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24.1 Capacitors for improving system voltage regulation24/883

24.2 Series capacitors 24/883

24.3 Rating of series capacitors 24/883

24.4 Advantages of series compensation 24/884

24.5 Analysis of a system for series compensation 24/886

24.6 Reactive power management 24/88724.6.1 Objectives 24/88824.6.2 Analysis of an uncompensated transmission line

24/88924.6.3 Power transfer 24/890

24.7 Influence of line length (Ferranti effect) 24/893

24.8 Optimizing power transfer through reactive control 24/89624.8.1 Line length effect (sin q): 24/89824.8.2 Influence of load angle (sin d) 24/898

24.9 Dynamic and transient stability of overhead lines(Applications of reactive controls) 24/90624.9.1 Auto-reclosure schemes 24/907

24.10 Switching of large reactive banks 24/90824.10.1 Thyristor-switched capacitor banks (TSCs) 24/90924.10.2 Thyristor-controlled reactors (TCRs) 24/91024.10.3 Transient-free switching 24/91024.10.4 Response of SVC on a fault or line disturbance of

a transient nature 24/91124.10.5 Combined TSC, TCR and fixed capacitor banks

24/911

24.11 Automation of power network through Supervisory Controland Data Acquisition (SCADA) System 24/91224.11.1 Application of a SCADA system 24/91424.11.2 SCADA implementation 24/91524.11.3 Implementation of load shedding and restoration

24/92024.11.4 EMS-SCADA: (Energy management solutions)

24/92224.11.5 Serial data transmission to a control and

automation system via communication interfaces24/922

24.11.6 Introduction to general protocols 24/92424.11.7 The OSI (Open System Inter-connection) seven

layers models 24/926

24System voltageregulation andimproving powerquality

24/881

24.11.8 Security to a SCADA system 24/927

Relevant Standards 24/930

List of formulae used 24/930

Further Reading 24/931

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24.1 Capacitors for improvingsystem voltage regulation

Another important application of capacitors is to improvethe voltage regulation of a power supply system. Theregulation of a power system at the receiving end isdefined by

% Regulation

= Voltage at no load – Voltage at full load

Voltage at no load 100¥

(24.1)

Higher regulation will mean a higher voltage fluctuationat the receiving end, resulting in poor stability of thesystem. Regulation up to 3–5% may be consideredsatisfactory. To improve the regulation of a system, powercapacitors can be used in series at the receiving end ofthe system.

24.2 Series capacitors

The basic purpose of series capacitance is to offset thecontent of excessive line inductance, reduce the linevoltage drop, improve its voltage regulation and enhancethe power transfer capability and hence the stability levelof the system. It can accordingly find application at allhigh-current and high-impedance loads such as

• An electric arc furnace, where heating is caused byarc plasma between the two electrodes. The arcingmakes the circuit highly inductive, besides generatingunbalanced currents (third harmonics), due to differenttouchdown arc distances in the three electrodes whichmake it a non-linear impedance load.

• An induction furnace, where the heating is due toeddy current losses induced by the magnetic field.

• Electric arc and resistance welding transformers asfor spot, seam and butt welding.

• Large scale electrolysis of aluminium, copper or zinc.• A long transmission line, say, 400 km and more, for

a radial line and 800 km and more for a symmetricalline, as discussed later.

• It can also be applied to an HV distribution networkthat has a high series inductive reactance to improveits receiving-end voltage.

In all these applications a shunt capacitance is of littlerelevance, as it will not be able to offset the line inductivereactance, XL, with XC, and hence will be unable to containthe switching voltage dips at the load end in furnacesand also voltage drops during a change of load in atransmission or HV distribution network. A shunt capacitoroffsets the reactive component of the current (Figure23.2) while the line voltage drop, for the same line current,remains unaltered. Series capacitors are therefore moreappropriate where voltage regulation is the main criterion,rather than line loss reduction. Summarizing the above,the main functions of a series capacitance can be statedas follows:

1 To neutralize and reduce substantially the content ofinductive reactance of the line. Refer to a simpletransmission network with series compensation, shownin Figure 24.1.

2 To alter the circuit parameters L and C, to reduce theline impedance and hence the voltage drop, and alsoenhance utilization, i.e. the power transfer capabilityof the line.

3 To improve the far end or the load-side voltage, inother words, the voltage regulation and the stabilitylevel of the system.

Notes1 Unlike the above, a shunt capacitor alters the load current by

offsetting the reactive component of the current (Figure 23.2)by improving the load p.f. and altering the characteristics of theload.

2 A series capacitor has little application in an LV system due tothe high content of line resistance and very little of inductance.Any amount of reactive compensation will scarcely influencethe performance of the line, as a result of the high content ofIR, compared to IXL.

Series and shunt capacitors both provide the samedegree of compensation. But it is the correct reactivesupport that provides a more stable system less prone toload and voltage fluctuations. Thus a judicious choicebetween the shunt and the series capacitors is required.In the following our main thrust is to arrive at the mostappropriate type and extent of reactive support to achievea higher level of utilization of a power transmission ordistribution system, on the one hand, and more stability,on the other.

24.3 Rating of series capacitors

Referring to Figure 24.2, this can be expressed by

kVAr = 3 12

C◊ ◊I X (24.2)

G

GT

Transmitting-sidevoltage Es

Primarytransmission(Generator side)

Series capacitors

Receiving-endvoltage Er

Secondarytransmission(Load side)

Figure 24.1 A simple transmission network with seriescompensation

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whereI� = line current. The value of line current to be

considered for calculating the size of capacitorbanks must take account of the likely maximumload variation during normal operation or the over-load protection scheme provided for the capacitors,whichever is higher.

XC = capacitive reactance of the series capacitors per phase.And voltage rating = I� · XC.

This rating will be much less than the nominal voltageof the system. But since the series capacitors operate atthe line voltage, they are insulated from the ground andfrom each phase according to the system voltage. Forthis purpose, they are generally mounted on individual

platforms for each phase, which are adequately insulatedfrom the ground. Figure 24.3 shows such an installation.

24.4 Advantages of seriescompensation

(i) Automatic voltage regulation: Since the VAr of aseries capacitor µ ,C

2I the voltage regulation isautomatic, as the VAr of the series capacitors willvary with a change in the load current. When thevoltage drops, the line current will rise, to cope withthe same load demand and so will rise the VAr of thecapacitors also providing an automatic higher VAr

Figure 24.2 The single-line diagram for Figure 24.1

G

GT R XLXC

Es Lineparameters

Seriescapacitors

IEr

Load side

Figure 24.3 The installation of HV capacitor banks (Courtesy: Khatau Junker Ltd)

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compensation. When the voltage rises, the currentwill fall and so will fall the VAr compensation. Noswitching sequence, as necessary in shunt capacitors,is therefore required for series capacitors.

(ii) They may be connected permanently on the system,as they compensate the line reactance, which is fixed,though the load reactance may be variable, unlikeshunt capacitors, which are to be monitored for theiraddition or deletion during peak and off-peak loadperiods respectively. The costs of switchingequipment and operational difficulties are thereforelow in series capacitors.

(iii) They also provide the same degree of p.f. improvementas the shunt capacitors and do so by the leading voltagephasor rather than the current phasor.

Limitations(a) It is not advisable to use them on circuits that have

fluctuating loads or frequent inrush currents, such asswitching of motor loads. During a start the latterwill cause an excessive current, Ist, and proportionatelyraise the potential difference across the capacitor units(Ist · XC) and over-load them in addition to causinghigher dielectric stresses. Series capacitors for suchinstallations must be designed for very high voltages,say, up to Ist · XC/1.5, which will not be economical.Also, protection against over-voltages will still beessential as a safeguard against a similar contingency,as discussed later.

(b) It is possible that the natural (sub-harmonic) frequency(1/2 ,p LC Section 17.6.3) of a system with seriescapacitors may fall below the fundamental frequencyand render the system more prone to resonance. Nowresonance may occur below the fundamentalfrequency. This may prove fatal under certain loadingconditions and influence the source of supply in thefollowing way:1 Ferro-resonance effects

An L-C circuit is more prone to ferro-resonanceeffects during voltage fluctuations as a result ofsaturation of the iron core, which may be of atransformer or an inductor coil. On saturation, theinductance reduces drastically and becomes moreprone to resonance with the capacitance of thecircuit. Voltage fluctuations may occur due toswitching operations, particularly of an unloadedline or load fluctuations (Section 20.2.1(2)).Although the line impedance will provide asufficient damping effect to automatically attenuatesuch a state, precautions are mandatory to avertthe same. An inductive compensation, of the orderof 40–50%, may be adequate to improve the systemparameters and also avert a ferro-resonance effect.A more realistic approach to the problem is possibleif a mathematical model of the ferro-resonance isdeveloped and supplemented by experiments toproduce data to design an appropriate seriescompensation scheme.

2 Sub-synchronous resonance (SSR)A series compensated network will have its naturalfrequency expressed by

fL C

h = 12 p ◊ (Section 17.6.3)

The above can also be expressed by

f fXXh

C

L = ◊ (Equation (23.11)

wherefh = natural frequency of the series circuitf = nominal frequency of the systemL = natural reactance of the line per phase,

including that of generator and loadXL = 2p · f · LC = series capacitance per phase

Xc =1

2 p ◊ ◊f C

The frequency, fh, will occur for only a few cyclesduring an abrupt change in the line parameters, suchas during a switching operation or occurrence of afault etc. (Section 17.6.3). To ensure that the circuitremains inductive under all conditions of loadvariations and fault, to avoid a capacitive mode ofoperation and an excessive charging voltage thecontent of XL must remain higher than XC (XL > XC).The natural frequency, fh, therefore has to benecessarily lower than the power frequency of thesystem (fh < f ). This is an unusual transientphenomenon that occurs in a series compensatedsystem which is adjusted for its natural frequency tomaintain XL > XC and may have far-reachingimplications. In the sub-synchronous range of a steamturbine generator this frequency may cause a resonancewith the rotating masses of the turbo-generator rotorand generate electromechanical oscillations in therotor. This may assume serious significance in largegenerators which have a number of natural mechanicalfrequencies of the rotating masses, in the range of10–25 Hz. This frequency may coincide with thenatural frequency of the system during a linedisturbance and magnify the oscillations of the rotatingmasses beyond desirable limits. If unchecked, theseoscillations may continue to magnify and result inthe shearing off of the weakest part of the shaft.Although rare, serious damages have occurred inearlier years, when the turbine shaft had actuallysheared off because of this phenomenon. Hydro-turbine generators are less prone to such oscillations,as their natural mechanical frequency lies below 10Hz. The natural frequency of a series compensatedsystem may not reach this level.

These oscillations can be damped with the useof filter circuits or by bypassing all or part of theseries compensation during a line disturbance.Similar techniques are adopted while protecting theseries capacitors against fault conditions, as notedin Section 26.1.2(2) and illustrated in Figure 24.4(Figure 26.10 redrawn). For critical installations itis essential to first evaluate the likely frequencies ofthe rotating masses and then more exacting measuresbe taken to avoid a resonance.

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If a large induction motor is switched on such asystem it is possible that its rotor may lock-up atthe sub-synchronous speed and keep running athigher slips. This situation is also undesirable, asit would cause higher slip losses in addition tohigher stator current and over-voltage across theseries capacitors.

3 System fault levelSince the line impedance, R + J (XL – XC), willreduce with a series compensation, the fault levelof the system will rise. It should not matter if thefault level of the system is determined by theimpedance of the source of supply as a customary,ignoring any other impedance of the circuit (Section13.4.1(5)). Moreover, such a situation isautomatically averted through the protection ofthe series capacitors, as discussed below, by whichthe capacitors are bypassed during a line fault, theline restoring its original impedance, hence theoriginal fault level. Nevertheless, when it is requiredto limit the system fault level, inductive couplingcircuits may be provided to reduce the fault to thedesired level. This is also discussed below:

The fault current can be limited by providing adamping circuit, such as a short-circuit-limitinginductive coupling, across the series capacitors, asillustrated in Figure 24.4. This can be a combinationof an R–L circuit. During normal operation thiscircuit will provide a high impedance and remainimmune. On a fault, the high voltage across thecapacitors will cause a heavy inductive currentflow through the coupling circuit, which willneutralize the capacitive current through thecapacitors and help keep the capacitors almost outof circuit (IC fault � IL fault), similar to a shortingswitch, as discussed later. The normal condition isrestored as soon as the fault condition is cleared.It may also be regarded as a filter circuit, as itwould also help to damp the system harmonics.

24.5 Analysis of a system for seriescompensation

Consider a simple system as shown in Figure 24.5(a).

Figure 24.4 Damping circuit across the series capacitors to limit the fault level

G

1 2 3

4

6

5

1

2

3

4

5

6

Es

XL R

I� (fault)

Ic (fault)

ErReceiving end

Ic (fault)

I� (fault)

Ic (fault) � I� (fault)

Effective currentthrough capacitorsand coupling circuitis nearly zero

An R–L damping circuit

Series reactor to add toline impedance

Isolators

Damping resistor

Auxiliary saturating reactor

Main saturating discharge reactor

G

I� R XL

Vr LoadEs

(a) Circuit diagram of an uncompensated line.

I� · R

I� · XL

Es

I�

fVr

I� · XL

Es

I�

f

Vr

(b) When ’R ’ is significant

(c) When ‘R ’ is insignificant

Figure 24.5 Receiving-end voltage phasor diagram on load,in an uncompensated line

1 When the line resistance, R, is significant comparedto the line inductive reactance, XL, there will be alimited use of series capacitors (XC) in view of alarge content of I.R. See the phasor diagram in Figure24.5(b). Also refer to Figure 24.5(c) when R isinsignificant. Now the receiving-end voltage, Vr, canbe improved by offsetting the reactive componentwith the use of series capacitors.

2 When R << XL: Now XC (Figure 24.6(a)) will offsetthe inductive component and improve the p.f., capacityof the system and also the receiving-end voltage, asillustrated in Figure 24.6(b). This advantage is not

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possible through a shunt capacitor. Accordingly, itmay be noted that the difference between thecompensated and the uncompensated receiving-endvoltages will be significant only when the content ofI · R is low, compared to I · XL.

In certain distribution networks the natural I · Rdrop itself may be sufficiently high to cause a dip atthe receiving end more than desirable even when thereactive component is fully compensated.Consequently, such a distribution network may haveto be operated underutilized or the size of the currentcarrying conductors may have to be increased to reducethe value of R, and hence the content of I · R, andthus raise the capacity of the line. It may thus beconcluded that

• In smaller cross-sectional areas of the current carryingconductors of the distribution network, i.e. for low-capacity networks where R/XL is high, seriescompensation may be redundant.

• For higher cross-sectional areas, i.e. for high-capacitynetworks where R/XL is low, series compensationwill be useful.

We will notice subsequently that series and shuntcompensation are complementary. What a shunt capacitorcannot do, a series capacitor does and vice versa. On asecondary transmission system, say up to 66 kV, a shuntcompensation may always be necessary to improve thepower factor, as the load would mainly be inductive. Aseries compensation may become essential, to improvethe stability of the system, to cope with load fluctuations,switching of non-linear loads and voltage fluctuations

occurring on the other power system or the grid to whichthis system may be connected.

