally strong relationship between the reactive power balance of a power system and the voltages. In itself, a reactive power balance will always inherently be present, but with unacceptable voltages if the balance is not a proper one. An excess of reactive power in an area means high voltages: a deficit means low voltages. The reactive power balance of a power system also influences the active losses of the network, the heating of components and, in some cases, the power system stability.

Contrary to the active power balance, which has to be effected by means of the generators alone, a proper reactive power balance can and often has to be effected both by the generators and by dispersed special reactive devices, producing or absorbing reactive power. The use of shunt reactive devices. i.e. shunt compensation, is a straightforward reactive-power compensation method. The use of series capacitors, i.e. series compensation is a line reactance compensation method.

No special reactive compensation devices were used in the early AC power systems, because the generators were situated close to the loads. As networks became more widespread, synchronous motors, small synchronous compensators and static shunt capacitors were adopted for power-factor correction. Ever larger synchronous compensators were installed in transmission systems. Along with the development of more efficient and economic capacitors, there has been a phenomenal growth in the use of shunt

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capacitors as a means of furnishing reactive power, particularly within distribution systems. With the introduction of extra-high-voltage lines, shunt reactors and series capacitors became important compensation devices. The latest development is the Thyristor-controlled static var compensator, which is now well established not only in high- power industrial networks but also in transmission systems.

In the following a distinction is made between transmission and distribution systems and also between different voltage ranges in terms of HV, EHV, etc. It should therefore be appropriate to explain briefly these terms.

Classification of System Voltages

Voltage Level in kV Category of Voltage <33 kV Distribution System

33 kV to132 kV Sub. Transmission System230 kV to 400 kV HV Transmission System750 kV and above UHV System

Transmission systems form those parts of power systems conveying comparatively large amounts of electrical power. They link the generating sources with the distribution systems and interconnect parts of the power system or adjacent power systems. Distribution systems form the continued links to the consumers. The boundary between transmission and distribution systems is not very well defined. Systems for voltages higher than 132 KV are usually called transmission systems. Systems for voltages lower than 33 KV are usually called distribution systems. Systems in the range 33 to 132 kV are called distribution, sub transmission systems.

All the figures given in this introduction refer to the highest voltage for equipment.

1.1 Need for management of reactive power

In an integrated power system, efficient management of active and reactive power flows is very important. Quality of power supply is judged from the frequency and voltage of the power supply made available to the consumers. While frequency is the measure of balance between power generated (or power available) and MW demand impinged on the system, the voltage is indicative of reactive power flows.

In a power system, the ac generators and EHV and UHV transmission lines generate reactive power. Industrial installations whether small or large as also the irrigation pump motors, water supply systems draw substantial reactive power from the power grid.

The generators have limited defined capability to generate reactive power- this is more so in respect of large size generating units of 210 MW/500 MW

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capacity. Generation of higher reactive power correspondingly reduces availability of useful power from the generators. During light load conditions, there is excess reactive power available in the system since the transmission lines continue to generate the reactive power thereby raising the system voltage and this causes reactive power flows to the generators.

Particularly in India, the load curves show wide fluctuations at various hours of the day and in various seasons of the year. When load demand is heavy, there is low voltage, which is harmful to the consumers as well as utility’s installations. Burning of motors occur. When load demand is very low, high voltage occurs in the system and this has harmful effect on insulation of power transformers. Failure of power transformers occur.

For better efficiency, it is necessary to reduce and minimize reactive power flows in the system.

Besides harmful effects, the reactive power flows also affect the economy adversely both for the utility and the consumer. If reactive power flows are reduced i² R power losses as well as i² X losses are reduced. The generators can produce additional active power. If the consumer reduces reactive power requirement his demand KVA is reduced. For energy conservation also there is need to reduce reactive power demand in the system.

It is therefore very clear that for efficient management of power system and for improving the quality of electric supply, it is very essential to install reactive compensation equipment. Such installations are necessary and essential for utility as well as the consumer. Infact the utility should be made responsible for making available only the active power to the consumer. Unfortunately, in India, the responsibilities of users are not well defined and there is not enough realization in this regard. Utilities have now introduced power factor clause in the tariff structure. However. It would be worthwhile to note that even a 90% power factor load requires 43% reactive power from the grid.

1.2 Basic Principles

A phasor description of voltage and current, the reactive power supplied to an AC circuit is the product of the voltage and the reactive (watt-less) component of the current, this reactive current component being in quadrature with the voltage.

A single-phase circuit according to Figure 1.1 the reactive power Q is given by

Q= VIsin (1)

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Unit is volt-ampere reactive (VAR) The sign of Q is a matter of convention, it depends on the definition of the direction of . According to the IEC the sign shall be such that the net reactive power supplied to an inductive element is positive. Consequently, the net reactive power supplied to capacitive element is negative. In the past the opposite sign convention has also been used. With the sign convention as base, reactive power is said to be produced/generated by overexcited synchronous machines and capacitors, and consumed or absorbed by under excited synchronous machines, inductors, etc.Reactive power can be considered as a convenient evaluation quantity, giving information about the watt-less current, which greatly influences voltages, active losses.1.3 Sources and sinks of Reactive power :

S.No. Sources (Q- Generation) Sinks (Q – Absorption)1 Gen. Over excited Gen. Under excited2 Transmission Lines - charging Transmission Lines - series

reactance drop3 Shunt Capacitors Shunt Reactors4 Static Var Compensators (Q –gen

mode)Static Var Compensators (Q – absorb mode)

5 Series Capacitors (Cse) -

6 Synchronous Condenser over excited

Synchronous Condenser under excited

7 Loads -Capacitive Loads - Inductive

1.4 Power transmission in a Transmission line

Let Vs =Sending end voltageVr =Receiving end voltageSr = Receiving end complex powerPr = Receiving end active power Qr = Receiving end reactive power = The angle difference between Vs and VrIr = Receiving end currentX = Line reactancePs = Sending end active powerQs = Sending end reactive power

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G M

VsM

Vr0Ir

Sr

j X

Fig. 1.2 Simple Transmission System

Sr = Pr +j Qr = Vr . Ir* (1)

= Vr

=

Pr = (2)

For a loss less line.P and are closely related.

Qr = (3)

Qs = (4)

For small angles of

Qr = (5)

Qs = (6)

Q and V are closely coupled.

Inferences:If V1and V2 are the sending end and receiving end voltages

The transmission capacity increases as the square of the voltage level1. the direction of MW flow is determined by

V1 leading V2 P is 1 2V1 lagging V2 P is 2 1

2. Magnitudes of V1 and V2 do not determine the MW flow direction3. Though P1=P2, Q1 Q24. The reactive loss in line reactance is

5. If Vs Vr the MVAR flows 1 2If Vr Vs the MVAR flows 2 1

1.5 Power Losses in a Transmission line:

Losses across the series impedance of a transmission line are I2 R and I2 X.

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Where I = ;

I* =

I2 = I.I* =

Ploss = I2R = (7)

Qloss =I2X = (8)

Hence in order to minimize losses we have to minimize the transfer of Q.

1.6 Voltage Regulation

Voltage regulation is defined as the change of voltage at the receiving end when rated load is thrown off, the sending end voltage being held constant.

ETh =V0 +j X I =V + j X

= V + (9)

The voltage rise term in phase with V depends on Q.

The angle, depends mainly on the quadrature term involving P.

Three methods of system voltage control are available : (a) Varying excitation of generators, (b) Varying the turns ratio of transformers by OLTC and (c) Varying shunt compensation.

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Vr X.

Qr

V

ETh

X.Pr

VFig 1.3 Voltage regulation in a loss less system

Shunt compensation is drawing or injection of reactive power at a node. Reactor absorbs reactive power and so reduces system voltage. Capacitor injects reactive power and so increases system voltage.

1.7 Short circuit capacity MVA (10)

Where V = Phase to phase voltage in kV

If = The three phase fault current in k.A.

Expressed in p.u parameters

Ssc = (V0-)(If) p.u. = If p.u. = (11)

V0- =The prefault voltage in p.u. = 1.0 p.u.

XTh = Thevinin impedance = Driving point impedance of the network.

The change in voltage when certain quantity of reactive power is supplied to the system is given by

WhereQ = Change in Q injectionSsc =Short circuit capacityV = Change in voltage in per unit

1.8 Reactive power - physical analogy

The reactive power is the extra effort needed to pull a load along the rail when the effort, s is at an angle, to the rails.

1.9 Power transfer components

Transformers, overhead lines and underground cables make up the major AC power transfer components and are discussed in this subsection.

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P

Q

Fig 1.4. Physical analogy for Active and Reactive powers

S

1.9.1 Transformers

Figure 1.5 shows a simple equivalent circuit of a two-winding transformer. The series reactance X is of main interest, usually lying within the range 0.05 to 0.15 p.u. based on the transformer power rating, with low values for small and high values for large transformers. The resistance is usually negligible. The total reactive power losses due to the magnetizing shunt reactance Xm of many small transformers within a distribution system can, however, be of some importance. The magnetizing reactive power may also increase rapidly with the voltage level, due to core Saturation.

1.9.2 Overhead lines

Overhead lines and underground cables are distributed-constant circuits, which have their series resistance, series inductance and shunt capacitance distributed uniformly along its length. Figure 1.6 shows a lumped-constant equivalent circuit. If we assume constant operating voltages at the ends, the reactive power generated due to the capacitance, the charging reactive power, is practically independent of the power transferred. Particularly when we are dealing with long EHV lines, the so-called Surge Impedance Load (SIL) P0 or natural load of an uncompensated line is a convenient value for reference purposes. It is given approximately by:

(12)

where V = voltage, line-line kV

b = susceptance mho/kmx = reactance ohm/km

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Fig 1.5 Equivalent Circuit of Transformer

A loss less line (a reasonable approximation of an EHV line) transferring an active power P0 and with equal voltages at the line ends has reactive power balance. The reactive power loss due to the line inductance is equal to the reactive power generated by the line capacitance.

Operating voltage kV

SILMW

Line charging Mvar/km

XOhm/km

X/R

0.410130220400500750

--501305509102200

--0.050.140.61.02.3

0.400.400.400.400.330.300.28

0.50.536151630

Table 1. Typical values of overhead line characteristics at 50Hz.

Table 1 gives typical values of overhead line characteristics at 50Hz. At 60 Hz the SIL values are the same while the line charging, X and X/R values are 20 per cent higher. The SIL is usually much lower than the thermal rating. Below 69 kV the line charging is usually negligible while it is a significant source of reactive power for long lines of higher system voltages.

Paradoxically, the series reactance is fairly independent of the system voltage, assuming a single conductor. The lower values at 400 kV, 500 kV and 750 kV illustrate the effect of the necessary use of bundle conductors for these system voltages. In reality there is a great spread in the X/R values, for a system voltage under consideration, in particular at low system voltages. The figures are however, included in order to illustrate that the X/R ratio increases rapidly with the system voltage.

1.9.3. Underground cables

Table 2 gives sample values of underground cable characteristics. The spread in parameter values for a system voltage under consideration is very much larger than for overhead lines, depending on the cable type, size and conductor geometry and spacing. Except for low voltage cables, the SIL is usually much larger than the thermal rating. The line charging of polyethylene insulated cables, now being introduced at ever higher system voltages, is much lower, e.g. 50 per cent of that of paper-insulated cables.

Operating voltage kV

SILMW

Line charging Mvar/km

XOhm/km

X/R

0.410130220400

-350010003200

-0.012413

0.070.100.150.180.2

0.30.4269

Table.2 Sample values of underground cable characteristics at 50 Hz. 0.4. 10 kV:PVC, 132,400kV paper-insulated cables.

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1.10 Loads

A great many loads consume not only active but also reactive power. The Industry wise power factor is generally observed to be as follows:

Some typical values of reactive power consumption of individual loads are given below:

Induction motors 0.5 to 1.1 kvar/kW, at rated output.

Uncontrolled rectifiers 0.3 kvar/kW.

Controlled rectifiers usually consume much more kvar/kW than uncontrolled ones and with dependence on the rectifier delay angle.

Arc furnaces around 1 kvar/kW.

Both controlled rectifiers and arc furnaces of steel mills have a reactive power consumption characterized by a high average value and fast variations. Purely resistive loads, like filament lamps and electric heaters, do not, of course,

consume reactive power.The synchronous motor is the only type of individual load, which can produce reactive power. it consumes reactive power when under excited and produces reactive power when overexcited. Synchronous motors are usually operated overexcited and thus usually produce reactive power.Individual loads may, of course, vary within short or long time ranges. The composite loads of a power system. Each one being the total load of a certain area, usually vary with the time of the day, the day of the

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Fig.1.7 Examples of load

curves

INDUSTRY POWER FACTOR

Textiles 0.65/0.75Chemical 0.75/0.85Machine shop 0.4 / 0.65Arc Welding 0.35/ 0.4Arc Furnaces 0.7 / 0.9Coreless induction furnaces and heaters 0.15/0.4Cement plants 0.78/0.8Garment factories 0.35/0.6Breweries 0.75/0.8Steel Plants 0.6 / 0.85Collieries 0.65/0.85Brick Works 0.6 / 0.75Cold Storage 0.7 / 0.8Foundries 0.5 / 0.7Plastic moulding plants 0.6 / 0.75Printing 0.55/0.7Quarries 0.5 / 0.7

week and the season of the year and may also grow from year to year. The consumer demand for reactive power varies in a somewhat similar way to the demand for active power. Figure 1.7 illustrates how the active and the reactive power supplied from a transmission substation into a load area, with mixed industrial and domestic loads, may vary during a Sunday and a Monday.The resultant active power demand of a power system varies roughly as the variation of total toad. The resultant reactive power demand may vary considerably more due to the changing series reactive power losses in the networks.

1.11. Relationship of voltage to reactive power

As regards the study of terminal voltages of a transmission or a distribution link, the link can be represented by the series impedance only if the shunt admittances of the equivalent circuit are included in the treatment of the connecting parts of the power system, Fig. 1.8. The link may be an overhead line, an underground cable, or a transformer. The voltage drop, i.e. the scalar voltage difference, is defined by:

V= V1 – V2 (13)

The Phasor diagram of Figure 1.8, for a case with lagging power factor, shows that it can be approximately expressed by the following equations: V=RI cos+XI sin (14) V= (RP+XQ) / V2 (15)

The accuracy of the equations (14) and (15) is better, the less the voltage-angle difference is. The equations are usually sufficiently accurate for calculations concerning a single link with lagging power factor. The equations are less accurate and should not be used in calculations for -leading power factor. Precise calculations concerning a complete network are, nowadays, performed by means of computer power flow programs.

The equation (15) is, however, generally useful for qualitative discussions of voltage versus reactive power. For transformers, R can always be disregarded. For transmission (not distribution) lines and cables. X is usually much larger than R. For all these many links, where X is -much larger than R, there will evidently be a much greater influence on V per kvar of reactive power than per kW of active power transmitted.

When power is supplied through a single link, Figure 1.8, assuming V1 constant, V2 varies with changes in P and Q. Load variations create voltage variations if not counteracted. This is a general, and sometimes -troublesome, operation feature of AC power systems.

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There are three major methods of power system voltage control: Varying the excitation of the generators by means of their

excitation systems. Varying the turn’s ratio of transformers by means of their on-load

tap changers. Varying the shunt compensation, where applied.

By shunt compensation is meant drawing or injection of reactive power, at a point of a power system by means of a shunt-connected device, which is installed for this sole purpose. Drawing reactive power. e.g. absorption by means of a shunt reactor, effects voltage reduction. Injection of reactive power, e.g. production by means of a shunt capacitor, effects voltage rise. The equation (15) and Figure 1.8 show how shunt compensation influences the voltage. The voltage-change directions mentioned arise because the network equivalent impedance has an inductive character at the fundamental frequency. The shunt compensation may be fixed, switchable in steps or continuously controllable. Around the nominal voltage, the voltage change V, when the shunt compensation is changed in step, is approximately expressed by;

V = (16)

WhereQ- change in nominal three phase reactive power injection Mvar

Ssc- Short-circuit capacity in MVA

Adjacent generators with voltage regulators and adjacent transformers with voltage-relay controlled on-load tap changers will, of course, more or less reduce the voltage change after a certain time. By series compensation is meant compensation of line inductive reactance by means of a capacitor in series with the line, thus reducing the effective inductive reactance of the line and the effects thereof.

1.12 PV Curves

PV Curves are the product of parametric analysis. Take into consideration the system shown at right. Power is transferred from the Sending Area to the Receiving Area via a set of transmission lines forming an Interface. As the transfer increases, the conditions on the lines and buses along the transfer path, including those within the Sending and Receiving area, change. The voltages may drop, flows on branches may increase or decrease.

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Monitoring voltage at a particular bus and plotting this against the power transfer produces a familiar diagram known as the PV Curve. A sample curve is shown below. When the voltage at the selected bus goes below some pre-defined criteria, then the transfer at which this occurs is the Low Voltage transfer limit for that bus. Ignoring the low voltage and continuing to increase transfer would eventually bring the curve to a point where the system collapses. The point of collapse can likewise be designated as the Voltage Collapse transfer limit.

In PSS™TPLAN, PV curves are provided as a distinct Analytical Engine. As such it is provided with powerful features:

Easy setup Comprehensive results Adaptive step size. You define a range for the transfer increment, and

PSS™TPLAN will select a step size which will maintain the accuracy of the simulation at minimum loss of resolution.

Non-divergent power flow. The last point on the curve is always accurately determined by a special algorithm which can identify divergence.

1.13 Need to optimize reactive power resources:

The need to optimize reactive power sources is essential to

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Capacity utilization of existing transmission facilities for power transfer.

Maximize the existing reactive power resources to minimize investment in additional facilities.

Minimize transmission losses Improve system security Maintain power supply quality by maintaining bus voltages close to

nominal value.

1.14. Remarks

Active power must, of course, be transmitted from the generators to the loads. Reactive power need not, and with regard to voltage differences, losses and thermal loading as discussed in the preceding subsections, should not be unnecessarily transferred. Ideally, a reactive power balance should be effected within each region of a power system, within each transmission system and within each distribution system. In practice, however, this principle is not always followed for one reason or another. The subject of reactive power compensation is easy to understand if we consider a single link of a power system, but quite complex when we consider an entire power system with its different conditions and behaviors.

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CHAPTER – 2

REACTIVE POWER SOURCES AND SINKS

2.0 Introduction

Sources of reactive power are Generating units Synchronous condenser On-load tap changers and phase-shifting transformers. Capacitors and reactors Static compensators.

Power system component characteristics

A brief look at characteristics for power system components will help to explain reactive power matters. The role of power system components in reactive power control are briefed below.

2.1 Generators

The purposes of generators are to supply the active power, to provide the primary voltage control of the power system and to bring about, or at least contribute to, the desired reactive power balance in the areas adjacent to the generating stations. A generator absorbs reactive power when under excited and it produces reactive power when overexcited. The reactive power output is continuously controllable through varying the excitation current. The allowable reactive power absorption or production is dependent on the active power output as illustrated by the power charts of Figures 2.1 and 2.2. For short-term operation the thermal limits are usually allowed to be overridden.

The step-response time in voltage control is from several tenths of a second and upwards. The rated power factor of generators usually lies within the range 0.80 to 0.95. Generators installed remotely from load centers usually have a high rated power factor; this is often the case with large hydro-turbine generators. Generators installed close to load centers usually have a lower rated power factor. In some cases of large steam-turbine generators the rated power factor may have been selected at the lower end of the above range in order to ensure reactive power reserve for severe forced outage conditions of the power system.

Fig 2.1 Typical Power chart for large steam turbine and gas turbine generators

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wherea — Turbine power limitb — Stator winding thermal limitc — Field winding thermal limitd — Steady-slate stability limit with proper AVRe — Assumed intervention curve of under excitation limiter

Fig.2.2. Typical power chart for large hydro-turbine generators (salient-pole machines)

Large generators are usually connected direct to transmission networks via step-up transformers. The terminal voltage of a large generator is usually allowed to be controlled within a ± 5% range around the nominal voltage, at rated load. In most countries the generator step-up transformers are usually not equipped with on-load tap changers.

Excitation Control: The MVAR output of a generator is dependent on its excitation. The MVAR is generated during over excitation and is absorbed during under excitation. The rotor current depends on the excitation. The rotor winding temperature, the air gap temperature and the machine temperature increase during over excitation. The winding temperature is limited to about 90oC during normal loading. It increases to 100 – 105oC during over loading. The machine which is already over heated due to MVAR generation can not take MW load to its full capacity. Hence MW load is to be compromised when the unit is excited beyond its normal limits.

When the unit generates MVAR and supplies to the system, the system voltage profile around the generating station increases. This increase in voltage is more in first neighbourhood. The load end voltages which are beyond, say second neighbourhood will not get effected because of this unit excitation. Hence the influence of a unit on voltage profile in the system is local in nature. The load end voltages can not be controlled by the generating units.

However depending on the capability curve of the generating unit and as long as margin is available in the unit, it can be used to control the system voltages in its vicinity.

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The change in the voltage V in the first neighbourhood of the generating station depends on the relation

V = Q/S in p.u.Where V = change in bus voltage in pu Q = Amount of Q supplied through over excitation in p.u. S = Fault level of the system at first neighbourhood in p.u.

2.2 Shunt reactor

A shunt reactor is a reactor connected in shunt to a power system for the purpose of absorbing reactive power. In some cases where a fixed or mechanically switched shunt reactor can be used with regard to the voltage control requirements. It is usually the most economic special means available for reactive power absorption. The majority of shunt reactors are applied in conjunction with long EHV overhead lines. They are also applied in conjunction with HV and EHV underground cables in large urban areas.

Shunt reactors in use range in size from a few Mvar at low medium voltages and up to hundreds of Mvar.

Shunt reactors are necessarily installed to suppress high voltage during light load conditions. For 400kV and UHV lines, shunt reactors are directly connected on line. This is for the purpose of compensating leading charging MVAR released by the line. Shunt reactors are also connected on tertiary delta windings of autotransformers so that these can be switched on during light load periods.

Reactor Operation: The shunt reactor is a coil connected to the system voltage and grounded at the other end. It draws the magnetizing current, which is purely inductive, from the system and hence forms an inductive load at the point of connection. Hence the reactor absorbs reactive power from the system as long as it is connected to the system. Hence it is complimentary to a capacitor bank in its function. The reduction in voltage at the point of connection is given by V = Q/S, all expressed in p.u. terms.

The reactors are required to be used at EHV voltages of 400 kV and above, as the line charging at this voltage is quite significant, it increases the receiving end voltage to unacceptable limits under light load conditions. A 400 kV line generates about 55 MVAR per 100 km and hence this Ferranty effect is high for lines of 300 km and above.

Two types of reactor connection are adopted in EHV systems.

A) The bus reactor, which is connected to the bus through a circuit breaker and hence can be switched as and when required.

B) The line reactor; which is connected to the line through only an isolator and hence can be removed from the system only when the line is switched off.

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The functions of both bus reactor as well as line reactor are same. They absorb the reactive power from the system depending upon their capacity.The bus reactors are switchable and hence are cut-in whenever the system voltage is higher and can be cut-off from the system whenever the system voltage reduces.

The line reactors are permanently connected to the lines and hence the system. Their role is to –

a) Reduce the effect of line chargingb) Provide a least impedance path for the switching over voltages

generated in the system due to inductive load currents’ switching. The switching over voltages are of power frequency and equal to 1.5 to 2.5 p.u. in magnitude.

c) When the EHV lines have single phase switching facility and auto reclose protection scheme is implemented, the abnormal voltages developed across the circuit breaker can be contained only with a line reactor on the line side.

d) The line reactors provide a least impedance path for low frequency (power frequency) switching over voltages. Hence they act as surge diverters for power frequency over voltages. The lightning over voltages cannot pass through the line reactor because of their high frequency.

2.3 Shunt capacitors

A shunt capacitor is a single capacitor unit or, more frequently, a bank of capacitor units connected in shunt to a power system for the purpose of absorbing reactive power. When a fixed or mechanically switched shunt capacitor can be used with regard to the voltage control requirements, it is the most economic means available for reactive power supply. The majority of shunt capacitors are applied within distribution systems of different types: Industrial, urban, residential and rural. They have a widespread use there, for power-factor correction. Some shunt capacitors are installed in transmission substations. Very large shunt capacitor banks (usually filters) are to be found in HVDC terminal stations.

Shunt capacitors in use range in size from a single unit rated a few kvar at low voltage up to a bank of units, rated hundreds of Mvar.

Capacitor Operation: The capacitor banks are reactive power sources. They produce reactive power equal to their rating when connected to the bus. In order to keep the insulation costs less, they are connected to the system at distribution voltage levels, e.g. 0.4 kV, 11 kV, 33 kV etc.

The output of a capacitor bank is Qc = V2 c

Where Qc = output in MVARV = the system voltage in k.V.C = in farads

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Hence the output is proportional to the square of the voltage. If the system voltage to which the capacitor bank is connected reduces to 0.9 p.u. the MVAR generated by the capacitor reduces to 0.81 p.u. Hence the performance of a capacitor bank will be poor under low voltage conditions, at which time it is required most.

The influence of a capacitor bank on the system voltage is again local like in case of a generator. It is most pre dominent at the bus to which it is connected. Its effect gets reduced as we go to next neighbourhood. The change in voltage at the point of connection is governed by the relation V = Q/S

Where V = change in bus voltage in pu Q = Amount of Q supplied through the capacitor bank in p.u. S = Fault MVA of the bus in p.u.