Series capacitors have also proved to be an easy toolof relieving an already overstressed distribution networkto meet ever-growing load demands, particularly whenit is not practicable to add another line for reasons ofcost or space.

24.6 Reactive power management

Through careful management of the reactive power,making use of shunt and series capacitors and reactors,we can provide support to an overstressed LV or HVsupply system, and achieve optimum utilization and ahigher level of stability.LV systems In LV systems reactive control is providedto improve the load p.f. and hence its load-carryingcapacity, as discussed in Chapter 23. This is achieved byoffsetting the inductive content of the load current at thereceiving or the consumer end by the use of shuntcapacitors. Hence support the system by reducing linelosses and improving its active load current (I1 cos f)carrying capacity. Despite emphasis to control the p.f. atthe distribution or the consumer end, it is not possible tofollow this rule to the desired extent, due to manyconstraints. One is ignorance or callousness on the partof consumer. It is therefore essential to compensate theomitted uncompensated load at the secondarytransmission.HV and EHV systems (132 kV and above): In thesesystems even a shunt inductive control may becomenecessary to offset the excessive charging currents, causedby the distributed leakage capacitances (C1’s) of the line,particularly during no-load or light-load periods. It isessential to relieve the system, particularly the generatingsource, from an unwanted burden of reactive load (Figure24.23). Figures 24.7(b) and (c) show the distributed andequivalent single-line diagrams of an uncompensatedtransmission line illustrated in Figure 24.7(a). Thedistributed leakage capacitances C1’s cause the line-chargingcurrents (ic1’s) even when the far end of the line is opencircuited. Figure 24.8 describes a normal current profileof such charging currents.

Capacitors play a vital role in the management ofreactive control in power transmission and distributionsystems. With industrial growth and growing demandfor power for public services, utilities and consumer needs,efficient reactive power management has become all themore desirable. In the following text, we broadly considerthe purpose and application of reactive powermanagement. The design of a power transmission ordistribution system is a different subject and is beyondthe scope of this book. Reference may be made to worksby many authors, some of which are provided in theFurther Reading at the end of the chapter.

Some developing countries, where reactive powermanagement practices have not been predominant, forwhatever reason, consideration of cost being one, maysuffer from fluctuating voltages, flickering lights, highline losses, reduced capacity of the power lines and

G

I� R XL XC

VrEs Load

Figure 24.6(a) Circuit diagram of a series compensated line

I �

· X

L I �

· X

CI� · R

Es

Vr

With series compensationWithout series compensationVr

I�Series

compensation

f

Figure 24.6(b) Phasor diagram of the series compensatedsystem

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consequent over-loadings etc, leading to frequent trippingsand breakdowns. The active load current (I1 cos f)becomes too low at low p.f.s. Frequent and wide voltagefluctuations lead to fusing of bulbs and failure offluorescent lights, besides requiring a voltage stabilizerwith each household appliance, such as TVs, airconditioners, refrigerators, ovens and computers.

All this increases the direct cost of the appliances, onthe one hand, and additional burden on the already over-stressed lines, on the other, by permanent losses of such

voltage boosters and generation of harmonics (becauseof magnetic cores and use of electronic circuits in suchappliances), which further erode the p.f. and quality ofthe power.

NoteThe reactive power should not be carried over long distances for itmay cause higher voltage drops and steep voltage gradients, on theone hand, and higher line losses due to higher line currents, on theother. Hence, it will affect the utilization capability of the entiresystem, including that of the generating source, transformers,overhead lines, cables and other line equipment.

24.6.1 Objectives

The basic objectives of a reactive power managementsystem can be identified by the following for LV and HVdistributions:

(A) Quality of power

1 Load balancing and reduction in negative phase sequencecurrents. In Section 16.12 we have discussed loadbalancing of two generators where more emphasis isplaced on the active control of power through speedcontrol of the prime movers rather than its field (reactive)control. Active load balancing is more appropriate forthe optimum utilization of a machine rather than reactivecontrol. But in the case of a power transmission ordistribution network it is the optimum utilization ofthe available active power through efficient reactivepower management that is more relevant.

A load unbalance is a common feature in a powersystem, and can be the result of one or more of thefollowing:

• A higher neutral current in the LV distribution due tounequally distributed single-phase loads.

• Saturation of power transformers as a result of periodicover-loading and load rejections.

• Increased ripples in the rectifier circuits, causingharmonics.

• Malfunctioning of some equipment, possibly becauseof a fault.

• Oscillating torque in the rotating machines as aresult of load variations and harmonics present in thesystem.

• Feeding non-linear loads such as:– Induction furnaces– Arc furnaces and arc welders

G

R

Y

B

Generator

GLumped leakage

capacitances

(a) Distributed line leakage capacitances

Cha

rgin

g cu

rren

t (I

o)

0

Sendingend

Line length Receivingend

Figure 24.8 Charging current profile on no load in a transmissionline

G

Generatortransformer

(Figure 13.21)

Io L1 L1 L1 L1

Es C1 C1 C1 C1 Vr

ic1 ic1 ic1 ic1

(b) Distributed line parameters

Figure 24.7 Representing an open circuited transmission linewithout compensation

G

Io R1 X1

Es

Io

Xc1 Vr

G(c) Equivalent circuit diagram on no load

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– Steel rolling mills– Large motors with periodic loading– Thyristor drives– Railway traction which is mostly through d.c. drives– And many loads which may have to be frequently

switchedAll such loads generate harmonics and cause variationsin the fundamental power frequency of the supplysystem leading to distortion in the sinusoidal waveformof the voltage. This distortion may affect the qualityof the supply system (voltage) beyond desirable limits.A non-sinusoidal and distorted supply system mayadversely affect the different loads connected onthe system, besides leading to outage of the systemitself.

2 Maintaining a near-unity p.f.3 Maintaining the frequency to near constant by

suppressing the system harmonics.4 Maintaining the receiving-end voltage at almost the

rated voltage.

(B) Transmission of power

1 Enhancing the steady-state power transfer capabilityof the lines over long distances, or making short linescapable of transferring larger powers.

2 Improving the stability of the system by supportingthe voltage at key points. Without compensation, thestability of the system becomes a limiting factor evenfor shorter line lengths and the system is renderedprone to frequent outages on small disturbances.

3 Reducing system oscillations and flickering causedby voltage fluctuations and system harmonics as aresult of frequent and rapid changes in reactive powerdemand, loss of load, loss of generation or a systemfault. Excessive voltage swings may cause trippingof industrial drives and even system outages. High-speed SVCs (Static VAr Compensators, Section24.10(2)) can overcome such situations by providingappropriate reactive power support during systemdisturbances and maintaining a near-flat voltage profilethrough the length of the transmission line.

4 Providing voltage support when switching largeloads.

5 Improving voltage regulation: both over-voltages(OVs) and under-voltages (UVs) are undesirable. AnOV may cause ageing of the equipment’s insulationand can lead to a flashover or eventual breakdown ofthe terminal equipment and line insulators. It mayalso lead to saturation of power transformers operatingin the system. The transformers produce high currents,rich in harmonics, and cause ferro-resonance or sub-synchronous resonances. A UV will result in highersystem loading than necessary and cause under-utilization of the system capacity.

In the following we consider the case of a transmissionline, 132 kV and above, being more typical and complexfor the purpose of reactive power control. Based on this,it would be easier to apply appropriate reactive controlto a distribution network and large inductive loads suchas an arc or induction furnace.

24.6.2 Analysis of an uncompensatedtransmission line

(i) Current profile

A transmission line can be represented, as shown in Figure24.7(b). In Tables 24.1(a) and (b), we show typical lineparameters for different system voltages and lineconfigurations. Because of line charging capacitances,C1’s, between conductors, and conductors and ground,as shown in Figure 24.7(a) (higher significance in HVand EHV lines of 132 kV and above), and series inductanceL1, there is a charging current, Io, even at no load andeven when the far end of the line is open-circuited (Figure24.7(c)). Figure 24.8 describes a normal profile for suchcharging currents. This current rises with the rise in linelength and is highest at the generator end. As thisphenomenon is a function of system voltage, it is negligibleor nil in HV lines up to 66 kV. This current is totallycapacitive, ignoring the effect of line resistance, R1. Atransmission line, being a high power transfer system,has a very low content of R1 (Table 24.1(a)).

The magnitude of the charging current, Io, will dependupon the content of C1, which is a measure of line voltage,size of the conductor, spacing between the conductorsand between the conductors and the ground etc. Table24.2 provides the approximate values of charging current,Io, and charging power for a few system voltages withdifferent line configurations. The generated chargingreactive power, by the line charging capacitances (C1’s),flows back to the generating source and has to be absorbedby it, even on no load, or a part of it during light loads.It is a strain on the field windings of the generator, as themachine under no-load or light-load conditions and withcapacitive charging currents will have to operate under-excited, and under-excitation is not a healthy situation(see also Section 16.3.3) for a thermal turbo-generatorbecause,

• A capacitive circuit magnifies the harmonic effectswhen present in the system, as discussed in Section23.5.2, and gives rise to spurious voltages and currents,raising the normal V� and I� to Vh and Ich, respectively(Equations 23.1 and 23.2).

• The stator windings are subject to over-capacitivevoltages as a result of this, and the end turns particularlyare endangered.

• Reduced field current reduces the voltage generated,which may affect the system’s stability.

• The generator manufacturer can define the lowestexcitation level below which the machine may beunstable.

Figure 24.9 shows a typical output characteristic orreactive capability curve of a generator, illustrating thestability levels of the machine under different conditionsof operation. The machine must operate within theselevels and the voltage profile within the specified voltagelimits, as noted in Table 24.3.

Example 24.1Consider a 400 kV, triple-Zebra line, having a distributedleakage capacitive reactance XC1 of 2.74 ¥ 105 W/ km fromTable 24.1(b). Then the charging power per phase per km,

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PV

XC112

C1 =

\ PC12

5 = 400

2.74 10¥

= 0.584 MVAr/km

(ii) Voltage profile

Since the charging current is capacitive in nature, the linevoltage drop at the far end would raise the terminal voltageon a no-load as shown in Figure 24.10. The chargingcurrent and rise in terminal voltage both at no-load orduring an under-loading condition are undesirable. Whilethe former would stress the generator windings, the lattermay cause a voltage swing during a load rejection or

load fluctuation and result in a line outage. These features,if not controlled, may render the system unstable.Overvoltages must be controlled within an acceptablelimit. Table 24.3 prescribes one such limit.

To achieve the above, the charging power must becompensated at the generating end itself, and this can beachieved through a reactive power control as illustratedin Figure 24.11. Figure 24.12 illustrates general voltageand charging current profiles before a compensation andFigure 24.13 a desirable flat voltage profile that can beachieved through a series compensation, discussed later.

24.6.3 Power transfer

It has been established that the active power transferthrough a power system can be expressed by

Table 24.1(a) Typical line parameters per circuit for HV and EHV transmission lines

Nominal Conductor Positive sequence components Zero sequence componentsvoltage, Vr type

R1 XL1 XC1 Z X XL C1 = 1 1◊ R0 XL0 XC0

kV (r.m.s.) W / km W /km W /km W W /km W /km W /km

765 Quad Bersimis 1.142 ¥ 10–2 2.619 ¥ 10–1 2.44 ¥ 105 252.8 2.633 ¥ 10–1 1.053 4.161 ¥ 105

(QB)400 Twin Moose 2.979 ¥ 10–2 3.32 ¥ 10–1 2.88 ¥ 105 309.22 1.619 ¥ 10–1 1.24 4.46 ¥ 105

(TM)400 Twin AAAC 3.094 ¥ 10–2 3.304 ¥ 10–1 2.82 ¥ 105 305.24 1.682 ¥ 10–1 1.237 4.37 ¥ 105

(TA)400 Quad Zebra 1.68 ¥ 10–2 2.544 ¥ 10–1 2.40 ¥ 105 247.09 9.133 0.950 3.73 ¥ 105

(QZ)400 Quad AAAC 1.566 ¥ 10–2 2.682 ¥ 10–1 2.29 ¥ 105 247.826 8.512 1.002 3.55 ¥ 105

(QA)400 Triple Zebra 2.242 ¥ 10–2 2.992 ¥ 10–1 2.74 ¥ 105 286.32 12.186 1.112 4.23 ¥ 105

(TZ)220 Zebra 7.487 ¥ 10–2 3.992 ¥ 10–1 3.408 ¥ 105 368.846 2.199 ¥ 10–1 1.339 5.421 ¥ 105

(Z)132 Panther 1.622 ¥ 10–1 3.861 ¥ 10–1 3.416 ¥ 105 363.169 4.056 ¥ 10–1 1.622 > 6 ¥ 105

(P)

Table 24.1(b)

Nominal Conductor Line inductance Line capacitance Velocity of Wavelengthvoltage, Vr Type propagation l = U/f

XL1 LX

fL

11 =

2 p ◊ XC1C

f XC1

1 = 1

2 p ◊ ◊ UL C

= 1

1 1

kV(r.m.s.) W/km henry (H) W/km n farad (nF)a km/s km

765 QB 2.619 ¥ 10–1 8.33 ¥ 10–4 2.44 ¥ 105 13.04 3.034 ¥ 105 6.07 ¥ 103

400 TM 3.32 ¥ 10–1 10.56 ¥ 10–4 2.88 ¥ 105 11.05 2.927 ¥ 105 5.85 ¥ 103

400 TA 3.304 ¥ 10–1 10.51 ¥ 10–4 2.82 ¥ 105 11.28 2.904 ¥ 105 5.81 ¥ 103

400 QZ 2.544 ¥ 10–1 8.09 ¥ 10–4 2.40 ¥ 105 13.26 3.053 ¥ 105 6.11 ¥ 103

400 QA 2.682 ¥ 10–1 8.53 ¥ 10–4 2.29 ¥ 105 13.89 2.905 ¥ 105 5.81 ¥ 103

400 TZ 2.992 ¥ 10–1 9.52 ¥ 10–4 2.74 ¥ 105 11.61 3.008 ¥ 105 6.02 ¥ 103

220 Z 3.992 ¥ 10–1 12.70 ¥ 10–4 3.408 ¥ 105 9.34 2.904 ¥ 105 5.81 ¥ 103

132 P 3.861 ¥ 10–1 12.28 ¥ 10–4 3.416 ¥ 105 9.31 2.958 ¥ 105 5.92 ¥ 103

Based on Manual on Transmission Planning Criteria, CEA (Central Electricity Authority)a 1 nF = 10–9 F

Note:The line parameters will vary with system voltage, configuration of line conductors and their spacing between themselves and the ground,tower configuration, etc.

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Tab

le 2

4.2

Typi

cal b

asic

l ine

cha

ract

eris

tics

(app

roxi

mat

e)

Nom

inal

Con

duct

orX

L1

XC

1Z

XX

LC

1*=

11

◊P

V Zo

2*

r 1 =

I 1

at

Po

Cha

rgin

gC

harg

ing

Fer

rant

i ef

fect

per

km

volt

age,

Vr

typ

ecu

rren

t pe

r km

MV

Ar/

km

=

1

V 3Z

r ◊I

V10

00

3X

oC

=

r

1

◊ ◊=

1

V Xr2a Cq r

ad1 1

=

X XL C

qp

qOb

rad

= 18

0 ◊

kV (

r.m.s

.)W

/km

W/k

mW

MW

Am

pA

mp

In r

adia

nsIn

deg

rees

12

34

56

78

910

11

765

QB

2.61

9 ¥

10–1

2.44

¥ 1

0525

2.8

2315

.01,

747

1.81

2.40

1.03

6 ¥

10–3

59.3

3 ¥

10–3

400

TM

3.32

¥ 1

0–12.