Hence it is possible to compute the capacitor requirement of the system at a location using

Q = (V)(S)

where Q is the amount of Q to be supplementedV is the voltage raise required to reach the nominal value in p.u.S is the fault level of the system in p.u.

Outstanding features of shunt capacitors are their low overall costs and their high application flexibility. An unfavorable characteristic, most important in conjunction with major outages and disturbances, is that they provide the least support at the very time when it may be most needed, because the reactive power output is proportional to the voltage squared. If used in a proper mix with other reactive power sources, this is, however, no obstacle to an extensive use of shunt capacitors. The losses of modern shunt capacitors are of the order of 0.2w/Kvar, including the losses of fuses and discharge resistors.

Shunt capacitors are useful in Power factor correction Voltage control and reactive power balance Reducing transmission losses Meeting requirements of reactive loads

Pf correction by shunt capacitors is by far the most satisfactory and economical method. The static capacitor owing to its low losses, simplicity and high efficiency, is finding very wide and universal use for pf correction.

A detailed description on construction, operation, protection and trouble shooting of capacitor banks is provided in Chapter 3.

2.4 Transformer Tap Changing

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A transformer in the grid is like a node. Its voltage is maintained by the requirement and availability of reactive power at its terminals. If the HV voltage is low, due to bucking tap at, say -5, for e.g. at 0.96 pu the HV bus will get a net reactive power in-flow of say 200 MVAR through its EHV transmission network. The same reactive power flows towards the LV bus. The LV bus voltage now increases. This is illustrated in Fig 2.3.

If the transformer tap is raised to say 5, it is now boosting the HV voltage to say, 1.02 pu. Now the reactive power in-flow reduces to HV bus, to say 20 MVAR. This reduced MVAR is flowing to LV bus. Hence the LV bus voltage reduces. This is illustrated in Fig 2.4. Hence the transformer tap only alters the number of turns in the HV winding there by altering the HV voltage. If this HV voltage is less than the neighbourhood voltage it receives MVAR, if it is more, then it pumps MVAR to its neighbourhood. The LV bus voltage is maintained only as a consequence of MVAR inflow or outflow to it from the HV bus.

2.5 Synchronous condensers

Synchronous condenser is another reactive power device, traditionally in use since 1920s. Synchronous condenser is simply a synchronous machine without any load attached to it. Like generators, they can be over-exited or under-exited by varying their field current in order to generate or absorb reactive power, synchronous condensers can continuously regulate reactive power to ensure steady transmission voltage, under varying load conditions. They are especially suited for emergency voltage control under loss of load, generation or transmission, because of their fast short-time response. Synchronous condensers provide necessary reactive power even exceeding their rating for short duration, to arrest voltage collapse and to improve system stability.

Synonymous terms are synchronous compensator and synchronous phase

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modifier. The synchronous compensator is the traditional means for Continuous control of reactive power. Synchronous compensators are used in transmission systems: at the receiving end of long transmissions, in important substations and in conjunction with HVDC inverter stations. Small synchronous compensators have also been installed in high-power industrial networks of steel mills; few of these are in use today. Synchronous compensators in use range in size from a few MVA up to hundreds of MVA.

Both indoor and outdoor installations exist. Synchronous compensators below, say, 50 MVA are usually air-cooled, while those above are usually hydrogen-cooled. Modern synchronous compensators are usually equipped with a fast excitation system with a potential-source rectifier exciter. Various starting methods are used; the modern one is inverter starting.

The size of a synchronous compensator is referred to the Continuous MVA rating far the generation of reactive power. In the generating mode of operation it usually has a rather high short-time overload capability. The absorption capability is normally of the order of 60 per cent of the MVA rating, which means that the control range is usually 160 per cent of the MVA rating. The reactive power output is continuously controllable. The step-response time with closed-loop voltage control is from a few tenths of a second, and up. The losses of hydrogen-cooled synchronous compensators are of the order of 10 W/kvar at rated output. The losses of small air-cooled machines are of the order of 20 W/kvar at rated output.

In recent years the synchronous compensator has been practically ruled out by the SVC, in the case of new installations, due to benefits in cost performance and reliability of the latter. One exception is HVDC inverter stations, in cases where the short-circuit capacity has to be increased. The synchronous compensators can do this, but not the SVC.

Comparison between Synchronous Condenser and shunt capacitor

Sl.No Synchronous condenser Shunt capacitor

1. Synchronous condenser can supply kVAR equal to its rating and can absorb upto 100% of its KVA rating

Shunt capacitor should be associated with a reactor to give that performance

2. This has fine control with AVR This operates in steps

3. The output is not limited by the system voltage condition. This gives out its full capacity even when system voltage decreases

The capacitor output is proportional to V2 of the system. Hence its performance decreases under low voltage conditions

4. For short periods the synchronous condenser can supply KVAR in excess of its rating at nominal voltage

The capacitor can not supply more than its capacity at nominal voltage. Its output is proportional to V2.

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5. The full load losses are above 3% of its capacity

The capacitor losses are about 0.2%

6. These can not be economically deployed at several locations in distribution

The capacitor banks can be deployed at several locations economically in distribution

7. The synchronous condenser ratings can not be modular

The capacitors are modular. They can be deployed as and when system requirements change

8. A failure in the synchronous condenser can remove the entire unit ability to produce KVAR. However failures are rare in synchronous condensers compared to capacitors

A failure of a single fused unit in a bank of capacitors affects only that unit and does not affect the entire bank

9. They add to the short circuit current of a system and therefore increase the size of (11kV etc.) breakers in the neighbourhood.

The capacitors do not increase the short circuit capacity of the system, as their output is proportional to V2

10. This is a rotating device. Hence the O&M problems are more

These are static and simple devices. Hence O&M problems are negligible

2.6 Thyristor-controlled static var compensators (SVCs)

A Thyristor-controlled static var compensator is a static shunt reactive device, the reactive power generation or absorption of which can be varied by means of Thyristor switches. The adjective’ static’ means that, unlike the synchronous compensator, it has no moving primary part. Because it is the latest developed means of reactive compensation, it will be described and discussed in greater detail than the other devices. In a strict sense, the term static var compensator covers not only Thyristor-controlled compensator but also other, types and in particular, the self-saturated iron-core reactor type. Even though the self-saturated reactor compensators introduced before the Thyristor-controlled one, the later completely dominates the applications of compensators in transmission systems, covering more than 95 per cent of all compensators. Today, it also leads industrial applications in conjunction with arc furnaces. The following description is restricted to Thyristor-controlled compensators utilizing traditional Thyristor (not GTO Thyristor).

As early as the first half of the 1970s the SVC became a well-established device in high-power industrial networks, particularly for the reduction of voltage fluctuations caused by arc furnaces. In transmission systems the breakthrough came at the end of the 1970s. Since then, there has been an almost explosive increase in the number of applications, in the first place as an alternative to synchronous compensators, but also for a more extensive use of

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dynamic shunt compensation, i.e. of easily and rapidly controllable shunt compensation.

Compensators in use range in size from a few Mvar up to 650 Mvar control range, and with nominal voltages up to 765 kV.

2.6.1. Function of SVC’s in Power systems

SVCs are used to improve voltage regulations, improve power factor, reduction of voltage and current unbalances, damping of power swings, reduction of voltage flicker, improved transient stability of the system etc. This can result in saving in operational costs, increased power transfer capability, reduced line losses, higher availability of power etc.

2.6.1.1 Voltage control in Power systems

The voltage variations in power systems are caused due to load switching, power system elements’ switching. These variations are compensated by SVC. Three phase system voltages are compared with adjustable voltage reference and the error signal is used to generate firing pulses. All three phases are fired at the same angle making a balanced control system. A voltage droop proportional to the compensator current is added to the measured system voltage and filtered to get low ripple feed back voltage signal.

This way the SVC not only improves the voltage characteristic but also helps in damping oscillations during post fault period. This property is also used for damping of power swings. Damping of angular swings are improved by feeding a properly conditioned signal derived from power flow on the line to the voltage regulator.

2.6.1.2 Reactive Power Control for Industrial loads

SVC can be used to compensate the reactive power to the loads, like furnaces, roller mills. The load power factor is measured from voltage and current signals, compared with a reference signal. Error signal controls the firing angle of TCR or switching of TSC to generate the required reactive power.

2.6.1.3 Load Balancing for unbalanced systems

Unbalanced loads are created in traction loads, electric arc furnaces. The SVC regulator consists of separate reactive power measurement control and firing pulse generation circuits for each phase to enable individual phase control. The firing angle for each phase will be different depending on its load conditions thus effecting unbalanced control

2.6.1.4 Flicker control for electric arc furnaces

Arc furnaces used to melt scrap in steel mills represent highly unbalanced and rapidly fluctuating loads. They produce the following types of disturbances.

Rapid open/short circuit conditions during arc initiation in the furnace Wide and rapid current fluctuations with unbalance between phases

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Fig. 2.5 operating principle of Thyristor-switched

Capacitor.

Fluctuations in the reactive current resulting in voltage variation which causes flicker.

These loads cause flicker in lamps, interference in TV reception and other electronic loads. To control flicker, furnace voltage and current are measured and reactive power requirement calculated. Control of firing angle is done by open loop to get very fast response.

The following subsections 2.5.2 to 2.5.5 apply in the first place to transmission system SVCs. Industrial system SVCs in conjunction with arc furnaces usually differ in some respects: No SVC transformer, fixed capacitor (filter)/Thyristor-controlled reactor main circuit arrangement only, open-loop reactive-power compensation control instead of closed-loop voltage control.

Principles of operation

Two types of Thyristor-controlled elements are used in SVCs:1. TSC — Thyristor-switched capacitor2. TCR — Thyristor- controlled reactor

From a power-frequency point of view they can both be considered as a variable reactance, capacitive or inductive, respectively.

2.6.2 Thyristor-switched capacitor

Fig. 2.5 shows the basic diagram of a TSC. The branch shown consists of two major parts, the capacitor C and the bi-directional Thyristor switch TY. In addition, there is a minor component, the inductor L., the purpose of which is to limit the rate of rise of the current through the Thyristor and to prevent resonance. Problems with the network.

Fig. 2.5 illustrates the

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operating principle. The problem of achieving essentially transient-free switching on of the capacitor is overcome by choosing the switching instant when the voltage across the Thyristor switch is at a minimum, ideally zero. In Fig 2.5 the switching-on instant is selected at the time (t1) when the branch voltage has its maximum value and the same polarity as the capacitor voltage. This ensures that the switching on takes place with practically no transient.

Switching off a capacitor is accomplished by suppression of the firing pulses to the Thyristor so that the Thyristor will block as soon as the current becomes zero (t2). In principle, the capacitor will then remain charged to the positive or negative peak voltage and be prepared for a new switching on.

The TSC is characterized by: Stepwise control Average one half-Cycle (maximum one cycle) delay for executing a

command from the regulator, as seen for a single phase Switching transients are negligible. No generation of harmonics

2.6.3 Thyristor controlled reactor

Fig. 2.6 shows the basic diagram of a TCR. The branch shown includes an inductor L and a bi-directional Thyristor switch TY. The current and there by also the power frequency component of the current are controlled by delaying the closing of the thyristor switch with respect to the natural zero passages.

The TCR is characterized by

Continuous control. Maximum one half-cycle delay for executing a command from the

regulator, as seen for a single phase. Practically no transients.

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Fig. 2.6 Operating principle of Thyristor-controlled reactor.

Fig 2.9 SVC current verses voltage Characteristic.

Fig 2.7 (a) SVC of the FC/ TCR type (b) SVC of the TSC / TCR type

Generation of harmonics

If stepwise control is acceptable, a switched mode of operation with constant delay angle. = 90o, can be used (TSR mode of operation). The advantage of this mode of operation is that no harmonic current is generated. A sufficiently small SVC step size can usually be achieved by a few TSRs, sized and operated in a so-called binary system.2.6.4 Static Var Compensator It is configured as FC + TCR or TSC + TCR.

The TCR and TSC are connected in delta for trapping harmonic currents of zero sequence (3rd, 9th etc.)

Fig 2.8 illustrates the operating performance of the compensator according to fig 2.7 (b)

Most transmission applications require closed-loop bus voltage control by an AVR. For a rapid change of the control order the change from full lagging current to full leading current takes place within a maximum of one cycle of the network voltage.

2.6.5 SVC CharacteristicsAccording to CIGRE an SVC shall be considered as a reactive load on the power system. That means the reactive power, Q, of an SVC is positive when the SVC absorbs reactive power, and negative when the SVC generates reactive power.