88 ¥

105

309.

2251

7.4

747

0.80

0.56

1.07

4 ¥

10–3

61.5

1 ¥

10–3

400

TA3.

304

¥ 10

–12.

82 ¥

105

305.

2452

4.2

757

0.82

0.56

71.

082

¥ 10

–361

.97

¥ 10

–3

400

QZ

2.54

4 ¥

10–1

2.40

¥ 1

0524

7.09

647.

593

50.

960.

671.

03 ¥

10–3

58.9

9 ¥

10–3

400

QA

2.68

2 ¥

10–1

2.29

¥ 1

0524

7.82

664

5.6

932

1.01

0.70

1.08

2 ¥

10–3

61.9

7 ¥

10–3

400

TZ

2.99

2 ¥

10–1

2.74

¥ 1

0528

6.32

558.

980

70.

840.

584

1.04

5 ¥

10–3

59.8

5 ¥

10–3

220

Z3.

992

¥ 10

–13.

408

¥ 10

536

8.84

613

1.2

344

0.37

0.14

21.

082

¥ 10

–361

.97

¥ 10

–3

132

P3.

861

¥ 10

–13.

416

¥ 10

536

3.16

948

.021

00.

220.

051

1.06

3 ¥

10–3

60.8

8 ¥

10–3

* C

onst

ant

for

a pa

rtic

ular

lin

e ir

resp

ecti

ve o

f it

s le

ngth

(S

ecti

on 2

4.6.

3).

a C

harg

ing

reac

tive

pow

er i

s pr

opor

tion

al t

o V

r2an

d di

min

ishe

s sh

arpl

y at

low

er v

olta

ges.

Cha

rgin

g re

activ

e po

wer

mus

t be

sui

tabl

y of

fset

at

the

poin

t of

pow

er g

ener

atio

n to

pro

tect

the

gene

rato

r an

d ot

her

conn

ecte

d eq

uipm

ent

from

exc

essi

ve o

ver-

volt

ages

due

to

capa

citiv

e ch

argi

ng.

b Thi

s re

veal

s th

at o

n a

50 H

z sy

stem

the

pha

se d

ispl

acem

ent

betw

een

the

send

ing

and

rece

ivin

g en

d vo

ltag

es, d

ue t

o el

ectr

omag

neti

c pr

opag

atio

n th

roug

h th

e li

nes,

is

of t

he o

rder

of

6∞ p

er10

0 km

. Acc

ordi

ngly

, an

unco

mpe

nsat

ed li

ne s

houl

d be

res

tric

ted

to a

bout

400

km

in le

ngth

in r

adia

l lin

es a

nd 8

00 k

m in

sym

met

rica

l lin

es to

avo

id a

n ov

ervo

ltag

e at

the

rece

ivin

g en

d (T

able

24.5

).

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PE E

Z =

sin

sin s r

1

◊◊ ◊q d (24.3)

The expression is free from p.f. A change in p.f. (cos f),however, will adjust the torque angle, d. The higher thep.f. (low f), the, greater will be the torque angle d andvice versa. For more details to arrive at the abovederivation refer to the Further Reading at the end of thechapter.

Assumption – that the line is lossless, i.e. R1 isnegligible.whereP = power transfer from one end of the line to the

receiving end per phase

Table 24.3 Permissible voltage variations during temporarysystem disturbances

Nominal voltage Vr Rated maximum Rated minimumstability level stability level

kV (r.m.s.) kV (r.m.s.)a kV (r.m.s.)b

765 800 728400 420 380220 245 198132 145 122

a As in IEC 60694 (since withdrawn but we have retained it forreference)b As in Manual on Transmission Planning Criteria, CEA (CentralElectricity Authority).

Figure 24.9 Normal characteristics of a generator, illustrating the stability levels (safe operating limits)

1.0 0.8 0.6 0.4 0.2 0 0.2 0.4 0.6 0.8 1.0

Per unitReactive power

(condenser mode)

Leading mode(field underexcited)

Per unitReactive power

(generator mode)

Lagging mode(field overexcited)

0.2

0.4

0.5

0.6Lead

ing

power

fact

or

0.7

0.75

0.8

0.850.90

0.95

90% generatorstability limit

Exiter-controllimit

0.2

0.4

0.5

0.6

0.7

0.75

0.80.85

0.90

0.95

Prime movercapacity

Lagging power factor

Rotor heatingcapacity

0.2

0.4

0.6

0.8

1.0

Per

uni

tac

tive

pow

er

Io

Es

Vr

Io ·(XL–XC1)

Figure 24.10 Receiving-end voltage rises on no-load

G

Io R1 X1XCC

XC1

Io

G

Es

Figure 24.11 An open circuited series compensated transmissionline

Vr

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Es = phase voltage at the sending endEr = phase voltage at the receiving end in radial lines

(lines connected to single source of supply orgeneration) and midpoint voltage in symmetricallines. (Symmetrical lines are those which are fedfrom both ends such as when the far end is connectedto a power grid.)

Z1 = surge impedance of the line (SIL)

=LC

1

1

= constant for a particular line, irrespective of itslength, although L and C will rise with the linelength (L = � · L1 and C = � · C1, if � is the lengthof the line).

where L1, C1, and R1 are the line parameters, per phaseper unit length. In our subsequent analysis, we haveignored R1, being negligible. The standard line parametersare normally worked out for different system networksoperative in a country by the power transmission and

distribution authorities of that country, on the basis ofconductor configuration, spacing between them and theground. Typical data for a few voltage systems havebeen provided in Tables 24.1(a) and (b).

sin q = line length effect or Ferranti effect, discussedlater

q = in radial lines this is determined for the entirelength of line while for symmetrical lines, it iscalculated up to the midpoint, i.e. it refers toq/2

d = load angle or transmission angle. This is the torqueangle between the receiving-end and transmittingend voltages, and is responsible for the requiredpower transfer from the transmitting end to thereceiving-end.

NoteThis should not be confused with Dq as used in Section 16.10 inconnection with the paralleling of two generators. There it representedthe electrical shift between the rotors of the two machines or supplybuses. If it is not eliminated, it will cause a circulating currentbetween the two machines or the buses when running in paralleland will add to their heating.

For short lines say, 200–300 km, for a 50 Hz system

sin q � q (in radians)

e.g. for a 250 km, 400 kV line, as considered earlier,from Table 24.2, for line type TZ,

q = 59.85 ¥ 10–3 degree/km = 14.96∞ for 250 km

and sin q = 0.258

In radians q p q = 180

◊ = 1.045 ¥ 10–3 per km or 0.261for 250 km (both are almost the same)

and q p

l = 2 ◊ � as in Equation (24.6)

Then from Equation (24.8) noted later,

Z1 sin q =

LC

f L C1

11 1 2 ◊ ◊ ◊ ◊p �

= L1 · 2p f · �

= XL, i.e. the inductive reactance of the entireline length.

and Equation (24.3) will become

PE E

X =

sin s r

L

◊ ◊ d (24.4)

For short lines, this is a very useful derivative.

24.7 Influence of line length(Ferranti effect)

The velocity of propagation of electromagnetic wavesand the line length have a great influence over the capacityof power transfer through a line under stable conditionsand also define the quality of the receiving-end voltage.The electromagnetic waves (electricity) travel with great

1

2

3

1

2

3

Vr/

Es

1.0

Vr

Vr

Io

0Sending

endLength of line Receiving

endI O

/ �– Vr profile without compensation.

– Io charging current profile.

– Vr profile with the use of series capacitors.

Figure 24.12 Voltage and current profiles when the line atthe far end is open-circuited

Io · XCC

Io · XL

Es

Vr

Figure 24.13 Receiving-end voltage is flattened with the useof series capacitors

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speed, close to the speed of light (Section 17.6.6) andhence have a very long wavelength. Since

l = Uf

wherel = wavelength in km

UL C

= 1

1 1(24.5)

= Velocity of propagation of electromagnetic waves� 3.008 ¥ 105 km/s for 400 kV line TZ (as determined

in Table 24.1(b) for the different line parametersconsidered).

\ l = 3.008 1050

5¥

= 6.02 ¥ 103 km

The normal line lengths may vary from 200 km to 500km. As a result, the electromagnetic wave is able totravel scarcely a small fraction of its one full wavelength,up to the far end of the line (Figure 24.14). Theinstantaneous voltage at the receiving-end therefore isnever in phase with the voltage at the sending-end (Figure24.15). This phase displacement, which is caused neitherby the p.f. nor by the mechanical positioning of the rotor

of the generator, or the bus to which the receiving endmay be connected, is termed the Ferranti effect. Itconstrains the line length within certain limits to transmitpower under stable conditions, as discussed later.

This phase shift (q) for a particular line length can becalculated as follows:

q p

l = 2 ◊ � (24.6)

where q = phase shift between the transmitting-end and the

receiving-end voltages, in radians or degrees,depending upon the value of p considered, i.e.

p = 227

or 180∞ respectively.

� = line length in km.

For the various HV and EHV networks and their lineparameters considered, q is calculated in Table 24.2 andthe voltage at the receiving-end, when it is open-circuited,

Er cos q = Es (Figure 24.15)

Or EE

rs =

cos q (24.7)

For the 400 kV, TZ line considered above, Er, for a400 km line length,

q = 400 ¥ 59.85 ¥ 10–3 = 23.94∞.

\ EE E

rs s =

cos 23.94 =

0.914∞

= 1.094 Es

The Ferranti effect therefore, raises the receiving-endvoltage and becomes a potential cause of increased voltagefluctuations when existing in the system, similar to acapacitor magnifying the harmonic quantities. The longerthe line, the higher will be the voltage rise at the receiving-end. This will cause wider voltage fluctuations during loadvariations, particularly during light loads and load rejections.Beyond a certain line length, this effect may even renderthe line unsuitable for the safe transmission of power. Forvery short lines, however, the effect may be negligible andmay be ignored. The line length is therefore chosen so thatthe receiving-end voltage is maintained within thepermissible limits under all conditions of its far-endloading. Thus the receiving-end voltage is influenced bythree factors:

• The line distributed parameters L1 and C1• The Ferranti effect due to C1 and• The p.f. of the far-end load.

The effect of p.f. can be controlled by shunt capacitors,near the load point and the Ferranti effect by altering theline parameters. Since

q p

l = 2

◊ �

=

2

p fU

◊ �

Receiving-end voltageEr rises with q= (Es)max sin wt= (Es)max sin q

Es(max)

Sending endvoltage Es(q = 0) q

400 kmEr cos q

w t

l = 6.02 ¥ 103 km

2p radians or 360∞

Illustrating one wavelength

Figure 24.14 Phasor position of sending-end and receiving-end voltages in an overhead line

Er

EsIs

Ir

q

Figure 24.15 The line length effect even when the sending-endand receiving-end voltages and currents are maintainedat unity p.f.

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= 2 or 1 11

1

p f L CXX

L

C◊ ◊

ÊËÁ

ˆ¯̃

� � (24.8)

or q µ LC

where

L = L1 · � and

C = C1 · �

NoteGenerally, an HV distribution network has a very short length (�),less than 10–15 km. Moreover, the leakage capacitance (C1) forsystem voltages up to 66 kV is almost negligible. The Ferrantieffect is therefore not applicable to a distribution network.

For the same system frequency, the Ferranti effectcan be reduced by• Sectioning or sin ddddd effect: Line length compensation

can be achieved by sectioning, i.e. by dividing theline into two or more sections. This method indirectlyreduces the physical length of line (� ). Each sectionnow operates as an independent line and iscompensated through series capacitors and shuntreactors (as shown in Figure 24.23) controlling thevoltage within the required limits, at all such sectionssince

PE E

Z =

sin

sin s r◊◊ ◊q d

Maximum power transfer is possible when d = 90∞.If the line is compensated, say, at the midpoint, asshown in Figure 24.16(a), then the maximum powertransfer will improve to

PE E

Zms m =

2 sin

2

sin 2

◊

◊◊q

d

where Pm = compensated power transfer at the midpoint.

Es = Em = Vm, which is the mid point voltage andis held constant

Zm, qm and dm are midpoint parameters and

Zm = Z/2

qm = q /2

dm = d /2

\ PV

Zm

m2

= 2

sin2

sin 2

◊

◊◊q

d

= 2 sin 2max◊ ◊P d

Maximum power is doubled by a midpointcompensation and occurs at d = 180∞, as shown inFigure 24.16(b). Thus by changing the location of theline compensation the utilization capacity of the linecan be altered. For a midpoint compensation, the linecan operate stably up to d/2 or so, i.e. at about 90∞.

This is a costly and cumbersome solution, and may

be resorted to where series compensation at the farend may not be adequate to restore the desirable levelof line stability (particularly during light loads andload rejections). Such a situation may arise when theline length exceeds 300 km or so (Table 24.4). It is adifferent matter that such a situation will seldom arise.Power is rarely transported over very long distancesand through radial lines. A transmission line is normallysymmetrical, as its far end will generally be connectedto a power grid at less than 1000 km or so. However,if such a situation arises, sectioning would be one viablesolution.

• Reducing the electrical line length by reducing theproduct LC (Equation (24.8)).

LX

f =

2 L

p ◊

Cf X

= 12 Cp ◊ ◊

\ LCf

XX

= 12

L

Cp ◊

This product can be reduced by reducing XL, usingseries capacitance with a reactance ¢XC, which will

Es Er

Vm = Em = Es

l/2 l /2

Figure 24.16(a) Series compensation by sectioning at themidpoint of the line

Without compensation

Mid

-poi

ntco

mpe

nsat

ion

200

100

Stablepower

transfer

Pm

ax(%

)

0 45∞ 90∞ 180∞Load angle (d)

Figure 24.16(b) Rise in power transfer with mid-pointcompensation

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reduce XL to XL – ¢XC . This is where reactive controlplays a major role. By meticulous reactive powermanagement, the Ferranti effect can be controlled andthe electrical line length increased to the desired level.It is a different matter that the electrical length of theline cannot be raised infinitely, for reasons of stability,as discussed later.

To apply the corrective measures to limit the Ferrantieffect it is essential to first study its over-voltage (OV)status at the far end of the line. Consider the earliersystem TZ of 400 kV 50 Hz and draw a voltage profileas illustrated in Figure 24.17, for the voltages workedout as in Equation (24.7), at different lengths of theline. The voltages, for the sake of simplicity, are alsoshown in Table 24.4.

From the voltage profile it is evident that up to aline length of almost 250 km the over-voltage at thefar end is quite acceptable. For greater lengths thanthis, the far-end open-circuit voltage will rise beyondacceptable limits and may damage the line insulatorsand the terminal equipment. Moreover, during a linedisturbance or load variation this voltage fluctuationmay assume more dangerous swings. Generally, atransmission line is connected through a power gridwhere more than one supply source may be feedingthe system. When this is so, lines are called symmetricalas they are fed equally from both ends. The far endpoint shifts automatically to the middle of the line,diminishing the Ferranti effect, doubling the electrical

line length. (Figure 24.18.) In other words, such linescan automatically transmit power, within permissibleparameters, up to twice the length of a radial line,which is fed from only one end. In such cases, it isonly the midpoint voltage that is more relevant andmust be considered for the purpose of Ferranti effect.