Fig 2.8 Operating principle of a SVC of type TSC + TCR for a slow change of control orderHarmonics in SVC

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A TSC does not produce harmonic currents, but a TCR does. All SVCs with continuous reactive power control include one TCR or more thus they produce harmonic currents. The harmonics of zero sequence character (eg. 3 rd, 9th

etc.) are eliminated by some delta connection. The 5th and 7th harmonics are in some cases eliminated by 12 pulse arrangement. As a last resort a filter is included. The allowable amount of harmonic currents into the Power System expressed in terms of voltage distortion at the point of SVC connection are :

The allowed voltage distortion caused by a single harmonic current =1.0%

The allowed total voltage distortion caused by all harmonic currents=1.5%

Dynamic Performance

The small-signal performance of an SVC with closed-loop voltage control may be characterized by its step-response time. It is defined here as the time required to achieve 90% of the called-for change in voltage, for a step change in the reference voltage. The step change must be small enough for the SVC not to reach a limit. The step-response time depends on the power-system equivalent impedance at the SVC point of connection. It is typically less than a few cycles of the power-frequency voltage at the minimum short-circuit MVA level considered when choosing the voltage regulator gain.

If there is a risk that the short-circuit MVA level can be even lower and thereby cause SVC voltage control instability, this can be cured by a gain supervisor automatically reducing the gain in case of instability.

If there are frequent wide variations in the short-circuit MVA level and if it is judged important to get as fast small-signal voltage control as possible for all operating conditions, this can be achieved by a gain optimizer, automatically and repeatedly adjusting the gain up or down versus the short-circuit MVA level.

The above discussion is primarily referred to continuously acting SVCs, but does in principle also apply to discrete acting SVCs (SVCs of TSC, TSR or TSC/TSR type in a binary arrangement).

The large-signal performance is essentially characterized by the actuating time of the SVC triggering and main

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circuits only. For a large voltage deviation, the SVC response time is typically of the order of one power-frequency cycle, considering the power-frequency voltage component only.

Fig. 2.11 Illustrates the dynamic performance of an SVC for a large step change in the reference voltage IT, IC and IB mean total, capacitor and reactor current respectively.

2.7 Series Capacitor

It is a bank of capacitor units inserted in a line for the purpose of canceling a part of the line inductive reactance and so reducing the transfer impedance. The reactive power generated in a series capacitor is proportional to IL

2 and so increases with increasing transmitted power and thus influences the reactive power balance of the system.

The typical uses are: To increase the transmission loading capability as determined by

Transient stability limits To obtain a desired steady state active power division among parallel

circuits in order to reduce overall losses To control transmission voltages and reactive power balance To prevent voltage collapse in heavily loaded systems To damp the power oscillations in association with Thyristor control

The degree of compensation is 20 to 70% of line inductive reactance. The series capacitor (Cse) can be located at the ends of a long Transmission line or in a switching station in the middle of it. Considerations are voltage profiles, efficiency of compensation, losses, fault currents, over voltages, proximity to attended stations etc. 2.7.1. Comparison between shunt and series compensation

S.N Shunt compensation Series compensation

1. The shunt unit is connected in parallel across full line voltage. The current through

The series unit is connected in series in the circuit and therefore conducts full current

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the shunt capacitor is nearly constant as the supply terminal voltage and its reactance are constant.

2. The voltage across the shunt capacitor is substantially constant as it is equal to the system voltage and generally within certain limits of say 0.9 to 1.1 pu.

The voltage across the series capacitor changes instantaneously as it depends on the load current through it, which varies from 0 to ILmax

3. The power developed across the shunt capacitor is

Csh KVAR =

The power developed across the series capacitor is

Cse KVAR = (IL XCse) (IL)= IL2

XCse

4. The shunt capacitor supplies lagging reactive power to the system. Hence directly compensating the lagging KVAR load. It improves the load power factor substantially. Hence its main purpose is to compensate the load Power factor

The series capacitor reduces the line reactance as it introduces leading reactance in series of the line. Thus series capacitor at rated frequency Compensates for the drop, through inductive reactance of the feeder. Hence it is used to increase the line transmission capacity.

5. The size and capacity of shunt capacitor is generally higher for the same voltage regulation

The size and capacity of a series capacitor is relatively lesser for the same voltage regulation

6. Not suitable for transient voltage drops caused by say, frequent motor starting, electric welding etc.

The voltage regulation due to series capacitor is proportional to the IL

2 hence it meets the requirements of transient voltage changes

7. Performance is dependent on terminal voltage. Hence not effective in fluctuating voltage conditions.

The performance does not depend on the system voltage variations. But depends on system load current. Hence gives full output under low voltage and heavily loaded conditions

8. The shunt capacitor need not be on the source side. But

The series capacitor should always be on the source side of

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Csc

closer to the load point the load.

9. The rating is based on KVARCsh = KW(Tan1 - Tan2) where 1 is the power factor angle before correction, 2 is the pf angle after correction

The rating is based on percentage compensation of the line reactance. Generally XCse = 0.3 to 0.4 of Xline Ex: A 220KV, 0.4/km, 100km line, 40%, XL = 0.4 X 100 = 40, Xcse = 0.4 x 40 = 16 = 1/2fCse Cse =

10. The Ferranti effect is aggravated by shunt compensation

The Ferranti effect is reduced by the series capacitor

11. Power transferred through a

line P=

with shunt capacitor, Vr increases P increases

With Cse, Vr increases and X decreases hence P increases much more.

12. The shunt compensation does not require special protection arrangements as the terminal voltage of the capacitor bank falls under fault conditions

The voltage across series capacitor abnormally rises due to flow of fault current through it. Hence it requires special protection schemes.

The fig. 2.12 Shows the bypass arrangement series capacitor (Cse) in case of faults as large voltage develops across the series capacitor. But the transient stability warrants reinsertion of Cse into the system at the earliest. This is achieved by the Zinc Oxide (Zno) varistor. It provides instantaneous capacitor reinsertion after fault clearing. A triggered spark gap is provided to take care of excess energy absorbed by Zno. Damping circuit (D) limits the discharge current.

Zno arrestor is highly non linear. It is connected across the series capacitor in addition to the triggered gap and by pass switch. The varistor clamps the capacitor voltage

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Fig.2.12 Series Capacitor with Zinc-oxide varistor by-pass system.

below its short time over voltage rating during the fault. The re-insertion is almost instantaneous. Thus both capacitor protection and system stability aspects are taken care of.

Series Capacitor in radial distribution systems

A Series Capacitor is becoming popular in radial distribution systems because

Cse is a cost effective device of reducing voltage drops caused by steady loads on a 11 or 33 KV radial line with load Power factor of say 0.7 to 0.9

To take care of starting of a large motor and consequential voltage fluctuations

To decrease line losses due to the lower current To increase load ability of the feeder Simple and reliable bypass systems are available Advanced resonance detectors are available.

2.7.2. Sub Synchronous Resonance (SSR)

The SSR is generated in radially connected turbo generators with a series Capacitor (Cse ) in the line.

Two basic phenomenon:

The generator appears as an induction generator for sub synchronous armature currents

If the difference between the synchronous frequency and the sub synchronous natural frequency of the electrical system lies close to a natural frequency of the shaft mechanical system, the bilateral coupling between the two systems becomes strong. If the net damping of the two systems is negative, electrical and torsional oscillations will build up, either spontaneously or after a disturbance, e.g. a line fault.

In case of hydro-turbine generator units, the risk of torsional oscillation problem is practically negligible.

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Fig 2.13 System of the type most exposed to the sub-synchronous resonance

Preventive Measures:

SSR detection and relaying leading to tripping of unit Compensating sub synchronous currents with Dynamic stability Pole-face amortizer winding against induction generator effect Thyrister Controlled Series Capacitor.

The use of a Thyristor-controlled module, appropriately controlled, of the series capacitor bank seems to be a promising counter measure.

Another subject often discussed is how to ensure correct operation of line relay protections in conjunction with series capacitors. According to service experience the risk of maloperation of line distance protections seems small. Ultra-high-speed line protections based on traveling wave detection can eliminate the possible problems of line protection in conjunction with series capacitors.

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CHAPTER - 3

CAPACITORS3.0 The Capacitance

Absolute permitivity () =(Electric Flux density/ Electric Field Intensity) = or ; = Absolute permitivity

Permitivity of free space = o

Relative permitivity = r

Electric field Intensity = (V/d) = ( Voltage across the dielectric / Thickness of the dielectric)Electric Flux density = (Q/A) =( Charge in coulombs/ Area of the dielectric)Q = Charge accumulated in coulombs = (Current in Amperes X Time in seconds)C = Capacitance = (Q / V) farads

A Farad is the capacity of a capacitor between the plates of which there appears a difference of potential of one Volt when it is charged by a quantity of electricity equal to one coulomb.

C = (or A / d) = A/d farads A= area of the dielectric field in sq. mts.d = distance between plates in mts. = Absolute permitivity

Capacitors in series =

Capacitors in parallel = C= C1 +C2+C3 + …

3.1 Capacitor in AC circuits

3.2 Circuit containing Resistance & capacitance

VR = IRVC = IXC

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Ic

V

Ic

Xc900

Leading Ic

V

Fig 3.1. Voltage and current relationships in a.c. capacitive circuits

Fig 3.2. circuit containing resistance and capacitance a) Circuit b) Phasor diagram

KVar = (IC) (V) = C V.V = 2fC V2

KVA = = KW = VI Cos x10-3

KVar = VI sin x10-3

Pf =

KVar =

3.3 Dielectric Loss

The dielectric loss is present due to dielectric in a capacitor instead of perfect vacuum. The phase angle of current falls short of 90o by . Hence Power factor of capacitor = Cos (90-) = Sin tan .

Tan = r.c = (90-)

Power absorbed by capacitor = VI cos = VI tan for low values of

Tan = 0.0006 Loss of 0.6 w/KVar

Fig 3.3 Power absorbed by the capacitor equals VI cos VI tan

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Tan =rC = 90o -

3.4 Charge and discharge of a capacitorCF

Fig 3.4. Charge / Discharge of a capacitor through a pure resistor

= Single phase capacitor current

= Three phase capacitor Current

V = line to line voltage

CR = Time constant of the unit

Energy stored in a capacitor = J =½ CV2 joules

Where C in F and V in kV

3.5 Capacitor for Power factor correction

KVar1 = KW tan1;KVar2 = KW tan2 ;

(KVar1-KVar2) = KW (tan1-tan2)

Fig 3.5.a Capacitor connected in parallel with load where V= supply voltage, IL= current taken by load, IC= Current taken by capacitor, I= current drawn from supply.

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Fig 3.6. Phasor diagram showing the effect of adding capacitance where IL=current flowing when no capacitor is connected. IC =current due to capacitor only; I= current taken from supply with capacitor connected

3.6 Shunt Capacitors applied to Power Supply System:

Fig 3.7. Simplified distribution system a) System b) simplified circuit c) Phasor diagram lagging power factor d) phase diagram unity power factor with shunt capacitor bank.

The reactive power is generated at the receiving end. Hence the HV transmission and distribution system is relieved of this reactive power flow in the system.

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Fig 3.5.b. Determination of shunt capacitor requirement

3.7 Series capacitors in Power Systems

Fig 3.8. Simplified distribution system with series connected capacitors a) System b) Simplified circuit c) Phasor diagram without capacitor d) Phasor diagram with capacitor

3.8 Protection of a Capacitor Bank

3.8.1 Design considerations for protection of HT Capacitors

The protection of HT Capacitors should consider abnormal voltage variations, distorted current and voltage wave forms due to non linear loads, resonance, parallel switching, restrike of switching device, identification and elimination of failed capacitors etc.

a) BIS, IEC specify capacitors to be suitable to take care 10% over voltage for 12 hours a day

b) The harmonics can be taken care of by a series reactor in series with capacitor. The series reactor shall be say 6%. This combination offers lower impedance at 5th harmonic. Net impedance at 5th harmonic is inductive and hence no resonance takes place. Explained in section 3.9.

c) The capacitor offers very low impedance at the time of switching. These in rush currents will be larger when subsequent banks are switched on. In order to limit this in rush current a 0.2 to 1% reactor is used in series.

d) Restrike: When capacitor is switched off, one side of the switch is system voltage and the other side the charge. Hence double system voltage may appear across the contacts. If a restrike occurs the capacitor gets damaged. Hence the switch should be restrike free.

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e) The failed units of the capacitor bank shall have to be eliminated in order to avoid over voltage on the remaining units.

3.8.2. A one line diagram of a protection scheme of a capacitor bank is as shown in fig (3.9)

As per IEC – 70, Capacitor banks must

i) Withstand 10% over voltageii) Withstand 30% over load due to over voltage and/or harmonicsiii) Peak value of in rush current must not exceed 100 times the rated

current of the capacitor.iv) Capacitor must not be re-energized until residual voltage falls below

10% rated voltage. v) CB must be restrike free

3.8.3 Over load protection (50)

The capacitor bank tuning factor = 8.9

Rated load current = I =

(1.1) Ir = 1.1 x 289 = 318 AmpsHence the CT ratio at 33kV is 320/5 AmpsThe relay should trip at 30% over load 289 x 1.3/320 x 5 = 5.87 Amps = 117%The above overload current is not sufficient for an 1DMT relay. Hence an O.C. relay with adjustable definite time delay is provided.Recommended settings

a) Current = 1.3 x Irb) Timer = 0.3 sec.

3.8.4 Over voltage protection (59)

Recommended settingsa) Voltage = 1.1 V ratedb) timer = 7 to 10 sec.

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3.8.5 Over current/Short circuit Protection

An IDMT relay is provided to take care of short circuits in the capacitor bank

3.8.6 Under voltage relay

This is provided with bus PT and set at 60% of rated voltage. A time delay of 2 sec. is provided. This takes care of auto re-close CB on the in coming feeder.

3.8.7. Capacitor Unbalance protection

This is to disconnect the bank when a fault has occurred inside the bank in order to prevent a healthy unit from being exposed to more than 1.1 rated voltage.

a) Voltage unbalance scheme (60)

The unbalance can be detected by sensing the residual voltage coming across the open delta of PT secondary as shown in fig.3.10

Disadvantages: i) The scheme can not distinguish between unbalance due to capacitor internal fault and unbalance due to external fault or unbalanced load. ii) Sensitivity of voltage unbalance scheme is always less than sensitivity of current unbalance scheme.

Fig. 3.10 Unbalance protection of 3 phase capacitor bank with RVT

b) Current unbalance scheme (61)

3 phase capacitor banks are connected in double star. The CT between two neutrals detects the unbalance current and trips.

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Delay in re-closing operation

Once tripped the capacitor should be allowed to discharge to an appreciable limit of 10% of Vrated within 5 mts. To facilitate this, a time delay interlock is provided to prevent the reclosure of the breaker within 5 minutes.

The CB should be re-strike free

It should be capable to break the capacitor current at maximum permissible bus voltage

Inrush current

Since generally the capacitor banks are used in series with reactors as filter banks. Peak value of the in rush current is limited by the reactor within specified limit. If it is used alone a small reactor is considered in series with the capacitor to limit the peak in rush current.

3.9 Series reactor for harmonic suppression

When there are harmonic generators like rectifiers or arc furnaces present in the system, there is a possibility of capacitors drawing much more current than permissible limit.

A series reactor connected to a capacitor forms a circuit with tuning frequency, fo:

At tuning frequency X = XL – XC 0

fo XL = 2foL; XC = 1/(2foC)

X = XL – XC = 0 2foL = 1/2foC

fo2 =

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The tuning frequency (fo) is the frequency at which the LC circuit offers least impedance. In order to suppress harmonics, the series reactor is so chosen that tuning frequency falls below the harmonics of the lowest order that may be present in the system.

For example if 5th harmonic is the lower order present in the system then the tuning frequency should be say 240 Hz so that the LC circuit will offer higher impedance to the 7th, 11th ……. harmonics.

The tuning number = n =

Where fo = tuning frequency f1 = fundamental frequency i.e. 50 Hz

XC = capacitive reactance XL = series reactor reactance

The frequency response characteristic of the series LC circuit with 6% series reactor:

n = .09

f XL XC X50 0.06 XC XC (1-0.06)XC = 0.94XC

100 0.12 XC XC/2 (1/2 – 0.12)XC = 0.76XC

150 0.18 XC XC/3 (1/3 – 0.18)XC = 0.46XC

200 0.24 XC XC/4 (1/4 – 0.24)XC = 0.04XC

250 0.3XC XC/5 (1/5 – 0.3)XC = -0.5XC

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Fig 3.12 the series reactor for harmonic suppression

n = fo/f1 = 205/50 4.09

The LC circuit does not offer high impedance to the harmonic currents close to the tuning number. Hence the series reactor and the capacitor should be designed to withstand these currents also.

S.No. f0 / f1 XL = XC / (f0/f1)2 XL as %ge of XC

1 1 XL = XC (1.0) 1002 3 XL = XC (0.11) 113 5 XL = XC (0.04) 44 7 XL = XC (0.02) 25 9 XL = XC (0.012) 1.26 11 XL = XC (0.0083) 0.83

3.10 Causes Of Capacitor Bank Failures And Remedial Measures

It has been found invariably, whenever capacitor bank failure takes place leading to failure of capacitor units, the tendency of the user is to get the failed units replaced as soon as possible or to use the bank with remaining lesser number of units without going into details of failure and causes thereof, Instead of rushing to re-install the capacitor bank one must analyse the failure and arrive at the root cause of failure so that necessary remedial measures can be taken to avoid recurring of such failures in future.

Capacitor Failures Can be segregated into following categories Failures due to internal unit faults. Failures due to installation problems. Failures due to system problems.

3.11 Failures Due To Internal Unit Faults

Faults are generally due to defective material used or due to manufacturing defects.

Defective Materials include mainly POLYPROPYLENE FILM having voids or spaces where thickness of the film is lower than average thickness stipulated

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Fig 3.13 the frequency response characteristic of a series LC circuit

by film manufacturer. This gives rise to higher voltage stresses thereby leading to puncture in the capacitor element and subsequent failure of the unit. In case of units with internal element fuse protection, may be such defective elements are Isolated and balance units continue to be in service. However, In case of units having external fuse protection, such faulty elements may lead to arcing, rise in Internal pressure, bulging (and may be unit bursting) before the external fuse can identify the fault to trip the unit.

Impregnate Oil is also important from the point of view of providing interlayer insulation and cooling. Any impurities in the oil are likely to give flashovers at lead wires/interconnections and containers and thereby failure of the unit.

CRCA Sheets are used for containers because of their higher tensile strength, which leads to distortion in the shape of the container in the event of abnormal internal pressure. If the sheet material is not CRCA, rusting of container, bursting due to internal pressure etc. are seen as reasons for unit failure.

Defective Workmanship include defects during the manufacturing process such as Element Winding, Impregnation. Container Welding. Sealing of bushings.

Element Winding is necessarily required to be done in dust—free atmosphere. Generally pressurised rooms are used for this purpose to avoid dust entering into the winding room. Any dust particles in the element give arcing in the elements and thereby failure of the unit

Impregnation process is most vital. Longer the impregnation cycle, better will he the quality of capacitor. During impregnation cycle full vacuum should be maintained in order to ensure complete drying of elements and then proper oil impregnation shall take place. If during the process vacuum is lost or oil impregnation is not done properly, premature failure of elements is likely.

If Container Welding & Sealing Of Bushings is not done properly, oil leakages start and when oil leaks out, air contamination leads to subsequent failure of tank. Generally raw material and process problems are identified during inspection stage and testing. Such portion of faulty unit or entire unit can be rejected during the process of manufacture. However, sometimes these units pass the in-house testing but do not sustain field conditions and lead to premature failure in operation. However, one must note, such failures are only isolated cases and are restricted to one unit failure at a time and generally within one month of commissioning of the bank.

3.12 Failures Due To Installation Problems

Capacitor Bank installations should he done properly as per SUPPLIERS DRAWINGS and INSTRUCTION MANUALS. Unit configuration and number of series groups should be strictly followed as per drawings. Mass failures are likely to occur if the series groups and number of units per series group are not installed properly.

If Handling of capacitors at the time of installation is done by dragging the

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units on the floor with the help of bushings, oil leakages from bottom welding portion or bushings solder may start leading to failure of the units. Sometimes units damaged in transit with OIL LEAKED out completely are used in the installation, which will cause subsequent failure. Interconnections between unit bushings and busbars should be done with L clamps using 2 spanner method to avoid breakage of solder joint of bushing. Sufficient space should be available between units for better COOLING of the units particularly for indoor banks

For open type banks live parts should be minimum 8 feet above ground level. Either elevated structures or wire mesh enclosures should be used. This is important with more than one series group is involved when the containers become live. Electrical Safety clearances should be maintained as per IE rules.

Earthing of installation is necessary but remember not to earth live structure or floating neutral point of capacitor bank.

At places where BIRD FAULTS are likely, insulate live parts with insulating tape, sleeving. Whenever live structures are involved with capacitor banks of more than one series groups, bird faults may lead to mass failure. Wire mesh may be used to avoid bird fault under such conditions.

Balancing Of Capacitor Units Per Group should be done before commissioning with the help of capacitance meter or by applying low voltage single phase AC supply. Failure of any unit in the group will also give unbalance leading to overvoltage on balance units of the same group which may be dangerous enough to cause failure of the units.

3.13 Failures Due To System Problems

As mentioned earlier, generally the capacitor bank should stabilize within one month of operation. If however, it is found that the units fail one by one or mass failure occurs, system study like harmonics, load variations, power factor measurements at various loading conditions, voltages and voltage/current surges due to loads/capacitor banks switching, will have to be carried out, to ascertain cause of failure.

In case HARMONICS are present in the system, capacitor system should be designed to take care of harmonics present since capacitor system offers lowest impedance path to harmonics. By adding appropriate size of reactor in the capacitor system, we can increase the impedance and curtail harmonics entering into capacitor thus reducing loading on capacitors. However, if harmonic contents are large• enough to give loading on capacitors more than designed value, we have to use capacitors in the form of tuned filter circuit designed to carry the required harmonics. If capacitors are not designed to take care of these aspects they are likely to fail due to harmonics.

3.14 Selection Of Capacitors

Rating of capacitors, basic technology and operating conditions are vital

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in selecting appropriate capacitors.

Rating should be selected to ensure that the Power Factor does not go leading under all conditions of loading. Leading power factor particularly under light load conditions is likely to rise system voltages as also resonance phenomena between incoming transformer and capacitor bank may occur to build up voltages and thereby failure of capacitors. Rated voltage of the capacitors should be selected based on the highest system voltage keeping some safety margin and considering effect of harmonics.

As per the latest trend and due to lowest loss figures 100% PP film capacitors are used in HT applications. However, in case of LT applications, selection of TECHNOLOGY will be vital. Metallised Polypropylene (MPP) capacitors are available at moderate rates and loss figures. These are best suited for LT system where harmonics are not present and application does not involve frequent switching. For system with harmonics or application involving frequent switching these capacitors’ output goes on reducing due to self healing property. Under such conditions either Mixed Dielectric (MD) capacitors of Paper plus polypropylene film dielectric or latest version with very low losses, 100% polypropylene film (All PP) capacitors should be used. Generally MPP capacitors are provided with inductor coil to reduce effect of switching surge currents thereby extending life against self healing under normal operating conditions.

When capacitors are connected directly across MOTOR in individual feeder compensation, due care should be taken to check that under all loading conditions of the motor, capacitors don’t overcompensate.

Number of SWITCHING OPERATIONS should not exceed 3-4 per day. If the number of switching operations are likely to be more, the life of capacitor bank, reduces as each time the capacitors have to carry high inrush currents. While SWITCHING ON the capacitor bank, it shall be ensured that system voltage is less than the rated voltage of the capacitor. Again, life expectancy goes down with switching at higher voltages. In case capacitors are used near to transformer with on-load cap changer it would be safer to have OLTC on the primary side of the transformer and capacitor on secondary side as each OLTC operation generates surges, dangerous to capacitors.

3.15 Selection Of Associated Equipment

Associated equipment selection is as import as capacitor selection for better performance of capacitor bank system.

In order to avoid overvoltages generated at the time of opening of BREAKER, the same should be restrike free. Necessary test certificates for breaker suitability for capacitor duty should be obtained. Sometimes it may be necessary to use surge absorbers With breakers used for capacitor duty. It has also been noticed that switching of fully loaded inductive feeder by vacuum circuit breaker (VCB) gives rise to voltage surges. If capacitors are connected to the same bus, these surges are likely to damage capacitors. Here also it is advisable to use surge absorbers.

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Series Reactors are used with capacitors to (i) Limit switching surge currents particularly during parallel switching (ii) Limit harmonic currents (iii) For tuned filter circuit. Depending upon the application involved, the parameters of the series reactors are decided. Capacitor rated voltage should be increased to the extent of drop in the series reactors. The series reactor current rating should be chosen to cover 130% continuous current rating of associated capacitor bank. The heat run test should be carried out at 130% current rating for series reactors, to ensure this compliance and to avoid failures due to higher currents. Series Reactors are available in magnetically & non-magnetically shielded versions. Generally in systems with harmonics, non-magnetically shielded reactors are used to avoid failures due to harmonic fluxes flowing through shielding.

It is a common practice to reduce one unit from each phase if one of the unit fails and use reduced capacity bank with same reactor. This should be avoided as reduced capacity bank has higher Xc value thereby percentage of series reactor compared to Xc reduces. Reduced value of series reactor may not be effective to curtail harmonics. A small value reactor at neutral end of the capacitor bank is always useful to improve capacitor bank performance as it reduces considerably switching surges particularly during parallel switching thereby reducing the duty on all the associated equipment including breakers.

Lightning Arrestors to some extent restrict switching surge voltages. Whenever high surges are expected, Lightning arrestors of higher discharge handling capacity should be used. Also, Lightning Arrestor leakage currents should be periodically checked to confirm the same are not more than 150% of the value recorded at the time of installation.

If RVT windings are not mechanically strong enough to sustain voltage surges due to capacitor bank switching, RVT is likely to fail.