In the first case, if we had considered a safe linelength of 250 km, this would become 500 km for asymmetrical line. Figure 24.18 illustrates such acondition. Depending upon the length and type ofline, a line length compensation may be required.Most transmission lines are seen to be withinpermissible lengths and only a few may require sucha compensation. Nevertheless, it may be worth reducingthe phase displacement between Er and Es to less than15∞ electrical, to further improve the quality andstability level of power transmission.

24.8 Optimizing power transferthrough reactive control

Reactive power pulsates up and down averaging to zeroand therefore contributes nil to power consumption. It canbe positive when being supplied or negative when beingreceived (consumed). Since the reactive power falls inquadrature with the active power, it is usually denoted as‘Q’ and the active power as ‘P’. Transmission anddistribution of reactive power reduces the active power.As P + JQ is pre-determined, any content of Q will onlyreduce P. Since reactive power is an inherent feature of ana.c. system it cannot be negated but its influence can beminimized by adopting to meticulous reactive powermanagement techniques as discussed below.

To transmit power over long distances is the basicrequisite of economical transmission. Let us study Equation(24.3). If we are able to maintain a unity p.f. between thetransmitting and receiving ends, then for a lossless line

Es = Er = Vo

Under such a condition, the line will maintain a unity

0 50 100 150 200 250 300 350 400

Line length in km

110

108

106

104

102

100

Er a

s %

of

Es

Figure 24.17 Voltage profile of a 400 kV/400 km radial lineon a no-load illustrating the Ferranti effect

0 50 100 150 200 250 300 350 400Line length in km

110

108

106

104

102

100

Er a

s %

of

Es

Figure 24.18 Voltage profile of a 400 kV/400 km symmetricalline on a no-load illustrating the Ferranti effect

Table 24.4 Far-end voltage, due to the Ferranti effect, in a400 kV TZ type line, at different line lengths

Line q from cos q VE

rs =

cos qkm Equation (24.6) in % of Es

and Table 24.2

100 5.985∞ 0.995 100.5200 11.97∞ 0.978 102.2250 14.96∞ 0.966 103.5300 17.955∞ 0.951 105.1400 23.94∞ 0.914 109.4

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p.f. at all points of the line and the reactive powergenerated, due to the distributed line charging capacitances(C1), will be offset by the reactive power absorbed bythe distributed line inductances (L1). The generator is nownot unduly stressed by the reactive power feedback, i.e.

VX

I Xo2

C1o2

L1 = ◊

where reactive power generated = V Xo2

C1/ per phaseper unit length and reactive power compensated (absorbed)= I Xo

2L1 ◊ per phase per unit length. Io is the capacitive

charging current

or VI

X Xo

oC1 L1 = ◊

= 12

2 1

1p p◊ ◊ ◊ ◊ ◊f C

f L

= = 1

11

LC

Z

(Z1 is termed the natural or surge impedance of the line SIL)The voltage will now maintain a flat profile from the

transmitting end through the receiving end and all theinsulators or terminal equipment would be equally stressed.

If Vo is considered as the nominal phase voltage ofthe system then Equation (24.3) can be rewritten as

PVZ

= sin sin

o2

1◊ d

q per phase (24.9)

The concept behind the above equation is that the voltagesand the currents, at the transmitting and receiving endsare maintained at the same p.f. The voltage at the receivingend, however, will shift in phase with respect to the

voltage at the transmitting end by an angle q, due to theFerranti effect and that effect is considered in the abovederivation. Refer to Figure 24.15 for more clarity. In theabove equation the element Vo

2/Z1 is an importantindicator of the power transfer capability of a line, and istermed the natural loading or surge impedance loading(Po) of the line, i.e.

PVZo

o2

1 = per phase (24.10)

Such a line is said to be naturally loaded and thisassumption is true only when the power is beingtransmitted at unity p.f. and there is a total balancing ofreactive powers. Since Z1 is constant for an uncompensatedline, so is Po, irrespective of its length. The magnitude ofthis will depend upon the line voltage, size of conductorsand the spacings between them and from the ground(these parameters decide C1 and L1 and hence Z1). It isalso an indicator of a normal loading capacity of a line.The recommended practice is to load an uncompensatedline to near this value or a little above when the line is alittle shorter, or a little less when the line is longer toretain the level of stability. Also refer to the load curvesin Figure 24.19 for more clarity.

To optimize this power transfer through reactive controllet us study Equation (24.10) for the parameters that canbe varied to achieve this objective. The active powertransfer will depend upon the following factors:

• Nominal voltage of transmission (Vo) is a policy decisionof a country, depending upon the likely power loadingof such lines and future power plans. Generally, thelevels of voltage, Vr, for primary and secondarytransmissions are gradually increasing to cope withgrowing power demands. A typical system of transmissionand distribution is illustrated in Figure 23.1.

1 2 3

1

2

3

1.0

0.5

0

Vr/

Es

1.0

(P /P0)

Uncompensated

Partially compensated

Fully compensated

Natural load

Figure 24.19 Capacity utilization load curves with and without compensation

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• Load to be transferred, keeping suitable margins fora future increase in demand.

• Likely expected load variations and p.f. of the load(which may be based on experience).

• Line length effect or Ferranti effect, sin q, that willdetermine the optimum line length which will alsodepend upon whether it is a radial or a symmetricalline.

• Surge impedance of the line, Z1.• Angle of transmission, d.

Equation (24.3) defines the active power as independentof p.f. However, depending upon the p.f. of the load, thiswill adjust the load angle d. The larger the angle oftransmission, the higher will be the power transfer. Figure24.20 illustrates the power transfer characteristics of a250 km line selected from Table 24.5.

Rewriting equation (24.9),

PP

= sin

sin oq d◊ (24.11)

For the system to remain stable under all conditions ofloading, switching, or any other line disturbances it isessential that an uncompensated line is loaded at muchbelow this level. Otherwise disturbances of a minor naturemay result in undamped oscillations, and may even swingthe receiving-end voltage beyond acceptable limits. Itmay even cause an outage of the system. It is thereforenot practicable to operate an uncompensated line to itsoptimum level. For this we will analyse this equation forsin q and sin d as follows.

24.8.1 Line length effect (sin qqqqq )

The element Po /sin q can be considered as the steadystatestability limit of the line, say Pmax. A line lengthcompensation can improve the voltage profile and hencethe power transfer capability of the line as follows.

Figure 24.19 illustrates three power transfer or loadcurves:

Curve 1: without any compensation, the voltage profilesags on small load variations and is not capable oftransferring even a natural load.Curve 2: with partial compensation, the voltage profileimproves and the line is able to transfer more load thanabove, but less than its natural loading. Voltage still sagsbut the swing is more tolerable.Curve 3: The line is fully compensated. The voltageprofile tends to be flat and the line is capable of transferringeven more than the natural load without an appreciablesag in the voltage profile.

24.8.2 Influence of load angle (sin ddddd )

A study of various systems has revealed that the loadangle for an uncompensated line should be maintainedat about 30∞ only. This means that an uncompensatedline may be loaded to just nearly half its steady-statelevel to retain a high level of stability during loadfluctuations, particularly during light loads or loadrejections, switching of large inductive loads or any typeof minor or major line fault.

When the line is compensated, and a near-flat voltageprofile can be ensured so that during all such disturbancesthe receiving-end voltage will stay within permissiblelimits, the load angle can be raised to 45–60∞ to achievea high power transfer.

Of all the above parameters, system voltage is alreadypredefined and considering that it cannot be changed,the only parameters that can be altered to optimize P areZ1 and q. Both parameters can be altered to any desiredlimit with the application of reactive power controls,subject to

• The thermal capacity of the line conductors and• Retaining the stability limit of the system thus

modified.

After we have assessed the optimum power level it

1 2 3

1

2

3

4

3.87

3.35

3

2.74

0

21.935

1

P/ P

0

15 30 45 60 75 90 120 150 180Load angle (d)

p radians

P /P0, considered for a 250 km radial line length as per Table 24.5.

d P /P0 Stability level

0 0

15 1.000

30 1.935

45 2.740

60 3.350

75 3.740

90 3.870

Stable region

Stable when series compensated

Not so stable on severe linedisturbances, even after aseries compensation

3.74

Figure 24.20 Variation in load transfer with change in transmissionangle d

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becomes easy to decide the type and amount of reactivepower control required to achieve this level, assumingthat the lines can be loaded up to their thermal capacityand the optimum power derived above can be attained.

Our main objective will now be to arrive at the stabilitylevel of the system and the parameters that define this.As noted above, the stability level defines the maximumpower that can be transferred through a line withoutcausing a voltage fluctuation and angular differencebeyond acceptable limits, or a consequent outage of theline, during a load variation, or a temporary linedisturbance. It should, in fact, maintain its continuityeven during a fast clearing of a major fault. To determinethe effects of Z1 and q on the receiving-end voltage andconsequently the transfer of power, P, within stable limitswe will study the voltage equation of a losslesstransmission line (considering R1 = 0, for an easyillustration), feeding a load P at a p.f. cos f.

1 Radial lines

The transmitting-end voltage in terms of line parameterscan be represented by

Es = Vr cos qr + JZ1 · I1 · sin qr (24.12)

whereEs = phase voltage at the transmitting-endVr = phase voltage at the receiving-endqr = line length effect or Ferranti effect at the end of the

line, in degrees I� = load current

= –

r

P JQV

P = active loadQ = reactive load

R1 = line resistance per phase. It has been ignored andthe line is considered lossless

Z1 = surge impedance of the line

The voltage stability of a system is the measure ofvoltage fluctuations which must remain within permissiblelimits during load fluctuation or rejection or other linedisturbances and even temporary faults. We may thereforesolve the above equation for Vr and P, to study thebehaviour of the system under varying load conditions,P. As there are two more variables, load p.f. and the linelength, which will influence P and Vr, different sets ofload curves can be drawn as illustrated in Figure 24.21,for different line lengths at different p.fs. (at near unity,to obtain the best performance). From a study of thesecurves one can identify the most appropriate line lengthswhich can extend the highest level of stability to thesystem. For example, set ‘a’ of curves are moreideal compared to set ‘b’, which correspond to verylong line lengths, compared to the ideal line lengths ofset ‘a’.

After identifying the likely line lengths we can thenstudy the most appropriate p.f. at which the load must betransmitted to maintain the highest level of stability. Forour purpose, parts of the curves that lie near the ratedvoltage, say, within Vr ± 5%, alone are relevant for study.The line will perform best at p.fs. very near to unity andcause the least possible voltage fluctuations by maintaininga near-flat voltage profile over reasonable variations ofload. Leading p.fs. are not considered for reasons ofcapacitive overvoltages.

Open end voltagehigh to very high,out of stable limits

Open end voltagewithin permissible

limits 1.0

V Er s

PP0

PP0

– Diminishes (referring to onlyoperating region) and linesoperate underutilized.

Po1.0

Leading p.f.

Unity p.f.

Lagging p.f.

Ideal line lengthaccording toline parameters(Set ‘a ’ curves)

Non-operatingregion

Operatingregion

Line lengthmuch longerthan ideal(Set ‘b ’ curves)

Lagging p.f.

Unity p.f.

Leading p.f.

Natural load

Figure 24.21 A comparative study of load transfers for different line lengths at different p.fs. for an uncompensated line

Po

Pmax

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InferenceThe voltage stability level diminishes with an increasein the line length. For very long line lengths, the far-endvoltage may swing from high to very high values duringload variations, rendering it unsuitable for operation nearthe maximum load transfer level. During light loads toothe steeply rising voltage profile may cause a high-voltageswing on a small load variation. A load variation thereforewill cause wide to very wide voltage fluctuations andrender the system unsuitable rather than unstable for apower transfer near the required level. For transfer of aload under stable conditions the line lengths of theuncompensated lines will be too short and hence will notbe economically viable. We will seek a solution to theseproblems with the help of these curves which will providean introduction to the utility of reactive power controlsto improve the power transmission capacity of a line andits quality through the following discussion.

Influence of PF

• The power transfer capability of the line rises as thep.f. swings towards the leading region and diminishesas it swings towards the lagging region. Since a powersupply system is not run at leading p.fs. for reasonsof dangerous over-voltages that may develop (as aresult of overexcitation of the capacitors, Section 23.13)across the terminal equipment it is advisable to runthe system as close to unity p.f. as possible. Moreover,the field system of the generating machines is alsodesigned for maximum operation at lagging p.fs. only,as discussed in Section 16.4. At leading p.fs. (after acertain limit) (see Figure 24.9) there is a possibilityof its field system losing control and becomingineffective.

• The receiving-end voltage rises with leading p.fs. anddroops with lagging. This is illustrated with the helpof phasor diagrams (Figures 24.22(a) and (b)).

• At unity p.f. the voltage variation and hence theregulation is the least and maintains a near-flat voltageprofile. This is the best condition to provide the highestlevel of system stability from a voltage point of view.

The power factor can be improved with the use ofshunt capacitors at the load points or at the receiving endas discussed in Chapter 23. It is not practical to have anear-fixed loading for all hours of the day. Moreover, theremay also be seasonal loads which may upset the parametersconsidered while installing the capacitor banks. Such asituation is overcome by readjusting the reactive needsof the line by providing switched capacitor banks a fewof which can be switched-in or switched-out, dependingupon the load demand. The switching may be automaticwith the help of a p.f. correction relay (Section 23.15).

Influence of line length (Ferranti effect)For each p.f. and line length the curve Vr versus P describesa certain trajectory. Maximum power can be transferredonly within these trajectories. Each line length has atheoretical optimum level of power transfer, Pmax, whichis defined by Po /sinq. In Table 24.5 we have worked outthese levels for different line lengths, for the systemconsidered in Example 24.1.

A line can be theoretically loaded up to these levels.But at these levels, during a load variation, the far-endvoltage may swing far beyond the desirable limits of Vr± 5% and the system may not remain stable. With theuse of reactive control it is possible to transfer power atthe optimum level (Pmax) and yet maintain the far-end(or midpoint in symmetrical lines) voltage near to Vr andhave a near-flat voltage profile.

Reactive control can alter the line length ( )µ LCto the level at which the system will have the least possibleswings. It is evident from the curves of Figure 24.21 thatan uncompensated line of a much shorter length may notbe able, to transfer even its natural load (Po) successfully.This is due to the steeply drooping characteristics of thevoltage profile at about this load point, which may subjectthe system to a much higher voltage swing than is desirableon small fluctuation of loads.