3.16 Nature of Failures

Whenever capacitor unit failure occurs, this necessarily gives rise to NDR (Neutral Displacement Relay) operation. In case of capacitor units protected with external expulsion fuse (or HRC FUSE), the fuse may operate to protect the unit, which will also give rise to NDR operation. NDR will also operate if RVT has internal fault. Therefore whenever capacitor bank trips on NDR operation, one has to find out if fuse has blown but unit is intact. This can be due to (i) Transient overcurrent or (ii) Overheating of fuse due to loose end caps.

Capacitor bank may trip due to other protections offered like overcurrent, over voltage, under voltage which are common protections. Here again bank may trip without any failure of units, one has to identify by checking the capacitance value of the unit and certify unit failure. From the protective relay operation one can identify the type of fault which might have caused failure of unit.

3.17 Summary

Any unit failure should be analysed based on information given above and

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such failures can be attributed to (a) manufacturing defects or (b) wrong applications. Failures due to harmonics, switching over voltages or inadequate protection shall not be attributed to manufacturers.

In order to find out cause of failure, full data of capacitor bank at the time of commissioning and at the time of failure may be noted.

IEEE have standardised ratings of capacitor units to take care of normal site conditions and safety margins in the form of adjusted rated voltages. After the capacitor bank system is fully stabilized, spare units should be kept to replace any of the failed units under circumstances beyond control, but only after ascertaining the cause of failure.

Problems1) A load of 85 KVA is working at pf of 0.6. The demand charges per KW of Maximum Demand per month = Rs.180/-. If the power factor in a month is less than 0.9 the MD charges for that month are increased by 1% for each 0.01 by which the pf is below 0.9. Find payback period if cost/KVar = Rs.100/- and the power factor is to be raised up to 0.95.

Soln: a) Total demand charges prior to correction:85 x 0.6 = 51.0 KW x 180 = 9180pf penalty = 30% of above = 2754

11934 per monthb) The cost of capacitor:Correction KVAR = Kw[Tan(cos-1pf1) – Tan(cos-1pf2)]KVAR=51 [Tan(cos-1 0.6) – Tan(cos-1 0.95)] = 51 x 1.005Hence 51 KVar is required to correct the power factor to 0.95 Cost per KVar = Rs.100/-51 KVar 100 x 51 = Rs. 5100/-c) Improved Load conditions:New total charges per month = 51 x 180 = 9180Difference/month = 11934 – 9180 = 2754 Rs.Hence the investment can be recovered in about 2.0 months

2) A HT consumer has 50 KW MD at 0.8 pf and average consumption of 5000 units per month. The distribution company penalizes @ 3 ps/kwh for each 1% decrease in power factor below 0.9. If the cost of capacitor bank along with associated switchgear is Rs.200/kVar. In how many months the investment on capacitor can be recovered if the power factor is raised to 0.98.

Solution: Percentage of pf inviting penalty = (0.9 – 0.8)/1 x 100 = 10%

Energy charges penalty = 10 x 3 x = 1500/- Rs.

penalty is Rs.1500/ month on average consumption of 5000 unitsCorrection KVar = 50 kW [(tan(cos-10.8) – tan (cos-1 0.98)]= 50 (0.541) = 27.050 KVarCost of 27 KVar = 27 x 200 = 5400/Rs.

It can be recovered in = 3.6 months

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3) Find the average reactive power flow through a 220 kV, 120 km line operating at Sending end voltage (Vs) of 1.0 pu and Receiving end voltage (Vr) of 0.9 pu and the = 30o.

Soln : cos = cos 30 = 0.866Qs =

Qr =

220 kV, 120 km x = 48

Base impedance =

Line impedance in pu =

Qs = = 220

MVAR

Qr =

Qaverage = 95 MVAR

4) A 100 MVAR capacitor is connected at a bus with 5000 MVA short circuit capacity what is the expected voltage change.

Let 1 pu = 100MVA;

V = Q = 100 MVAR,

Q in pu = 100/100 = 1 puSsc = 5000 MVASsc in pu = 5000/100 = 50 pu

V (pu) =

5) A bus experiences 3% voltage fluctuation. The Ssc is 5000 MVA. We wish to size the Static Var Compensator to smoothen the voltage fluctuation, what shall be the size of SVC?Soln: V = 0.03 pu; Ssc = 5000/100 = 50 puQ = (V )(Ssc) = (0.03)(50) = 1.50 pu = 150 MVARHence the size of SVC required is 150 MVAR

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CHAPTER – 4

REACTIVE POWER COMPENSATION IN TRANSMISSION SYSTEMS

4.0 Introduction

Well-planned and coordinated reactive power compensation is an indispensable element in the design and operation of a reliable power system. The effectiveness of reactive power control on power system may be of utmost importance not only under normal conditions, but also during major system disturbances.

It is often advantageous to operate the transmission parts of a power system.

• with a fairly flat voltage profile, in order to avoid unnecessary reactive power flows.

• With a relatively small supply of reactive power into the distribution systems.

• With reactive power capacity reserves available for use in connection with major disturbances and under generator, transformer or line outage conditions.

4.1 Transmissions with long overhead linesThis section discusses transmission and sub transmission systems, where shunt compensation, in one form or another, is necessary or useful for reactive power and voltage control and possibly also for synchronous stability improvement. Problems of voltage control and synchronous stability are most pronounced in systems with high “transfer impedances’. With low “transfer impedances’ the question is more that of only balancing the reactive loads by reactive power production. The heading “transmissions with long overhead lines” has been chosen because long lines means high “transfer impedances”.

The discussion is grouped into the subjects of steady-state var and voltage control, prevention of voltage collapse, reduction of temporary over voltages, other voltage quality improvements and synchronous stability improvement.

4.2 Steady-state var and voltage control

The aim of the steady-state voltage control is to keep the transmission bus voltages within fairly narrow limits, while the load transferred varies. The desirable voltage range under normal operating conditions is usually defined by the nominal voltage +/- 5 to 10 per cent, usually with higher voltage during heavy load conditions than during light load conditions. Usually a larger voltage deviation is allowed under circuit outage operating conditions than under normal operating conditions. The set voltages on the different buses, for which the voltage can be controlled directly, should be such that the reactive power flows are minimized.

Since the reactive power transmitted may greatly vary hour by hour, the variation of the reactive power balance of a line may be considerable, as illustrated by Figure 4.1. In the case of a long EHV transmission, where variations in the hundreds of Mvar per line are involved, this greatly influences the reactive power balance of the entire transmission systems.

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Reactive power p.u.of line generation

Fig 4.1 Reactive power balance of a transmission line

If there is an outage, either, forced or scheduled, of one line out of a number of heavily loaded parallel lines, a great increase in reactive power demand may be created. The line generation of reactive power is reduced and the line consumption of reactive power is greatly increased.

The basic voltage control of a power system is provided by the large

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generators, each having its own excitation system with an automatic voltage regulator. The generators are used for voltage control at the terminals to which they are connected; reactive power is generated or absorbed, depending on the load conditions. Transfer of reactive power from the generators to electrically remote points of the power system or vice versa is usually avoided under normal operating conditions.

Generators are, however, very important as reserve sources of reactive power, needed also rather far from the generators, after contingencies such as the sudden loss of a main generator or a major line section. The short-time reactive overload capability of generators may also be valuable on such occasions. Further, pure synchronous compensator operation of generators can be valuable under unusual system operating conditions.

4.3 Passive shunt compensation

The coarse reactive-power balance and voltage control, in particular of the parts of transmission systems which are not adjacent to generators, is brought about through passive shunt compensation by means of breaker-switched and permanently connected shunt reactors and breaker-switched shunt capacitors. Also series compensation comes into picture.

Under light load conditions of a long EHV transmission, the excessive line-generated reactive power must be drawn out at the buses in order to keep down the voltages. Shunt reactors are frequently used on EHV lines of lengths exceeding about 200 km they are also needed on shorter lines, if these are supplied from weak systems. With this method, shunt reactive-power absorption; the adjoining parts of the power system are released from reactive power flows. There is a trend towards the highest degrees of compensation for the highest system voltages and the longest lines. Degrees of compensation of 60 to 70 percent of the line charging are not unusual for the highest EHV levels.

Shunt reactors in EHV systems are usually connected either to tertiary windings of transformer, for instance at 12 KV, or direct at line potential; in a few cases to generator buses. Nowadays. Most new EHV system reactor installations are at line potential. Shunt reactors are also used in EHV transmissions with long lines or cables but less frequently than in EHV transmissions.

With increasing load transferred by a long EHV transmission, the excessive line-generated reactive power decreases and the reactive power absorption has to be reduced. At least some of the shunt reactors are usually disconnected so as not to cause an unnecessary voltage drop. Very long EHV transmissions without series compensation are usually not operated above 1.0 p. u. of SIL per line.

The reactive power injections, which may be needed under heavy load conditions are supplied from generators, shunt capacitors and dynamic shunt compensation means; the latter is discussed under the next subheading.

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Shunt capacitors are not frequently used in EHV transmission systems. They are usually to be found in systems with lower nominal voltages; in HV transmission systems and sub transmission systems, and in distribution systems, in particular.

Series compensation is employed on long EHV lines; the main purpose is usually to improve the transient stability or to obtain a desired load division among parallel circuits. At the same time series compensation has a greatly beneficial effect on the coarse reactive-power balance and voltage control. Because of a smaller variation the net reactive power balance at the lines versus the variation in the load transferred.

4.4 Dynamic shunt compensation

In cases where the voltage has to be better controlled than is possible with passive shunt compensation, i.e. by breaker-switched shunt reactors and shunt capacitors, active or dynamic shunt compensation may be needed to provide high-performance voltage control. The latter term is referred here to the control quantities of Continuity, rapidity, accuracy and frequency of control actions.The synchronous compensator and the Thyristor-controlled Static Var Compensator (SVC) make to the devices for dynamic shunt compensation. Synchronous compensators were installed and continue to be in service in AC transmission systems at the receiving end of long radial transmission and at main buses within meshed networks with long lines, particularly in regions where there is only little local generation. For new installations of dynamic shunt compensation devices the SVC has virtually replaced the synchronous compensator due to benefits in costs, maintenance and performance characteristics. A great many SVCs are in use for high-performance voltage control, worldwide.

4.5 Prevention of voltage collapse

By voltage collapse is meant a severe voltage depression without inherent recovery, The voltages do not necessarily decrease to zero but to low values, making the continued proper operation of a small or large part of a power system impossible. The phenomenon has appeared occasionally and is sometimes difficult to predict. Generally, less attention is paid to voltage collapse than to synchronous instability, but it can, nevertheless, be of great importance. Particularly when leading to power system blackout. Voltage collapse is a form of voltage instability. The key cause at its appearance is inadequate reactive power supplies. One or more of the following factors are usually involved:

High transfer impedances High load content of induction motors Insufficient reactive power generation reserves Temporary operating conditions Generator, transformer or line outage High system loading Maintenance work Erroneous human action Equipment malfunction

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Automatic control of transformer on-load tap changers Actions of generator current limiters

The load-voltage characteristics, i.e. the real and the reactive power of the actual composite loads versus the voltage have a tremendous influence on the phenomenon. The process leading to voltage collapse takes place within time ranges from a fraction of a second to half an hour very much depending on how it is triggered but also on the network configuration and the operating conditions. Three examples referring to different time ranges are given below:

A forced outage, e.g., of a line, may cause a fast voltage collapse for a limited load area of a power system.

A large-scale voltage collapse preceding a system blackout, may take a minute or more to develop after the initial disturbance. During this time there may be cascade line disconnections, actions by field and stator current limiters of generator excitation systems, actions by transformer on-load tap changers. etc.

Voltage collapse in a distribution system fed via a long sub transmission line and due to receiving-end transformer tap changing as the load increases, may take half an hour to develop.

Voltage collapse can usually be prevented by installing sufficient amounts of controllable reactive-power supply sources at proper buses, e.g. in cases of conceivable slow voltage collapse breaker-switched shunt capacitors and in cases of conceivable rapid voltage collapse, SVCs. Network reinforcement by series compensation, if applicable, can also prevent voltage collapse.

4.6 Reduction of temporary over voltage

Fundamental-frequency over voltages, the kind of temporary over voltages primarily considered in this subsection, originates from switching operations and faults. A rough rule of thumb is that temporary over voltages should usually not exceed 1.5 p.u. And their duration not 1 second.

Figure 4.2 illustrates a marked case of conceivable high fundamental-frequency over voltages, if not counteracted; a very long EHV line between two systems and with a low short-circuit capacity Ssc of the sending system. If receiving end load dropping occurs at high load, leaving the line energized

from the sending end only for some time, a high fundamental-frequency over voltage will appear at both line ends and at the receiving end in particular. The

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Fig 4.2 Reactive power absorption by shunt reactors at line potential

voltage rise is due to the change from active/inductive load to capacitive load for the sending system and due to the so-called Ferranti effect of the line. If the load dropping brings about a separation of the systems, problems of frequency rise and of generator self-excitation may appear.

Perhaps the very worst case, sometimes considered, is a single line-to-ground fault at the receiving end followed by load dropping. Fundamental-frequency overvoltages, as discussed here, are usually most critical during the initial period of transmission development, when the short circuit capacities and the number of interconnections are low.

Energization of a long EHV line is similar to load dropping, but with lower overvoltages; a long line is usually energized from the “best end”, i.e. the end with highest short-circuit capacity.

The remedy for fundamental-frequency overvoltages, if they are a problem, is reactive power absorption. The shunt reactors installed for the steady-state voltage control and the line energization are usually sufficient. There is, however, a problem in that some or all of the reactors may be disconnected during heavy load conditions. One method to overcome this is to use a combination of a minimum installation of permanently line connected shunt reactors and switchable bus-connected shunt reactors. A third alternative is SVCs with reactive power absorbing capability.

4.7 Other voltage quality improvements

Two special voltage quality subjects in conjunction with sub transmissions are discussed.

Reduction of voltage asymmetries, caused by time-varying single-phase traction loads.

Unbalanced loads of the type mentioned give rise to asymmetrical currents and voltages, the negative-sequence components of which can have undesirable effects, particularly on rotating machines.

Let us consider first an unbalanced load consuming active power only. The possibility to balance a steady-state load of this type by means of reactive devices (capacitors and inductors) has been wellknown for many years. To balance a rapidly varying load of this type has been practically impossible. Now, the SVC with individual phase control allows this possibility. The unbalance in reactive power consumption can, of course, also be balanced by proper individual phase control. Several SVCs are in use for this purpose.

4.8. Reduction of voltage fluctuations caused by dragline loads

Dragline loads of remote mining plants create voltage fluctuations, which often represent a problem both for the plant itself and for other consumers in the vicinity of the plant. The power of a large dragline excavator is characterized by: Relatively rapid variations

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Shock loading The digging cycle, typically 1 minute Driving motor oscillations, if synchronous motor, typically 2 HzThe SVC is an excellent means to reduce these voltage fluctuations.

4.9 Synchronous stability improvement

The term ‘synchronous stability’ denotes the ability of a power system to retain the synchronous machines in synchronism without sustained rotor oscillations, both after large disturbances (transient stability) and during steady state conditions (steady-state stability). By the term stability limit is meant the maximum power, which can be continuously transmitted stably. The critical transient stability limit is usually lower than the steady-state stability limit. From the economic point of view, transient stability, and in particular the first-swing transient stability is the most important type of stability, because it may influence the choice of high power elements of power systems: transmission voltage levels, number of parallel lines, line sectionalization, etc.

4.9.1 First-swing transient stability

When transient instability occurs for a severe disturbance, it usually, but not necessarily, appears during the first swing of rotor oscillation and within one second. Loss of synchronism occurs between one machine and the rest of the system or between groups of machines. If the system is stable through the first swing, the behaviour during the subsequent swings is usually a matter of damping only.

Let us consider a ‘two-machine system’, similar to that of with a link of parallel lines, the resulting reactance of which, X, is an essential part of the impedance between the generators. Under both steady-state and transient conditions the voltage-angle difference of the link is approximately determined by:

P =

Now, without going into a discussion of transient stability as such, the following statement is made: there is a close relationship between the first-swing transient stability and this voltage angle difference .

In a critical case of first-swing stability (not all cases are critical) it is important that the contribution from the link to the total difference of the generator internal voltage angles does not become too great.

As can be seen from the equation, both rapidly controlled shunt compensation and fixed series compensation can be used to reduce , thereby raising the first-swing stability limit. Shunt reactive power injections at the nodes of the

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link during the critical power swing after a disturbance will keep up the voltages, thereby reducing . Series compensation, reducing X, means both a lower value of before the disturbance and a smaller increase in during the critical power swing.

If a severe stability criterion, such as a three-phase short circuit or a double line-to-ground fault, is applied, the first swing transient stability may be critical and of main concern. Full advantage should, of course, be taken of low-cost countermeasures such as rapid fault clearing, rapid reclosing, etc., but in critical cases this may not be sufficient.

Shunt reactive-power injections, as discussed above, through dynamic shunt compensation by SVCs (voltage support) can be used. However, studies performed have demonstrated that even with optimum locations of the SVCs with regard to stability improvements, the necessary large normal size of the SVCs will usually make this method less attractive than series compensation. (The optimum locations of the SVCs are not necessarily at the ends of the link as discussed above).

Series compensation is in many cases the most cost effective method of raising first-swing transient stability limits.

4.9.2 Damping of Power Oscillations

The damping of synchronous machine eletromechanical rotor oscillations is of interest to both steady-state stability (small disturbances) and subsequent swings of transient stability (large disturbances).

The connected synchronous machines of a power system can be considered as a system of coupled oscillatory objects, as long as the machines are in synchronous operation. The system can be characterized by a number of latent or developed modes of electromechanical oscillations, expressed in terms of incremental rotor angle displacements and speeds. In principle, the number of modes related to the machine inertias are equal to the number of machines minus one. Usually, however, modes coincide with the result that a fewer number of modes show up in the oscillations.

The oscillation frequency and the damping of each mode depend on several factors. The oscillation frequencies are usually to be found within the range 0.2 to 2 Hz, in a few cases down to 0.1 Hz or up to 4 Hz. In many cases the damping can be considered low; sometimes one has to accept damping ratios down to 0.05 and even lower. Fig 4.3 illustrates the meaning of different damping ratios. In the network the rotor oscillations show up as oscillations in power, voltages, etc. The term power oscillation is often used.

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As to steady-state stability, if the damping of a mode becomes negative, an oscillatory instability will appear. An oscillation will occur spontaneously or after a small disturbance. The oscillation amplitude will be either constant or growing in the former case the instability will disturb the continued operation of the power system, in the latter case it will lead to loss of synchronism.

As to subsequent swings of transient stability, the oscillatory behaviour is similar to that of steady-state stability, but with pronounced effects of the non-linear characteristics of the power system.

In those cases where damping improvement is necessary or desired, advantage should, of course, first be taken of the two low-cost measures available:

Ensure that the most important generators are equipped with excitation control systems with good performance qualities and that the voltage regulator parameters of these systems are properly adjusted.

Equip the voltage regulators of the above generators with so-called power system stabilizers(PSS).

For those cases where the above measures are not sufficient, e.g. cases of low-frequency inter-area or tie-line oscillations, SVCs may, depending on some conditions, be an excellent means for further damping improvement. This matter is discussed in the following of this sub-section.

Fig 4.4 illustrates the ideal control principle for optimum damping of one type of a symmetrical two-machine system. Each machine may represent a number of generators. Ideally the reference value for the midpoint voltage should be composed of a fixed component and a component proportional to the speed difference between the two equivalent generators. This means that the modulation of the reactive power injection at the midpoint should lead by 90 degrees the power oscillation between the segments of the system.

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In some few cases, and due to the load area locations in the power system, a certain damping can be achieved by keeping the SVC bus voltage constant. Usually, however, the SVC has to be equipped with a supplementary controller, a so called power oscillation damper (POD) modulating the SVC bus voltage with a proper relationship to the oscillations. POD input signals used so far are local signals: active power of the passing lines or frequency of the SVC bus voltage.

The use of an SVC with POD may raise the steady-state stability power limit of a transmission link, i.e. of a tie line. This may be of great economic value. Improvement of the damping of the oscillations after large disturbances may also be desirable.

The following remarks are recommended to be considered when planning to use an SVC for damping improvement:

Whether an SVC will be useful for damping improvement or not depends

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on the network configuration, where the power stations and load areas are situated in the network and in particular where the SVC is connected.

A study should usually be performed for each application in order to determine if the desired damping improvement can be achieved and to establish the POD parameter values to be set. Both frequency-domain analysis based upon a linearized description of the power system and time-domain simulations by means of a transient stability type program are useful.

4.10 Extensive cable networks

Cables produce up to twenty to forty times more reactive power per km than overhead lines. This creates voltage and reactive power control problems in some large metropolitan or urban areas with extensive underground EHV cables, particularly during light load periods. Local generators and shunt reactors are used in the first place to absorb the excessive reactive power. In the EREB (India) power system an unusual method, named tap staggering, has also been applied. By this is meant operating parallel transformers on different tap position thus creating a circulating current and increasing the reactive power losses. Also in conjunction with long submarine EHV cables, there may be a need for considerable absorption of excess reactive power. So far, normal shunt reactors have usually been applied. It seems that a combination of fixed shunt reactors and SVCs, of a type that can absorb reactive power only, should be the ideal solution in several cases.

4.11 HVDC terminal stations

HVDC converters always consume reactive power when in operation. The reactive power consumed is normally around 50 per cent of the active power converted, which means that the terminal stations need large reactive power supplies. Rectifier stations with adjacent generators, the reactive power need is usually covered partly by the generators and partly by shunt capacitors in

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the stations. At inverter stations with low short-circuit capacity, synchronous compensators have often been installed in order to increase this, so as to avoid some undesirable effects. These synchronous compensators are, naturally, also used for reactive power production (or absorption), the AC voltage control and to reduce load -rejection temporary over voltages. The remaining reactive power need is then usually covered by shunt capacitors.

Most of the shunt capacitors, if not all of them, in a terminal station, form integral parts of the necessary AC filters, which means that these shunt capacitors perform the dual tasks of reactive power production at fundamental frequency and diverting of harmonic currents.

The MVA amount for reactive power compensation devices needed in conjunction with an HVDC transmission is quite high. For example the 6300 MW Itaipu HVDC system of FURNAS, Brazil, has 1541 Mvar of 500 kV AC filter banks at the rectifier station and 2483 Mvar of 345 kV AC filter banks, 588 Mvar of 345kV normal shunt capacitor banks and 1200 MVA (2000 Mvar control range) of synchronous compensators at the inverter station.

It seems that a combination of synchronous compensators and SVC s should be an attractive solution, for easily and continuously variable reactive compensation and voltage control, in several inverter plants, instead of synchronous compensators only, where such are needed. This would be for the reasons of rapid control and costs.

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CHAPTER - 5

REACTIVE POWER COMPENSATION IN DISTRIBUTION SYSTEMS

5.0 Introduction

Distribution systems need to be supplied with reactive power to equalize the reactive power consumption of the loads and the net reactive power losses of the distribution network itself. The required reactive power is supplied from one or more of the following sources:

1. Possible synchronous machines within the distribution system2. Shunt capacitors3. Static compensators

Absorption of excessive reactive power is seldom needed. Many electric supply utilities are, for the reasons discussed in the previous sections, restrictive in supplying reactive power from transmission to distribution systems. This is often reflected in the supply tariffs to large consumers, such as retail distribution utilities and high-power industrial customers, with a penalty for low power factor.

Under normal steady-State conditions, the voltage at the consumer terminals should lie within a certain range around the nominal voltage. The limits vary between different countries, different classes of service, etc., but are usually from 5 to 10 per cent from the nominal voltage. The term power-factor correction is used in conjunction with slowly varying loads of distribution systems. It usually refers to the method of generating reactive power relatively close to the loads consuming it.

Power-factor correction by means of fixed and switched shunt capacitors is much used in many urban, residential and rural systems and extensively also in high-power industrial systems. The objective is usually one or more of the following:

To reduce power costs by avoiding low power-factor penalty, if applicable.

To reduce active (i²R) and reactive power (i²X) tosses in the distribution network.

To release current capacity of transformers and cables (and, possibly, overhead lines).

To increase the voltage level and, in the cases of switched shunt capacitors, to improve the voltage regulation (to reduce the voltage variation from light to peak load conditions).

In many existing systems the two latter effects can postpone or even eliminate otherwise necessary large investments in new equipment. Because of the large number of parameters involved and the many alternative combinations of shunt capacitor equipment possible, it is difficult to give universally applicable recommendations for the location and rating of shunt capacitors. An evaluation of the above gains versus the shunt capacitor costs has to be made, considering different constraints such as maximum size of switched banks with regard to voltage change, space availability, etc.

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The control of switched shunt capacitors is an area with many alternative methods in use: manual, time switch, automatic regulator or relay control of voltage or current, or reactive power, or power factor, etc.