To decide on the best reactive control for an existingtransmission line one should choose the most appropriateelectrical line length that can transmit the optimum powerfrom the load characteristics drawn in Figure 24.21. Thencompensate the line with suitable reactive controls toobtain the required line length. For instance for the 400kV, 50 Hz system considered, we can choose a radialline with an electrical line length of 200–250 km andthen compensate the existing line according to 200–250km system to achieve the desired line length. Thecompensation is provided so that the Pmax point, whichlies far from the natural power transmission point Po,shifts within a stable region, i.e. near the Po region. Thenfrom equation (24.8),

q µ ◊ ◊L C �

Say, for an actual line length of 800 km (symmetrical),

q 400 1 1 400µ ¢ ◊ ¢ ¥L C (q400 = midpoint Ferranti effect)

which must be improved for, say, a 250 km radial line

i.e. q 250 1 1 250µ ◊ ¥L C

for q400 to be almost equal to q250 ,

I

f

Es

I · Xc

VrVr > Es (I · R ignored)

(a) Receiving-end voltage rises with leading p.fs.

f Vr

I · XL

Es

I

Vr < Es (I · R ignored)

(b) Receiving-end voltage diminishes with lagging p.fs.

Figure 24.22

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¢ ◊ ¢ ¥ ◊ ¥L C L C1 1 1 1 400 = 250

or ¢ ¢ ÊË

ˆ¯ ◊ ◊L C L C1 1

2

1 1 = 250400

or¢¢

ÊË

ˆ¯

XX

XX

L1

C1

2L1

C1 =

250400

Since a shunt capacitive compensation will reduceXC (µ 1/c), it will not provide the desired compensation.This can be achieved with the use of series compensation,C1 remaining the same. Then

¢ ÊË

ˆ¯ ◊X XL1

2

L1 = 250400

= 0.39 · XL1\ Compensation required = 0.61 XL1 per unit length.Series capacitors making up 0.61 XL1·l may be introducedinto the system to achieve the desired electrical line length.

Influence of surge impedance (Z1)

Since PZo

1 1µ

Z1 plays a very significant role in the power transfercapability of a line. By reducing the value of Z1, thepower transfer capability of a system can be increased.Since

ZLC1

1

1=

and in absolute terms = L1 C1X X◊

or = L CX X◊

This value can be reduced by decreasing the value of XL,which is possible by providing series capacitors in theline. If XCC is the series compensation, then the modifiedimpedance

¢ ◊Z X X X1 L CC C = ( ) –

and hence any value of power transfer can be achievedup to the theoretical Pmax (Table 24.5). But for reasonsof other parameters that may also influence the stability

of the system, it is not practical to achieve the optimumcapacity utilization of the line without sacrificing thelevel of stability, even when the required degree ofcompensation is provided. Parameters that may influencethe stability can be one or more of the following:

1 A small value of (XL – XCC), i.e. XCC approaching XL,will have more chance of a sub-synchronous resonance(SSR) with the rotating machines and a ferro-resonancewith the transformers during a switching sequence orline disturbance.

2 Higher harmonic contents may magnify the harmoniccurrents and affect the loading capacity of the line.

3 A very close compensation, i.e. a low XL – XCC, mayalso raise the fault level of the system beyond desirablelimits.

To overcome such situations within acceptableparameters during normal operation, it has been foundthat an ideal series compensation for combined ‘electricalline length’ and ‘surge impedance’ is achieved at around40–70% of XL, preferably in the range of 45–60% only.The level of compensation will depend upon the expectedload fluctuations and the presence of harmonic disordersin the system.

Example 24.2Consider the 400 kV, 50 Hz system and apply the abovetheory. If the system has relatively fewer load fluctuationsand the loads are reasonably linear, then we can consider ahigher compensation to the extent of, say 75% of XL. Then

PVZo

r2

1 = and

PVZmaxr2

1 =

¢

or P PZZ

PX X

X X XC

max o1

1o

L

L L C = =

( – 0.75 )

¥¢

◊◊ ¢

Since there is no change in the line charging capacitance( = ),C C¢X X

\ P P Pmax o o = 10.25

= 2 ¥

While it is possible that Pmax may be further raised by a stillcloser compensation, this is not advisable to retain the stabilitylevel of the system. The above compensation is higher thanthe line length compensation considered earlier and will further

Table 24.5 Level of Pmax for a 400 kV, 50 Hz, TZ system

Line length q from Equation (24.6) sin q PPmax

o = 1

sin qVr /Es = 1

cos q %

Radial line Symmetrical linekm km

100 200 5.985∞ 0.104 9.61 100.5200 400 11.97∞ 0.207 4.83 102.2250 500 14.96∞ 0.258 3.87 103.5

300 600 17.955∞ 0.308 3.25 105.1400 800 23.94∞ 0.406 2.46 109.4

Note:Normal practice is to design a system to carry at least its natural load, Po, under stable conditions.

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improve the electrical line length. Choose a combined seriescompensation of the order of 60–75% of XL, preferably around65% for better stability.

Adding shunt capacitors would also reduce Z1 but wouldraise the electrical line length; hence it is not considered.Moreover, on EHVs, the charging shunt capacitances, C1, assuch require compensation during light loads or load rejectionsto limit the voltage rise (regulation) at the far end or themidpoint. Hence no additional shunt compensation isrecommended.

NoteSeries compensation would mean a low value of Z1 andhence a higher system fault level. This need be kept in mindwhile designing the system and selecting the switching devicesor deciding on the protective scheme or its fault setting.

2 Symmetrical lines

Equation (24.12) is now modified to

Es = Vm · cos qm + JZ1 · I1 · sin qm (24.13)

whereVm = voltage at the midpoint of the line (Figure 24.18)qm = line length or Ferranti effect up to the midpoint of

the line.

The rest of the procedure, even the inferences drawnabove, would remain the same as for a radial line. Theonly difference now is that the system would becomesuitable for twice the lengths of the radial lines as aresult of the midpoint effect which doubles the line length.

Conclusion

A compensated line can transmit much more power thanits natural loading within stable limits and hence fulfilthe requirement of economical power transfer. The abovewas a theoretical analysis which can provide quite accurateresults, depending upon the accuracy of the data assumed.The more scientific procedure to conduct this type ofstudy, however, would be through a load flow analysisof the steady-state component to study temporary over-voltages and transient analysis through a TNA (transientnetwork analyser) or an EMTP (electromagnetic transient

programme). TNA is an analogue method while EMTPis a digital method of system analysis. For details ofsystem models and procedure to study a system, refer toMiller (1982).

A transmission line may have to operate under differentconditions of loading (I� and p.f.) at different hours ofthe day, and then there may also be seasonal loads. Thetype of reactive compensation therefore must be decidedfor the varying load conditions, so that they are able toprovide a continuous change in the VAr as demanded. Itis normal practice to have a combination of series andshunt reactive compensations to suit all conditions ofloading, some fixed (unswitched) compensators for normalload conditions and the remainder variable, to switchON or OFF depending upon the load conditions or loadfluctuations. The choice of different types of reactivecompensators may be considered on the following basis:

1 Shunt reactors These are provided as shown in Figure24.23 to compensate for the distributed lumpedcapacitances, C1, on EHV networks and also to limittemporary over-voltages caused during a load rejection,followed by a ground fault or a phase fault within theprescribed steady-state voltage limits, as noted in Table24.3. They absorb reactive power to offset the chargingpower demand of EHV lines (Table 24.2, column 9).The selection of a reactor can be made on the basis ofthe duty it has to perform and the compensation required.Some of the different types of reactors and theircharacteristics are described in Chapter 27.

Reactors add to Z Z X X1 1 L1 C1( = )◊ and hencereduce surge impedance loading (SIL), Po. Most arethe fixed type, depending upon the maximum loadconditions, and the remainder are switched. Theswitchable reactors are switched only during atemporary disturbance, therefore they have no adverseeffect on Po. Ideally they can be made fixed tocompensate 50–60% of C1 and the remainder switchedin a few steps. The size and number of steps willdepend upon the likely under-loading, open-circuitingduring offpeak periods or other temporary disturbances.The over-voltages that may occur under such

G

TransformerL1 L1 L1 L1

SCR C1 C1 C1 C1SCR SCR C1

GIntermediatory

switching station

SCR – Shunt compensating reactor

Vr

G

Figure 24.23 A shunt compensated transmission line

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conditions, and which must be controlled through thesereactors, is a matter of system design practice adoptedby a country or its central power authorities and maybe broadly based on our discussions in Section 24.6and Table 24.3. To determine more accurate over-voltage conditions, however, a TNA or EMTP studywould be better for an existing system and earlierdata and experience for a new system.

NoteOn 132 kV networks the MVAr loading is light, as most of thep.f. is controlled at the distribution level and the capacitivecharging MVAr demand is low (Table 24.2, column 9). Thecharging MVAr is normally not compensated because, on load,more than this is offset by the load p.f.

2 Shunt capacitors They are used generally for p.f.improvement of the system. They reduce Z1 andenhance SIL, Po, and boost the line voltage. They arenormally switched and not permanently connectedto avoid resonance on load rejection or an open circuit.Generally they are used for systems up to 33 kV, i.e.at the distribution end. But when the p.f. is not fullycompensated at the distribution end it can becompensated at the secondary transmission level of66 kV or 132 kV also. Capacitors at such voltagesmay be connected through dedicated transformers,as illustrated in Figure 24.24.

NoteOn 66 kV networks the MVAr loading is normally high andtherefore one practice is to instal MVAr meters and adopt amanual switching during variation of MVAr beyond thepermissible level, purely as a cost consideration.

3 Series capacitors These are used for line lengthcompensation to help transmit power over longdistances and also improve the stability level of thenetwork. They are usually installed at the line endsor at the selected locations. They reduce Z1 and

enhance SIL, Po, and electrical line length, and boostthe receiving-end voltage as discussed in Section 24.8.

Example 24.3 Application of series compensation onan HV distribution network

Let us consider the primary distribution network of Example23.2 as shown in Figure 24.25(a) feeding an LV load of 30MVAat 0.98 p.f. through a 33/0.4 kV transformer. The followingline parameters have been considered:

Resistance of primary distribution overhead lines, SectionB–B at the operating temperature,

R1 = 0.13 W/km per phase

Inductive reactance of this section at 50 Hz

XL1 = 0.4 W/km per phase

There is no leakage capacitance, C1, and hence no Ferrantieffect on such low voltages. We will use series compensationto reduce the line voltage drop and improve the regulationand hence the stability of the network as well as its loadtransfer capability,

Load p.f. = 0.98 (– -11.48∞)

In Example 23.2 the system was not capable of transmittingits full capacity. Let us consider that with the use of seriescompensation it can be fully loaded up to

30 MVA ¥ 0.98 = 29.4 MW.

The impedance of the transformer

Zz V

= 100

kVA 10

p r2

3¥

¥(from Equation (13.3))

= 10100

33 1030 10

2 6

6¥ ¥

¥

= 3.63 W

For ease of calculation, let us consider the impedance ofthe transformer as its leakage reactance, ignoring resistanceand draw an equivalent circuit diagram as in Figures 24.25(b)and (c). Assuming the length of the primary distribution lineto be 15 km, the total line parameters will become

XL = 3.63 + 15 ¥ 0.4 + 3.63

= 13.26 W

and R = 0.13 ¥ 15

= 1.95 W

Receiving-end voltage before series compensation

To study the voltage fluctuation at the receiving-end withfluctuations of loads, let us do so in terms of variation inthe transmitting-end voltage, assuming the receiving-endvoltage remains constant at 33 kV. We are doing this forease of calculation and for drawing the phasor diagram,Figure 24.26. To study the impact of series compensationwe consider the full-rated current of the transformer andthe line for optimum utilization of the entire system.

E I Zs 1–3 = 33

3 + 10 in kV◊ ◊

= 19.05 + 5251000

– 11.48 (1.95 + J 13.26)– ∞ÊË

ˆ¯ ¥

66 or 132 kV line

Dedicatedtransformer

Switchingdevice

Capacitorbanks

G

Figure 24.24 Use of dedicated transformer to connectcapacitors on networks 66 kV and above

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11/400 kV LV

HV

Primarytransmission

400/132 kVLV

HV

Secondarytransmission

Primarydistribution

SectionB–B under

consideration

132/33 kV

LV

HVB

B

Secondarydistribution

30 MVA

(a) Typical primary distribution network

33/0.4 kVLV

HV

G

1 2 3 4 5

1

2

3

4

5

Figure 24.25 Determining the value of series capacitors for a primary distribution network

B

HV

LV

30 MVA,132/33 kVzp = 10%

R = 1.95 W

XL = 6 W

XC

HV

LV

30 MVA,33/0.4 kVzp = 10%

Shuntcapacitors

B

LV loads = 30 MVA at 0.98 p.f.

(b) Details of Section B–B

B B

3.63 W 6.0 W 3.63 W

Leakage reactance of transmitter-end transformer.

Resistance of overhead lines of Section B–B.

Inductive reactance of overhead lines of Section B–B.

Capacitive reactance of series capacitors.

Leakage reactance of receiving-end transformer.

(c) Equivalent circuit of Section B–B

1.95 W XC

= 19.05 + 0.525 ¥ 1.95 – – 11.48∞ + 0.525

¥ 13.26 – (90 – 11.48∞)

= 19.05 + 1.024[cos (–11.48∞) + J sin (–11.48∞)]

+ 6.96 (cos 78.52∞ + J sin 78.52∞)

= 19.05 + 1.024(0.98 – J 0.199) + 6.96(0.199 + J 0.98)

= 19.05 + 1.00 – J 0.20 + 1.38 + J 6.82

= 21.43 + J 6.62

= 22.43 tan 6.6221.43

–1

= 22.43 –17.16∞ (Figure 24.26)

\ Voltage drop = 22.43 – 19.05

= 3.38 kV

or 15.07% of Es

It is difficult to operate such a system on full load. Itis bound to have wide voltage and load fluctuations,more so on a line disturbance. Such a system may haveto be operated well below its rated capacity to retain itsstability, even when the voltages on the primary and thesecondary transformers are adjusted so that the requiredrated voltage is available at the receiving-end. A voltageswing of 15% between a full load to a load rejectioncondition is too wide and may lead to outage of the

Seriescapacitors

6.96 kV

Es = 22.43 kV

1.024 kVVr = 19.05 kV

17.16∞

11.48∞525 A

Figure 24.26 Receiving-end voltage after shunt compensation

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system on a line disturbance. Since there is no furtherscope to improve the above situation with the help ofshunt capacitors (the p.f. is already at 0.98), let us do sowith the help of series compensation. Since the far-endp.f. is being maintained at a high level, the system canachieve some stability. A series compensation to the extentof, say 60% of the total line impedance should not beexcessive, as the line already has some series resistance.Moreover, the transformers will have some resistancetoo which has been ignored in the above analysis andhence the chances of a sub-synchronous or ferro-resonanceoccurring will be remote.

\ Series compensation = 0.6 (1.95 + J 13.26)

= 8.04 W (in absolute terms)

Say, XC = 8 W

and size of series capacitors,

= 525 8

1000

2 ¥

= 2205 kVAr per phase

For 10% load variation, to be on the safe side, thecapacitors must be rated for:

= (1.1)2 ¥ 2205

= 2668 kVAr

and voltage across the capacitors,

VC = I� · XC

= 525 ¥ 1.1 ¥ 8

= 4.62 kV

If we consider three units in series and nine in parallel(Figure 24.27(a)) then the size of each unit

= 26683 9

= 98.8¥ say, 100 kVAr

and the voltage rating of each unit

= 4.623

= 1.54 kV

The improved line impedance

= 1.95 + J 13.26 – J 8.0

= 1.95 + J 5.26

and the improved transmitting-end voltage, the loadremaining same;

Es = 19.05 + (0.525 – – 11.48∞) (1.95 + J 5.26)

= 19.05 + 1.024 (0.98 – J 0.199) + 2.761 (0.199 +J 0.98)

= 19.05 + 1.00 – J 0.02 + 0.55 + J 2.71

= 20.6 + J 2.51

= 20.75 tan 2.5120.6

–1

= 20.75 – 6.95∞

\ voltage drop = 20.75 – 19.05 = 1.7 kV or 8.2% of Es

This is also the regulation of the system. See the phasorrepresentation shown in Figure 24.27(b).