5.1 Application of shunt capacitors to HV distribution

Use of shunt capacitors in HV Distribution Systems result in the following advantages(a) They ensure that the transmission of inductive kvar to the load area

from the generating source is kept to reasonable limits.(b) They avoid overloading of circuits and/or release circuit load-carrying

capacity.(c) By avoiding overloading they release spare MVA capacity on the

generators.(d) They reduce the system I2R losses(e) They reduce the system I2X losses(f) They improve the voltage regulation and/or restore it to an acceptable

level for a given load.(g) Shunt Capacitors have low dielectric loss = 0.006 W/KVar(h) Have no moving parts – R&M is easy(i) Do not require heavy foundation like Synchronous Condensers(j) Automatic switching can be done(k) Series and parallel arrangements are possible to suit the system

voltage

Fig 5.1. Radial distribution system – effect of improved load power factor

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5.2 The effect of improved power factor on a radial distribution system

The Fig 5.1 illustrates the effect of improved power factor on a radial distribution system

5.3 Application of series capacitor to distribution systems

Fig 5.2. A general radial distribution system with series capacitors (a) Equivalent series capacitor circuit (b) phase diagram without series capacitor (c) Phasor diagram with series

capacitor

The following formula gives the line to line voltage drop :Voltage drop line-to-line =

This is approximate short line formula and from consideration of this formula it follows that :

1) With high power-factor loads, the value of Cos R is high and Sin R is small. Hence, the resistance drop is predominant so that if the total circuit resistance exceeds the total circuit reactance, the effect of a series capacitor will be small.

2) Conversely, with a low power-factor load, and comparatively high circuit reactance, the inductive voltage drop is dominant. Series capacitors will produce the maximum effect in reducing total voltage drop as they

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directly compensate for inductive voltage. Provided that improvement only in voltage regulation was required, under these conditions a series capacitor would be more effective than a shunt capacitor of the same KVar.

3) Series capacitors reduce voltage drop by compensating for the line reactance but they have no effect on receiving-end power factor, and, in radial circuits, no significant effect on the reduction of line losses. The improvement in power factor of the load at the sending end is due to compensation of the I2XL component of the line.

4) Series capacitors are self-regulating, because, at any load, the IXL

component of the voltage drop is automatically cancelled by the voltage appearing across the series capacitor.

Applications of series capacitor

a. Reduce voltage drop and improve voltage regulation on Transmission lines.

b. Reduce flicker or rapid voltage fluctuation due to loads of repetitive and rapidly fluctuating nature

ex: Large motors, arc furnaces, saw mills, welders etc.

c. Large resistance welders impose very high currents on the supply circuit for only 2 or 3 cycles. Series Capacitor can reduce voltage drops in such cases.

d. Control of load sharing in parallel lines : The series capacitor in a parallel line will reduce its impedance and hence power carrying capacity

e. The maximum power transmitted in a transmission line can be increased for the same regulation with Series Capacitor. Hence the stability margin can be improved.

5.4 Urban, residential and rural systems

There are many different configurations and voltages of these systems. One simple example: A 132/11 kV distribution substation transfers power from a 132 kV transmission to 11 kV distribution feeders (primary circuits). Each distribution feeder supplies a number of 11/0.4 kV distribution transformers, each of which supplies consumer feeders (secondary circuits) at the utilization voltage. The loads are usually many but small. The voltage level and voltage regulation (voltage drop) are usually considered when dimensioning the distribution circuits. Voltage control is actuated by means of on-load tap changers on the distribution substation transformers. Often, as the load increases, the controlling device raises the substation secondary voltage to compensate for the increased voltage drops in the distribution feeders.

Possible local generators are, naturally, utilized for reactive power supply and fine voltage control. Shunt capacitors are much used in these distribution systems, in several countries, for the purposes previously discussed, and

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including voltage control. In spite of the difficulties of stating generally applicable location rules a Swedish committee investigation gives the following summarizing rules of thumb for the location of shunt capacitors in these types of distribution system: Locate the shunt capacitors as close to the loads as possible. In the first place install shunt capacitors, which can postpone the

reinforcing of the network otherwise needed. In the second instance, install low-voltage (utilization voltage) fixed shunt

capacitors in such an extension so that in total they equal the yearly minimum reactive load of the system.

Meet the remaining need by installing switch able shunt capacitors: in the first instance, low-voltage banks at large customers and medium voltage banks at intermediate switching stations.

The above rules should, of course, not be dogmatically applied, but with good judgment, considering the actual conditions. Another recommendation given is that the maximum voltage change when switching a bank should not exceed 2 per cent for hourly switching, 3 per cent for daily switching and 5 per cent for seasonal switching.

5.5 High-power industrial systems

Many major industrial plants purchase power at 66 kV or above. The distribution systems usually have at least two lower voltages: a medium voltage, e.g. 11 kV, for the primary distribution and large loads, and a low voltage at 0.4 kV for other loads.

5.6 Steady-state var supply and voltage control

Induction motors are common loads, which consume reactive power. Static power converters and uncompensated fluorescent lamps are other examples. Static power converters for rolling-mill DC motors and arc furnaces, in steel mills, have reactive power consumptions with a large average value and are subject to substantial rapid fluctuations.

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The primary voltage control is usually achieved by means of on-load tap changers of the step-down transformers from the metering point. Existing synchronous machines are naturally also used for reactive power generation: generators for reactive power supply and fine voltage control, synchronous motors for reactive power supply. In some few cases, existing small synchronous condensers may possibly still be used.

Power-factor correction by means of fixed and switched shunt capacitors is extensively used in industrial systems, for the reasons previously discussed. Figure 5.3 indicates different locations: A)System level correction, B) plant correction, C) group correction, D) motor correction.

Static power converters and arc furnaces produce current harmonics, which must be considered during the planning and designing of shunt capacitor installations, in many cases, shunt capacitors are arranged for both functions, reactive power production at fundamental frequency and filtering of harmonic currents.

5.7 Capacitor location for industrial power factor improvement

5.7.1 H V Distribution

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Fig 3: Industrial Shunt Capacitor

Fig 5.4. Schematic diagram of layout for a larger size factory with high voltage supply and high voltage distribution showing possible location of capacitors A,B,C,D are distribution sub

stations with A showing detail typical of the others.

5.7.2 HV distribution with loads fed direct from H.V.

Fig 5.5. Schematic diagram of layout for a large factory with high voltage distribution and loads fed direct at high voltage and low voltage. A,B,C,D are distribution sub stations with A

showing detail typical of others

(a) Factories not operating continuously, and which may be supplied at high voltage but with low-voltage load, should employ low-voltage

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capacitors for power factor improvement. Low voltage switchgear is much cheaper than high voltage gear and obviously is available with much lower ratings which enable relatively small capacitor steps (100 kvar and below) to be employed for automatically controlled capacitors. This ensures flexibility of operation without excessive switchgear costs.

(b) High voltage capacitors should be employed for power-factor improvement of all loads supplied directly from the high voltage supply, e.g. large induction motors, electric furnaces, a.c./d.c. converter plant etc.

(c) Splitting total requirements LV capacitors for power factor improvement between various locations may well increase capital and installation costs. Such action can only be justified when special distribution or operational requirements must be met or when, for example, individual connection of suitable motors may reduce the cost of capacitor control gear hence the total capital cost.

(d) In a factory where the low-voltage is supplied from several distribution substations, local automatic control at each substation is generally much cheaper as well as operationally superior to an elaborate method of overall contrl operated from the point of incoming supply.

(e) To reduce initial costs, whenever practicable, switchgear for controlling capacitors should be operated as closely as possible to its maximum capacitive load rating. This condition, while easily met with low-voltage switchgear (contractors), can only be satisfied with high voltage switchgear when the capacitor steps are relatively large, i.e. up to 5 MVAr. For a multi-stage high-voltage bank with, say 500 KVar steps, the switchgear could cost considerably more than the capacitors.

(f) For the power factor improvement of large continuously operating industrial plants with no local distribution problems or special operational requirements, the most economical scheme is one which employs a large high voltage capacitor bank manually controlled by means of a circuit breaker connected to the line continuously. The cost per KVar is low, switchgear operates close to its maximum capacitive rating and installation charges are at a minimum.

5.8 Reduction of voltage fluctuations

Rapidly fluctuating loads create voltage fluctuations, which may cause annoying disturbances, particularly flicker of filament lamps in adjacent load areas. The most pronounced load of this kind is the arc furnace.

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In AC arc furnace is usually a large load on a power system. Furthermore, it is a nasty load, characterized by:

Low power factor Unbalance Rapid large active and reactive power fluctuations of more or

less random character and with an irregular frequency of 2 to 20 Hz.

Harmonic currents.

Figure 5.6 shows a typical arc-furnace supply of a steel mill. The reactive-power consumption fluctuation is the most Important one for the voltage fluctuations, due to the relatively high reactance/ resistance ratio of the supply network. Figure 5.7 shows a typical arc-furnace reactive-power consumption.

The mean reactive power consumption can be compensated for by means of a shunt capacitor. The voltage fluctuation remains. However even somewhat magnified by the shunt capacitor, both at the arc furnaces bus C and at the

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Fig.5.6 Typical arc-furnace supply

Fig 5.7 typical arc-furnace reactive power consumption

bus B. The latter, named the PCC bus (point of common coupling with other consumers) is the critical one with regard to voltage fluctuations.

Before the era of SVCs, there were no good means for effective reduction of these rapid, unbalanced voltage fluctuations. The SVC is such a means. When used, it is connected to the arc furnace bus C in Figure 5.6. Due to the effective reduction of the voltage fluctuations also at the bus C, it is possible to operate the arc furnace at a higher average voltage level without adverse effects, thus increasing the furnace active power and reducing the meltdown time; This was first overlooked, but it became later on an economic incentive for the installation of SVCs.

A great many SVCs are installed in conjunction with arc furnaces. The majority of them are of the type Thyristor-controlled reactor (TCR) in parallel with a fixed capacitor (filter).

Fig 5.9 shows the single-line diagram of a typical SVC arrangement in conjunction with arc furnaces; the figures apply to a particular large installation.

5.9 DC arc furnaces

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The majority of arc furnaces in operation are of the AC type. During recent years the AC arc furnace has, however, met with competition from the DC arc furnace. A Thyristor rectifier supplies the direct current.

The voltage fluctuations caused by a DC arc furnace are different from those caused by a comparable AC arc furnace. However, as in the case of the AC arc furnace, depending on the short-circuit level, an SVC will normally still be needed to reduce the voltage fluctuations. AC filtering is usually needed to divert the harmonic currents produced by the rectifier and arc furnace.

5.10 Reduction of voltage drop during starting of large motors

Direct-on-line starting is the simplest, most straightforward and cheapest of all the starting methods for induction motors. It creates, however, a high inrush current at low power factor, in turn causing a voltage drop. In cases of one or more large motors in relation to the network short-circuit capacity, these voltage drops may be intolerable due to their size and frequency of occurrence. They may disturb the performance of other loads in the plant and the loads of other consumers. In cases of very large load torque during starting, the starting of the motor itself might be critical. One method of several of reducing the voltage drop is the use of a starting shunt capacitor, which operates during starting only. A technically much superior method is the use of an SVC.

Fig. 5.10 shows the single-line diagram of such an SVC application. The SVC is installed in a mining load area with sometimes very low short-circuit MVA capacity and with frequent starting of relatively large induction motors.

5.11 Location of Power Factor improvement Capacitors on Induction Motors

Fig 5.11 illustrates the alternate methods of connecting a capacitor to a motor fitted with a star/delta starter.

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Fig.5.10 SVC in a mining load area.

Connection A: When a motor is started with the windings connected in star, the phases of the capacitor are also connected in star and therefore the capacitor will provide only one third of its minimum KVar output. When maximum, KVar should be available for correction.

Connection B used a standard 3 terminal delta connected capacitor, which gives maximum power factor correction at the start when the power factor is low.

Fig 5.11. Alternative methods of connecting a capacitor to a motor fitted with a star/delta starter. Connection A using six terminal capacitors and connection and B

using three terminal capacitors.

5.12 Location of capacitors for individual correction or motors

The capacitor may be connected in one of the three points as shown in Fig.5.12.

Location A: The capacitor is installed on the supply side of the starter and Motor overload relay. a) The capacitor size is not dependent upon the Motor no-load magnetizing current (b) The current to the starter remains unchanged. (c) The motor overload trip settings remain unchanged.

Location B: The capacitor is installed on the load side of the starter, but on the line side of the overload relay, (a) The capacitor size is dependent on the motor magnetizing current (b) The current to the starter is reduced (c) The motor overload trip setting is the same as without capacitor

Location C: The capacitor is installed on the load side of both the starter and motor overload relay. (a) The capacitor size is dependent upon the motor

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magnetizing current. (b) The current to the starter is reduced (c) The motor overload trip setting (OLTA) must be reduced as follows:

OLTA new = OLTA old x

Fig 5.12. Diagram showing the alternative points of connection for capacitors used to correct the power factor of induction motors

5.13 Location of reactive compensation devices in Transmission and Distribution

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A hypothetical power system illustrating possible locations of reactive power compensation devices is shown in fig 5.13

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References

1) Power capacitor hand book

-T Longland, T W Hunt, W A Brecknell : Butterworths – 1984

2) Reactive Power Compensation

- Tore Peterson, ABB Power systems, SWEDEN – 1993

3) Proceedings of Seminar on “CAPACITORS” during 18 – 19 January 2001

- A CBIP and MPEB publication – 2001.

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