Inferences1 Raising the compensation from 60% to, say, 70%

may further improve the above situation but this maynot be advisable to maintain a high level of stabilityduring line disturbances. Moreover, the p.f. of thesystem has already reached a high of cos 6.95∞, i.e.0.99, which also is not advisable. To be safer, thelevel of shunt compensation should be slightly reduced.

NoteSince the load variation on an HV distribution network will beonly nominal, and the network will also have enough resistance,

132/33 kV

Z = 3.63 W 0.975 W 3 W

* 27 Nos. 100 kVAr eachN1 (Series group) = 3N2 (Parallel group) = 9

4.62 kV

2700 kVArper phase

N2

3 W 0.975 W

Shunt capacitors2240 kVAr per

phase(for arrangement

refer to Figure23.18b)

33/0.4 kVLoad 29.4 MVA

at 0.98 p.f.Z = 3.63 W

Note

(1) The capacitors are shown in the centre ofthe line which being the best location. Butthey can be provided near the receiving-end transformer also.

(2) They are to be mounted on platforms,insulated for 19.05 kV from the ground.

(3) The normal practice is to mount eachphase units on separate platforms,insulated for 33 kV from each other.

N1

*

Figure 24.27(a) Application of series compensation on an HV distribution network

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it should be possible to compensate the system up to 70% or so,to further improve the regulation of the network, say up to 5%of Es, without jeopardizing the level of stability. The applicationengineer can take a more judicious decision, knowing thecondition of the network to be compensated.

2 The voltage variation with the series compensation,although high, at about 8.2%, is still manageable byadjusting the tappings on the transmitting-endtransformer, for which a transformer with highertappings may be selected or a transformer with a highersecondary voltage may be chosen, say, at 36 kV or so.For minor adjustments, the tappings on the receiving-end transformer may be used. With this, the abovesystem can be utilized to its optimum capacity.

3 The phasor displacement between the transmittingand the receiving ends, with the use of seriescompensation, is reduced and the receiving-end voltagehas moved closer to the transmitting-end voltage, whichwill provide more stability to the system during a linedisturbance.

4 Even a higher cross-section of line conductors wouldbe able to improve the above situation by reducingthe line resistance and hence the voltage drop.

5 It will be pertinent to note that series compensationon HV lines will be more effective when the lineinductive reactance itself is high, as when the line isindividually feeding highly inductive loads, such asan induction or an arc furnace or other similar loads.Nevertheless, it can also be effectively applied onover-loaded distribution networks similar to the onewe have considered above, to raise the line capacityand reduce the voltage dip at the receiving end.

6 For large concentrations of loads, such as for an industrialor a residential area and where addition of more loadsin future is likely, forecasts of a realistic loading oflines may fail. Therefore, for growing cities particularly,it is advisable to instal initially a slightly larger primarydistribution network to cater for the increasing powerneeds. It is felt that for such load centres, an 11 kV oreven 33 kV distribution is inadequate. Thecommensurate primary distribution for such locationsmay be considered at 66 kV, and in residential andindustrial areas or public places underground cablingshould be adopted to minimize the risk of running such

high tension lines in the open and also save the scarceland area. Underground cabling is more expensive thanan overhead system, but is more safe in congested areas.The use of an overhead or underground system willdepend upon the location, safety and convenience,besides consideration of cost. See Lakervi and Holmesin the Further Reading for more details.

NoteCountries like the USA and Japan have adopted undergroundcabling for transmission of power up to 1000 MW at 550 kV.

7 To provide reactive support for any power system ornetwork, suffering from voltage fluctuations or highline losses or when it is felt that the system cannottransfer the required load it is important to carry outa field study first, to identify areas and suitable locationswhere reactive support would be more appropriate. Aprocedure along the lines of Example 24.3 to determinethe amount and type of reactive support should thenbe adopted.

Above we have dealt primarily with the technicalaspects of reactive controls. For commercial implications,see Lakervi and Holmes.

24.9 Dynamic and transient stabilityof overhead lines (Applicationsof reactive controls)

A. Dynamic stabilityThe dynamic stability of a power system defines whetherit can restore normal operation following a majordisturbance, such as on

• The outage or failure of a generating unit• Failure of the overhead line or a transformer and• Abrupt change of load like, sudden opening of the

line or switching of large loads causing severe powerfluctuations.

The highest level of power it can transmit during suchdisturbances without disturbing its synchronism is itsdynamic stability limit. It is also a function of momentof inertia of the rotating masses of the generating source,prime-mover and the generator (see function of a flywheelSection 3.9). Higher the inertia longer the period thesystem can sustain the line disturbances noted above andkeep the system in tandem. But no extra rotating massesare usually added to supplement the stability level of thesystem in view of already large rotating masses on thesystem.

Damping the power oscillations on such disturbancesand restoring the power system to stable limits are themain objectives of reactive control. From the load curvesone can observe that an uncompensated line may havedangerous power swings on small fluctuations of load,which may lead to loss of synchronism between twogenerators and even cause an outage of the line. To keepthis system stable during such disturbances, it must beoperated at much below its steady-state stability level.

Consider a typical case during a line disturbance when

525 AVr = 19.05 kV

17.16∞

11.48∞6.95∞

6.96 kV

Es = 22.43 kV

1.024 kV

2.761 kV

*

* Series compensation

NoteIn fact Es is the fixed phasor and Vr the variable. But for ease ofdrawing, we have considered Vr as the base phasor.

Es = 20.75 kV

Figure 24.27(b) Receiving-end voltage after shunt and seriescompensations

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the line is not adequately compensated. A transmissionnetwork is being fed by more than one generator. Whena line disturbance occurs say due to abrupt loading thecurrent flow to the excessive load will be shared moreby the machine nearest to the load point and less by theone installed a little away due to difference in lineimpedances up to the load point. This will upset theearlier tandem operation of the machines and they willbecome unequally loaded and may fall out of step. Theone near the point of disturbance will slow down morethan the other. The machine that shares the smaller amountof the load will slow down less and feed more, becomingoverstressed. Now it will slow down and the other willpick-up. The situation will reverse thus and so the situationwill continue creating a hunting effect. The followingmay result depending upon the dynamic stability limit ofthe system.

• In a reasonably stable system the situation is controlledpromptly and the normal condition is restored. Thesetting and the speed of the protective relays shouldbe commensurate with such a situation to restore thenormal condition as quickly as possible,

• If not, the machine being loaded most may fall out,which may not necessarily be the one nearer the fault,or

• The situation may have a cascading effect until allthe machines fall out, resulting in a total blackout.

To achieve a better level of dynamic stability it isdesirable that the line be loaded a little less than theoptimum power it is capable of transmitting to sustainthe system disturbances without an outage. The load curves(Figure 24.19) provide a guide to determine the level atwhich the line should be operated and from this can beassessed the magnitude of disturbances that the line cansafely sustain and recover promptly without an outage.Series reactive support can provide a restoring force tosustain such disturbances and become essential, wheneverthe line loading is expected to be more than the SIL (Po)(generally on 132 and 220 kV networks).

Series reactive support has been found extremely usefulon existing lines even up to 11 kV, which are required tocater for higher power demands than were originallyenvisaged (see Example 24.3).

B. Transient stabilityA transient stability limit refers to the maximum powerthat the system (all the generators feeding the network)can deliver on a transient fault without loss of synchronism.Such transient faults are caused due to system disturbancesas discussed in Section 17.3 and summarized below,

Single phase faults– due to passing objects like birds, gales and storms

hitting the overhead lines– due to arcing grounds or arcing insulators– lightning strikes (not switching surges which

necessarily is a three phase fault)– system harmonics and over-voltages also enhance the

electrostatic flashovers– arcing faults may also occur without actually there

being a fault due to electrostatic discharges at the

insulators which may occur because of humidity orduring rainy season. Dirt, dust and soot deposited onthe insulators providing the tracking path

NoteThe arc occurring before the breaker can be termed as primary arc andthat occurring during the interruption of the breaker as secondary arc.

In most cases, such disturbances are of a momentarynature. Field studies have revealed that such causescontribute nearly 90% of the total trippings. During suchfaults, the interrupters at both ends of the transmissionline may trip as a result of travelling waves in bothdirections because of flashover at the insulators and theirdischarging through the ground. It becomes a case ofground fault. Switching surges may also raise the potentialof the overhead lines and cause similar arcing insulators.

Three phase faults– two phase or three phase short-circuits or ground faults

and– switching surges.

24.9.1 Auto-reclosure schemes

Auto-reclosing on a power system, normally for overheadlines, after a transient fault is a type of protective closing andnetwork automation to avoid a supply interruption on suchfaults and to improve system’s transient stability limit.

It may be applied to an overhead transmission or a longHV distribution system to reclose the interrupters onsuch a trip and maintain the continuity of the supplysystem, preventing loss of synchronism and helping toachieve a high level system stability. We discuss belowthese schemes for single and three phase faults.

– Single phase faults – Since such faults are of transientnature, the scheme may be applied even on a per-polebasis, allowing the healthy phases to remain intactand the reclosing necessitated only in the affectedphase to further enhance the system’s transient stability.Now it would require an independent interruptingmechanism and individual relaying and tripping schemefor each pole which is a costly affair but desirable.The reclosing sequence will initiate as described belowfor a 50 Hz system (illustrated just for the sake ofclarity). To be on the safe side the total duration offault may be considered about 20 cycles. This is knownas rapid reclosing scheme and is almost the minimumpossible time to reclose after a fault, when the breakersmay successfully close and hold.

It is possible that the breakers may trip on the firstreclosing, as the fault may not have cleared by then,because the other two healthy phases may also befeeding the fault through electrostatic (leakage)capacitances and prolonging the de-ionisation of theinsulators’ arc or the arcing grounds. In single poletripping a delayed reclosing can still be adopted byshifting the timer to a delayed mode permitting anothertime gap of about 500 ms (25 cycles) after the first trip.Therefore in delayed reclosing the total closing timefrom the initiation of fault up to the second reclosingcan be up to 1.12 second or so as noted below,

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Second reclosing

� 400 ms (20 cycles) + 500 ms (25 cycles) + 40 ms(2 cycles) + 40–80 ms (2–4 cycles) + 80–100 ms(4–5 cycles) (second reclosing)

� 1060–1120 (53–56 cycles)

i.e. up to 1.12 second or so

The delayed reclosing supplements the fast reclosingto still save the system from a swing and a consequenttrip. By then the fault would clear in all probability toallow the breakers to reclose and hold, thus maintainingthe continuity of supply once again, saving the systemfrom falling out of synchronism and a tandem trip ofall the feeding lines of a power grid. If the fault persistsand the breakers trip again, the breakers will lock-out, tripping the other two phases as well, and willnot close again until the fault is removed and thebreakers are reset.

Delayed reclosing may be adopted where the systemhas large inter-connections (mesh system) as at a powergrid, and where loss of one phase may not cause aloss of synchronism in such a duration and hencerestore the transient stability of the whole system.When the network is not very complex and may beinter-connecting only a few transmission lines, somepower handling agencies may adopt to only singleclosing permitting a higher dead time of about 1 secto account for contingencies and delays in fault clearing(total fault duration 1.16–1.22 sec). It is possible thatthe breakers may trip now also. If so, they will lock-out tripping the other two phases also.

It is possible that the breakers may hold but tripagain within a few seconds. If this occurs within 25sec or so (reclaim time) the breakers will not recloseand will be locked-out tripping the other phases aswell. If tripping occurs after 25 sec or so, it will beconsidered a fresh fault and the same reclosingsequence will repeat as after the first tripping and soon.

– Three phase faults – These faults may lead to two orthree phase trippings hence more severe. To maintainstability the system must be restored within 200–300ms (10–15 cycles) after the tripping of the breaker,permitting a total fault time as

� (200–300) ms + (40) ms + (40–80) ms + (80–100) ms

� 360–520 ms or 18–26 cycles

Delayed reclosing may be possible now also dependingupon the system parameters, permitting a dead timeup to 10–15 cycles.

The above schemes are only suggestive and timingsfor illustration to outline the reclosing schemes that atransmission or an HV distribution network can adapt toenhance the stability level of the network. Actual timingsand philosophy for fast and/or delayed reclosing willdepend upon the system parameters, rate of occurrenceof transient faults and other considerations based on fieldexperiences, system stability level and factors noted before.Small variations may also occur due to variation in theoperating times of interrupters and protective relays.

NoteThe critical drives connected on the power network such as auxiliarydrives in a power station, a process plant, industry or other importantinstallations, which may fall out during this momentary interruptioncan still be saved by incorporating in their switching circuits a re-acceleration feature as discussed in Section 7.18.5 (Figure 7.19).

Reclosing relays

Reclosing relays are available for single phase and threephase reclosings and can be programmed for 1–4 shotsas per the reclosure scheme. The relay operates when therecloser dead-time delay has elapsed. For dead-time aseparate time delay setting provision can be made in therelay, while the reclaim time can be adjusted through aseparate time delay relay. The relay an IED (intelligentelectronic device) has communication interfaces forconnecting it to a power network control and automationor a SCADA system. Figure 24.27(c) shows the generalover-view of an auto-reclosure relay.

24.10 Switching of large reactivebanks

The series capacitors are connected in series with thepower lines to provide reactive support to an individualload or to a power distribution or transmission system.They are therefore switched with the power lines and arethus permanently connected devices.

But the shunt capacitors and reactors can providereactive control through unswitched, i.e. permanentlyconnected, banks (fixed VAr) or through switched banks(variable VAr). The unswitched VAr may be used to aidstability against possible over-voltages of the network,during a load rejection or an open circuit while theswitched VAr is used to maintain the level of p.f. andstability during load variations. VAr switching can bedone in three ways.

1 Manual control This is through switching devices

First reclosing(i) Dead time of the � 140–180 ms (7–9 cycles)

breaker (duration the

line remains disconnected,to account for the prolongedarcing and other factors)through a closing timer

(ii) From commencement of � 40 ms (2 cycles) (Table

fault up to trip command 19.1)

(iii) Tripping time of the � 40–80 ms (2–4 cycles)

breaker (Table 19.1)

(iv) Reclosing time � 80–100 ms (4–5 cycles)

(Table 19.1)

Total reclosing time � 300–400 ms (15–20 cycles)

from the instant of

commencement of fault

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by switching in or switching out a few units. In manualswitching it will be possible only in steps, and maynot provide a smooth compensation and may alsocause switching transients (Section 23.5.1). Moreover,conventional switching methods (mechanical switchingthrough contactors and breakers), are sluggish due tothe time of closing and interruption, which may be asmuch as three or four cycles, depending upon thetype of interrupter (Section 19.5 and Table 19.1) aswell as the minimum time required for the dischargeof the capacitors. Human sluggishness may alsointroduce some delay. They are therefore ill-suited tomeet the system’s rapidly fluctuating needs.

However, power systems that cater to almost fixedloads at a time and whose variations occur only atspecific times of the day may not require a fastresponse. In such cases, it is possible to provide manualswitching methods which will give enough timebetween two switchings. Manual switching, however,has certain shortcomings, due to the human factorsuch as its accuracy and diligence, as noted above.The recommended practice is therefore to select fastreactive controls as noted below.

2 Auto control When auto-control is selected throughp.f. or voltage control, care must be taken againstfrequent switchings of the capacitors when the loadis of a varying nature which may cause the capacitorsalso to switch frequently. Fast switchings can be madepossible by providing special discharge devices, andby controlling the number of switchings to within

permissible limits (Section 26.1.1(2)) by carefullyarranging the units as discussed in Section 23.15.1.

3 Static VAr compensators (SVCs) or soft switchingof capacitor banks Whenever a large reactive controlis required, the SVC is always a preferred method.The static VAr controllers are more expensive, butrespond very quickly. They cause no switchingtransients and limit the magnitude of a disturbance,through extremely fast controls. They can handle largecurrents and peak inverse voltages, except voltagetransients, such as switching surges or lightning strikes.The surges may have a front time as low as 1–2 msonly (Section 17.3.3) while the switching time of astatic device (a thyristor) may be as high as one cycle,as discussed later. But surges can be taken care of bya surge arrester. The use of an SVC or a manualswitching will largely depend upon the characteristicsof the line, the type of load it is feeding and itsimportance. For a system having almost the sametype of load demand during the day, manual switchingmay serve the purpose as noted above. But for a systemwith wide fluctuations, an SVC alone will be suitable.The decision will vary from one system to anotherand the system engineer can make a better choice.

In SVCs the number of switchings is of no relevance,as they are free from inrush currents. Switching isperformed at the instant when the current wave ispassing through its natural zero. Static devices in variouscombinations and feedback control systems, whichmay be computer-aided, can almost instantaneously(£ 1 cycle) generate or absorb reactive power, as maybe demanded by the system. Correction is quick andmatches the fast-changing load parameters of the powernetwork at the receiving end. They are capable ofmaintaining a near-constant voltage profile at all timesat the receiving end. The correction achieved is accurateand smooth, besides being extremely fast and freefrom surges. They may be installed at strategic locationsalong the line or at the receiving end. The selection oflocation is an important aspect to optimize the size ofcompensator and a more efficient voltage regulation.

A fast VAr control is achieved through thyristorswitching, which by itself is capable of a stepless variation.But switching of capacitors, which are switched in banks,is not stepless. The SVCs may be of the following types.

24.10.1 Thyristor-switched capacitor banks(TSCs)

Thyristor-switched capacitor banks are normallyconnected in parallel with several banks of shunt capacitorsto control the system voltage. Feedback sensors andcontrols monitor the voltage level. When the voltageswings to either side of the preset value, a few banks areswitched in or switched out. This is illustrated in Figures24.28(a) and (b). Point a indicates the operating pointunder normal conditions. During a load variation ordisturbance the voltage dips and the operating point shiftsto b. With the use of TSC, the load point is shifted backto c. Since the control is in steps, it may be coarse. Thesteps may be limited to save on the cost of thyristors.

Figure 24.27(c) Over-view of an auto-reclosure relay (Source:Siemens)

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This step change in voltage can, however, be smoothedand a stepless reactive control achieved with the use ofa TCR (thyristor-controlled reactor) in parallel andoperating it with the TSC banks in tandem. Such a schemecan be tailored to suit even the smallest reactive need ofa system. The combination can be termed hybridcompensators. One such scheme is illustrated in Figure24.31 and discussed later, in more detail.

In TSCs the thyristors are used in anti-parallel to switcha capacitor bank ON or OFF but without any phase anglecontrol. A TSC therefore does not by itself generate anyharmonics, unlike a TCR.

24.10.2 Thyristor-controlled reactors (TCRs)

These consist of two oppositely poled thyristors, as shownin Figure 24.29 and conduct on alternate half cycles atthe fundamental frequency. Reactors may be switchedor phase angle controlled. Three-phase SVCs can

independently control each phase and the TCR can beused for phase balancing. When a phase angle is controlled,a stepless reactive power control can be achieved, exceptfor generation of harmonics during the control process.The gate control at peak voltage (a = 90∞) can allow fullconduction of the reactor. The conduction can be controlledby varying the gate angle, a. For example, partialconduction is possible with a between 90∞ and 180∞, buta from 0 to 90∞ is not used, as then the circuit wouldproduce asymmetrical currents with d.c. components.The effect of increasing the gate angle is to reduce theharmonic components of the current, and hence the powerlosses in the thyristor controller and the reactor. If thereactors and the thyristors are connected in delta, tripleharmonics can be eliminated and filter circuits would benecessary only for the remaining harmonic quantities.Various combinations of thyristor circuits are possible toobtain a desired phase displacement between the voltageand the current (cos f ) and hence suppress the variousharmonic contents present in the system. (Section 6.13provides more details on this.) See also Further Readingat the end of this chapter.

The number of thyristors in series, each selected foran impulse voltage of a little less than the impulse voltagewithstand level of the terminal equipment (Table 11.6)can effectively limit the switching overvoltages withindesired safe limits. Then connecting them in anti-parallelwill mean that the voltage will be forward for either ofthe opposing thyristors, hence protecting the systemagainst overvoltages in either direction.

24.10.3 Transient-free switching

To switch ON a charged capacitor

In a thyristor circuit if a charged capacitor is left ungatedat a current zero there will be no conduction of currentwhile the capacitor will still hold the full d.c. charge, as

Figure 24.28(a) Switching instants for a TSC

Switching instants

System voltage

Capacitor induced emf(with harmonic disorders)

Rec

eivi

ng-e

nd v

olta

ge (

Vr)

E1

E2

a

c

b

Normal load line

Load line on a

disturbance

1 se

t of b

anks

2nd

set o

f ban

ks

Ir

Figure 24.28(b) Improvement in loading by use of a TSCcompensator

Interrupter

Reactor

Opposite poledthyristors

For practical approach, thewhole reactor is divided into

two parts. One part isconnected after the thyristor,

to limit the fault current

V�

Figure 24.29 Scheme for a thyristor-controlled reactor (TCR)

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illustrated in Figure 24.30, equal to positive or negativepeak of the system voltage. For a transient-free switchingthe capacitor is switched when the system voltage andthe capacitors’ induced e.m.f. have the same polaritiesand coincide almost in magnitude. This situation maytake up to one full cycle (Figure 24.30) and can delaythe switching by one cycle when switched immediatelyafter a switch OFF. The system’s protective devices maybe introduced with an additional time delay of at leastone quarter to one half cycle to bypass disturbances of atransitory nature.

To switch OFF a charged capacitor

This can be achieved at any current zero which occursevery half cycle (Figure 24.30).

Reactor switching

Unlike a capacitor, an energized reactor on a switch-offretains no charge at a current zero and can be switchedON or OFF on a current zero at any point on the voltagewave without causing a transient. Hence there is a delayof, at most one half of a cycle between two consecutiveswitchings of a reactor. The balance of the two oppositelypoled thyristors, however, is monitored through the gatecontrol to avoid even harmonic quantities, although oddharmonics will still be generated when the gating anglesare balanced, i.e. are equal for both the thyristors.

24.10.4 Response of SVC on a fault or linedisturbance of a transient nature

An SVC offers an extremely low response time, of theorder of just one cycle as noted above. But this time issufficiently high to respond against disturbances of atransient nature. For instance, during a fault condition,as expressed by the current–time oscillogram of Figure14.5, the SVC will respond during the transient periodonly and not during the sub-transient period. Thesubtransient period may be less than a cycle and not fallwithin the response range of an SVC. But a reactivecorrection is also not needed for conditions of such atransient nature, which is taken care of by the surgearresters (Chapter 18). A system is normally suitable to

remain stable, without an outage, during disturbances ofsuch a transitory nature. Similarly, the SVC will stayimmune to lightning and switching surges.

24.10.5 Combined TSC, TCR and fixedcapacitor banks

With the combination of switched capacitors and reactors(TSCs and TCRs), also known as a hybrid combination,each phase voltage can be closely monitored to maintaina near balanced and flattened profile at all times at thereceiving end. A typical scheme is illustrated in Figure24.31 which comprises:

• A few fixed capacitor banks which are normallyenergized. When they are required to be switched,they cause a switching delay due to the closing oropening of the interrupting device, besides generatingthe switching surges. To avoid delays and switchingsurges, they may also be made as TSCs, if cost is oflittle consideration and faster and more accuratecorrections are more important, in view of highlyfluctuating and non-linear load demands.

• A few TSCs for finer reactive controls.• A few TCRs to balance the reactive power supply.

They may generate harmonics, which must besuppressed to avoid any resonance. TSCs and TCRsare monitored through a feedback control system.

• A filter circuit to absorb the harmonic currentsgenerated by TCRs and in certain conditions, whenTCR is ‘OFF’, also generate capacitive reactive power.Refer to Figure 24.33 for more clarity.

Consider a normal load line (1) (Figure 24.32) havingthe initial operating point at (a). On a disturbance, theload line shifts to (2) and the operating point to (b). TheTCR would respond and some inductive reactance (XL)will be shed to raise the content of XC. The load line willbecome less inductive and more capacitive to help thevoltage rise to point (c) within one cycle. If the voltageis still below the preset value, some capacitors can beswitched ON either electromechanically or through TSCs,depending upon the system adopted. The delay at point(c) will depend upon the method of switching of thecapacitor banks. The voltage will now jump to point (d)and final correction is achieved up to point (e). Thesequence a–e would complete in less than two cycles ifall the components are thyristor switched. The sequencesfrom a-b-c-d-e can be reduced to a-b-e allowing a littleover- or undershoots from c to d.

Notes1 Reactive control is also possible through synchronous condensers.

As they rotate, the rotor stores kinetic energy which tends toabsorb sudden fluctuations in the supply system, such as suddenloadings. They are, however, sluggish in operation and veryexpensive compared to thyristor controls. Their rotating massesadd inertia, contribute to the transient oscillations and add tothe fault level of the system. All these factors render them lesssuitable for such applications. Their application is thereforegradually disappearing.

2 Reliability of shunt or series power capacitors is of utmostimportance for the security of the system on which they areinstalled. Their failure may disturb the system or result in asystem outage.

The next similarcondition occursafter one cycle

DC charge ona switch off

Vmax

One cycle

AC voltagewave form

Vmax

‘I0’ at everyone-half of a cycle

Figure 24.30 A delay up to one cycle in transient-free switchingON, of a charged capacitor

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3 Generally, SVCs are designed for 11 or 33 kV and connected toa higher voltage system through a dedicated transformer throughthe tertiary of the main transformer. Figure 24.33 illustrates atypical SVC system using a dedicated transformer.

4 Since reactive controls are normally meant for large to verylarge installations, the practice so far has been to use thyristorsonly for such applications. With the advent of IGBTs, IGCTs andother devices (Section 6.7) installations of any capacity can nowbe switched through these state-of-the-art semiconductor devices.Likely applications besides power distribution and transmissionsystem

– Rolling mills– Industrial heating through arc and induction furnaces (Section

25.1.4). See also Section 6.7.4.

24.11 Automation of power networkthrough Supervisory Controland Data Acquisition (SCADA)system

Introduction

In this age of mechanization, SCADA has become aninevitable tool for automation. With the availability of

microprocessors and digital signal processing intelligenttechnologies that are prompt, accurate and moreimportantly reliable, human involvement in monitoringand control of complex activities in industries and powermanagement can be kept to the minimum. Automationenhances the integrity, reliability and dynamic stabilitylevel of a system. Such supervisory systems are becomingthe state-of-the-art, around the world to monitor andcontrol complex activities in power management andindustries like steel, cement, chemical, fertilizers,petrochemical, refineries etc. achieving,

– Improved reliability– Better quality of service– Better outage management– Striving to become customer centric– Timely revenue realization and reduced losses– Enabling trading and sourcing in optimum manner

Besides financial benefits, automation is sometimes theonly way to cut down a chaotic situation. A distributionsystem without SCADA-DMS can have three to fourhours of painful downtime which can be brought downby SCADA-DMS to just a few minutes.

There are consulting agencies who undertake studyof such complex systems and work out scientific, logical

Figure 24.31 Scheme for a reactive power control showing combined TSCs, TCRs and fixed capacitors

1 2

3

4

400 kV transmission or132 kV distribution line

Reactive powersupply bus

Interrupter

Transformer forreactive power supply.Secondary at say, 11 kV

V.T

Interrupter

Some fixed reactorto filter out sub-harmonic components

Line side reactorto limit inrush current

and suppress harmonics

Opposite poledthyristors to

switch capacitorsor reactors

Voltage regulatorand feedbackcontrol system

Note:

1

2

Thyristor switched capacitors

Thyristor controlled variable reactor (TCR)(it may also be a saturated reactor)

3

4

Filter circuit to absorb harmonic currents caused by TCR

A few filter circuits for different harmonics

* *

Capacitors and reactors may be D connected toeliminate triple harmonics

*

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and efficient SCADA solutions through automation.Industrial automation is on the rise and so also theautomation of ever rising power generation and complextransmission and distribution networks. A powerautomation system also provides the followingmanagement support,

– The automation schemes rely on data from IEDs*(relays, sensors, meters) and PLCs/RTUs placed atall critical locations. They measure essential parametersand environmental conditions like generation, loading,status of transformers and distribution networks andtransform them to real-time and historical data anddeliver to the system or application and decision makersfor further action.

– Continuous process monitoring of a power system –without automation and feedback controls it ispractically impossible to provide stability andcontinuity to a complex power network catering hugeloads in a city, state or a whole country, inter-connectinga number of generating units, transmission anddistribution networks, their load control centres andfeeding stations etc. spread over a large geographicalarea. In a complex network a line disturbance followedby human error, or power system element failure may

dislodge the synchronism between the generating units,transmitting stations and distribution networks andthrow the whole power network out of tandem toeventually trip or cause a total blackout as noted inSection 24.9.

Using microprocessor based intelligent technology it isnow possible to produce relays and measuring deviceswhich can record, compute, compare (like a comparator),analyse and diagnose, make prompt decision and relayout prompt remedial activity, as per the program storedin their memory, to control a remote mechanical orelectrical operation in a power network or generatingstation as needed. A few such relays are mentioned inSection 16.8. These relays as IEDs (intelligent electronicdevices) can record numerous operating conditions ofvarious machines, equipment and devices operating inthe generating station related to flow, temperature,pressure, speed, voltage, current, frequency, p.f. or anysuch data and the loading conditions and vital parametersof each transmission or distribution line connected onthe network. They compute all such data, compare themwith the data programmed in their memory, analyse anddiagnose them for any corrective action and can relayout prompt warning signals or a remedial action to therelated generating unit or the load dispatching or loadcontrol station.

de c

a

b

13

2

Rec

eivi

ng e

nd v

olta

ge (

Vr)

Load current

Capacitive Inductive

123

– Normal load line– Load line on a disturbance (overloading)– Corrected load line

Note: Similarly, load lines can be drawn on a load rejection, or thegenerator or the line outages.

Figure 24.32 Voltage regulation during overloading throughreactive management

O

400 kV line

400/33 kVDedicated

transformer

7thharmonic

filter

5thharmonicfilter

TCR say,0–190MVAr

Fixedcapacitor

banks90 MVAr

40 MVAr10 MVAr

Filter circuits

Range of compensation availableCapacitive : 0 to +140 MVArInductive : 0 to –140 MVAr

Illustration:(a) When the TCR is ON, MVAr support = –190

Now filter circuits would also be on to suppressharmonics and absorb capacitive MVAr = +50\ Net maximum reactive support available = –140 MVAr

(b) When the TCR is OFF, fixed capacitor bankswould supply capacitive MVAr = +90The filter circuits would also supplycapacitive MVAr = +50\ Net maximum reactive support available = +140 MVAr

Figure 24.33 Typical SVC at 400 kV through a dedicatedtransformer

* IEDs – Intelligent electronic devices.

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SCADA-EMS/DMS is an energy management softwaresystem to provide such complex networks, the requiredmanagement support and the necessary automation. Themain functions of SCADA are,

– Acquisition of field data from the equipment anddevices installed in the field, process them and usethem for the control of remote devices

– Telemetry – to transfer the data processed to differentsites/operators. The data can be analogue or digitalstored by RTUs (Remote Terminal Units)/FRTUs(Feeder Remote Terminal Units) or IEDs like relays,sensors and meters.

These are the basic blocks on which is built the utilitycontrol system.

SCADA system constitutes a combination of computerhardware/software and communication technologies. Thefield system comprises a network of microprocessors(PLC’s (Section 13.3.6) or RTU’s) in association with anumber of other IEDs like digital and numerical relaysfor different protections, pre-warning alarm, recordingand metering facilities. All possible causes ofdestabilization and their remedies are simulated in thesoftware program at a control centre to achieve promptrestoration of stable conditions and avoid a destabilizationor tripping of a line or the whole system as far as possible.The software used possesses scalability to migrate betweencomputers of different vendors and different scales andare expandable.

A very important area constituting the energymanagement system is telemetry – a data transfer andcommunication network, to relay out data and messagesto different control stations in an efficient, distortion anddisturbance free communication network such as througha Serial Data Transmission System discussed in Section24.11.5. The relays’ communication open type protocolsare noted in the same section.

In case of EMS-SCADA the main controlling andmonitoring station (master control centre (MCC)) islocated centrally over-viewing through the SCADA energymanagement system (EMS) all its generating units andcontrol stations (transmission networks) for their optimumoperation within desirable parameters. The sub-energymanagement stations are located at different field pointslike at generating stations and feeding and load controlcentres operating in tandem, to monitor and regulate theiroperating conditions and load balancing through remedialaction such as load shedding, load transfer, starting andsynchronizing a standby generating unit or any suchactivity.

In the event of a line disturbance or a fault of transientnature as discussed in Section 24.9, the energy managementsystem so achieved will be capable to restore the operatingparameters within desirable limits in the least possibletime. Such as through an auto-reclosing as noted in Section24.9.1 and avoid a voltage swing or outage of the systemas far as possible. Worse, if the faulty section is not ableto restore its normal operation within permissible time, itcan be taken out. If it is a generating unit, carry out loadre-distribution from the available power to the variousdispatch stations and load centres without jeopardizingthe dynamic stability and continuity of the network.

24.11.1 Application of a SCADA system

SCADA basic functionsBased on the discussions we have had so far the basicfunctions of a SCADA system as applied to a powerdistribution system can be summarized as below,

– to provide real-time, accurate and consistentinformation of the power system

– to maintain database and history of system parametersto review and analyse past operating data to providean insight for future corrective actions, alsomanagement information reports

– to locate the fault quickly, isolate it and restore thesystem

– to maintain records, store statistical data and transmitthe same to desired destinations

– to provide inputs for better network planning– to improve availability of system and– to optimize the system based on real-time calculations

Other functions

– Data acquisition– Control– Alarm and event handling– Trending– History and archiving– Reporting– Load shedding– Reactive power control– Voltage control– Load balancing

Automation scheme It shall mean– Monitoring– Decision making and– Control

and shall be accomplished through a centralizedSCADA system.

SCADA main ingredientsIt covers large geographical areas and relies upon thecommunication network and may comprise the followingdepending upon the level of automation and feedbackrequirements,

– At field levels (generation, transmission or distributioncentres), the SCADA will comprise Remote TerminalUnits (RTUs) or PLCsa for remote telemetry, Input/Output (I/O) racks, transducers and auxiliary relaypanels.

a NoteEarlier it were RTUs that were usually employed because oftheir compatibility with various communication protocols. Thisfeature is now available with PLCs also. Both are computersand possess good programmability and compatibility with variouscommunication protocols and can be employed for this purpose.

– System level components: These are located at theControl centre level and comprise Front End Processors(FEPs), Database servers, Man Machine Interfaces(MMIs), Video projection system etc. Critical system

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level components, mainly Front End Processors andDatabase servers have redundancy. There are multipleMMIs with provision to view the entire network fromeach of them.

The MMI program operates on the MCC computer.A single line mimic diagram of the whole plant orprocess can be displayed on the monitor for quickercomprehension and remedial action by the operatorwith the real-time system. Similarly can be displayedbar charts, trend curves of key areas, alarm displays(it can be programmed to display all requisite dataand information such as tag number, trip value, time,date or any other data or information as desired) anddaily logs or management information reports of theprocess. Typical diagrams representing a few of thesedetails are shown in Figures 24.34 (i-v).

– Communication media: It comprises the media forcommunication between field and system levelcomponents and can be fibre optic, leased lines, privatemicrowave networks etc., and the associated endterminal equipment. The communication media shallalso have redundancy.

– Serial data transmission via communication interfaces(Section 24.11.5)

NoteThe above is the vital data collection and transfer system and ishighly vulnerable to intrusion by unscrupulous persons and mustbe adequately secured for their integrity and reliability as discussedin Section 24.11.8.

24.11.2 SCADA implementation

For implementation of SCADA system, remote dataacquisition and its control are the key areas. To implementthis, following are the pre-requisites,

– Availability of auxiliary contacts for status monitoringof circuit breakers (CBs)

– Suitability of closing & tripping mechanisms of circuitbreakers for remote operation

– Availability of CTs, VTs, CVTs and transducers formonitoring of feeder power flow

– Availability of auxiliary contacts from protection relays– Assessment of retrofitting requirements if any (usually

with the old installations)– Suitability of remote control of OLTCs (on-load tap

changers) on power transformers– Space in substations for installations of RTUs or PLCs

System planningThe following factors may be kept in mind,

– System architecture (layout)– System sizing and scalability– Communication network

• System architecture (layout)

Usually the SCADA system can have one MasterControl Centre (MCC) and one Backup Control Centre(BCC). The BCC shall be in hot stand-by mode for

Figure 24.34(i) Single line diagram display of a power process line (Courtesy: BHEL)

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Figure 24.34(ii) Typical bar chart

Figure 24.34(iii) Typical trend curves

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Figure 24.34(iv) Typical part of an alarm display chart

Figure 24.34(v) Typical part of a daily log of data required

disaster recovery and shall cater to the full operationalrequirements of the network upon severe contingenciesto the MCC. For the sake of reference a typical layoutis illustrated in Figure 24.35. MCC is the master unitof SCADA system and responsible for storing thedata collected by the remote stations and generatingaction plan. It can be networked to work stations forsharing the information.

Location of MCC – It should be located at a centrallocation with easy accessibility to the entire distributionarea. A typical layout of control room area is shownin Figure 24.36. Figure 24.37 shows a typical layoutof a SCADA system.

Location of BCC – Anywhere with easy accessibilityto the distribution area.Switch-over procedure from MCC to BCC – All RemoteMMIs and RTUs are connected in normal condition tothe master control centre (MCC). In case of total stopof MCC for whatever reason, the situation is signalledimmediately to the operator in a conspicuous manner.

The operator decides after calling the administrator oroperators at the MCC if it was necessary to switch overto the Back-up Control Centre (BCC) or if the situationwould be recovered in a short while. This philosophyhas gained momentum especially post-September 11,2002 catastrophe of USA.

• System sizing and scalabilityThe system sizing requirements are governed by thedata flow between

– Substation equipment (status, control and powerflow) and RTUs

– RTUs and Master Control Centre (MCC)– Master Control Centre (MCC) and Backup Control

Centre (BCC)

The system can be designed keeping in view thefuture expansions and additions in the installedcapacity that may take place in course of time.

• Communication networkFor optimum and reliable operation of the SCADA

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system, communication network for exchange ofinformation between field systems and control centresystems (MCC) plays a crucial role. Redundancy isessential to be built in the communication system toensure minimum downtime. For real time monitoringand control of the system, the following update times(considered typical for an MMI) can be chosen

– Control 4–6 seconds (from command executionto back indication on MMI)

MCC - BCC link and speedMCC/BCC remote MMI linkand speedMCC BCC

10 Mbit10 Mbit

2 Mbit2 Mbit

WAN

2 Mbit

Figure 24.35 Typical control centre configuration interconnectedwith dedicated link and Wide Area Network (WAN) (Courtesy:Reliance Energy)

Figure 24.36 Typical layout of a SCADA system MCC controlroom

Video screen

Operatorconsoles

Supervisoryconsole

Engineer inchargeConference room

Master Control Centre (MCC)

Figure 24.37 Typical system architecture of SCADA-DMS (Courtesy: Reliance Energy)

Light users(PCs/Web)

LU1 LU2 LUn Main users(consoles)

ICCP

Transco CC Backup ControlCentre (BCC)

12

Systemcontrol

WAN

Grid stationCommunication media

Grid station

RTU #1

Bay switch

Bay switchProtection relay

Protection relay

RTU #nth

Bay switch

Bay switchProtection relay

Protection relay

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– Status 4–6 seconds (from RTU to updationin MMI)

– Analog 10 seconds (from RTU to updation inMMI)

To achieve response times as indicated above thefollowing key factors must be considered.

– Processing capabilities of the RTUs or PLCs– Processing capabilities of the Front-End Processors– SCADA architecture– Communication media: speed, reliability and

availability

The communication media shall provide adequatebandwidth to carry the data-flow of the RTUs or PLCsinstalled with provisions for future expansions, so thatthere is no over-loading at any point in the communicationnetwork especially during high load and burst scenarios.In view of the need for DMS functionalities,communication planning should be based on liberalcapacity (kbs) per Grid Station. In addition to thebandwidth requirements, the following criteria are alsocritical for selecting the communication media.

– Reliability– Availability– Data Security– Communication Protocols: The media should be

capable of supporting standard protocols as notedin Section 24.11.5 or any other not covered there.

For communication media, fibre optic cable isrecommended because,

– It provides highest availability, reliability,bandwidth and data security

– Modern communication protocols as well asadditional services are available almost withoutrestrictions

– The media is independent from public utilities andservices

– Redundancy is possible by using ring structures

Implementation of DMS (Distribution ManagementSystem) and Business Integration Concepts can besummarized in the following manner,

– SCADA system (with its functions noted above) isinter-connected to the grid stations with MCC andintegrated with DMS functionality to achieve,

• Distribution Network Power Flow• Fault Isolation and Service Restoration• Switching Procedure Management• Voltage and VAr Control• Capacitor Bank Control

– System is also integrated with business processes such as,

• Automatic Meter Reading system (AMR)• ERP (Enterprise Resource Planning) system software• TCS (Trouble Call System) software• Any other requirement

– Independent inter-connection of grid stations with BCC– Inter-connection between MCC and BCC– Integration of DMS-SCADA with other systems

With the help of DMS-SCADA system a power networkcan be integrated with other networks. A typical blockdiagram indicating information exchanges between thedifferent systems is shown in Figure 24.38. Figure 24.39shows the hardware configuration. The above is only abroad overview of a DMS-SCADA system giving ageneral idea about SCADA architecture, its applicationand utility. The basic requirements would vary fromapplication to application, type of power system, itscomplexity and requirements. The same logical approachcan be adapted when applying a SCADA system togeneration, transmission or an industry.

CIS(Customer information

system)

GIS(Geographical

information system)

Status data

Maps. equipmentdataCustomer

Trouble tickets(substations)

Outage data

SCADA-DMS

System &equipment faults

Equipmentdata

Loadprofiles,

(substationalarms)

AMR (automaticmeter reading

system)Billing & settlement ERP system

Figure 24.38 Block Diagram indicating work flow between various business processes (Courtesy: Reliance Energy)

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Below we discuss a simple SCADA scheme for auto-load shedding in a power utility distribution and substations’network. The scheme can be modified to suit any complexpower network for load shedding, rationing, load transferor re-distribution of power as per the network requirements.Most of the modern substations apply the new generationmicroprocessor based IEDs like relays, sensors andmeasuring devices, while the old ones that are looking foran automation can be retrofitted with similar IEDs.

24.11.3 Implementation of load shedding andrestoration (Figure 24.40)

Below we describe typical implementation of loadshedding functionality in SCADA for a utility that hasits own generating station, plus it imports power from asupply company which is connected to the State ElectricityBoard (SEB), which in turn is further supported by thenational grid of a country.

Load shedding schemeThe load shedding (LS) scheme, network determination

(Utility Grid connected, Tie line outage, Utility islanded)is carried out in SCADA MMI (Man Machine Interface)based on identified breakers. The load is shed in theindividual receiving station (RS) proportional to theloading on individual receiving station. A logic is alsoimplemented in SCADA MMI for generating an over-load trigger in case of tie line outage or a UGS unit tripcondition. The breaker status & load per RS are sentfrom individual RS to SCADA MMI over acommunication system.

Network status (Utility Grid connected, Tie line outage,Utility (UGS) islanded), amount of load to be shed andover-load trigger is sent from SCADA MMI to individualRS over a communication system. The SCADA MMI atUtility Generating Station (UGS) acts as master, whilethe SCADA units in the individual RS work as slaves.The load shedding (LS) takes place on trigger from underfrequency relay stage or the over-load trigger receivedfrom SCADA MMI. It takes place as per the prioritydefined by the operator at the respective RS or as per thedefined program.

Figure 24.39 A typical SCADA-DMS hardware configuration interconnected on the network (Courtesy: Reliance Energy)

GPS (Globalpositioningsystem) & TimeDisplay

IS&RDMS & otherapplications SCADA

BCC MCC

RoutersMulti-portRouters

IS&RDMs & otherapplications SCADA

LANLAN

FEP Videoprojectorsystem

To RTUsCNP (ICCP)

Console Console Console Console

PDS

Printers

Colour printers

Console Console Console Console

PDS LAN

Routers

CNP (ICCP)FEP

To RTUs

PrintersColourprinters PDS

processor

To remole FEPs RTUs and IEDS

Router Data Acquisition Network

DAN

WAN

Fire walls

Web UIserver

Corporate Network

CMSDMS

Datawarehouse Web consoles

To othersystem

2 B&W printers1 colour printers

GPS & Time DisplayRemoteWS PC

Console Console Console Console

FEP

To RTUsCNP (ICCP)Video

projectorsystem

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Utility (UGS) load shedding requirementsLoad shedding is implemented as a fast acting systemwhich sheds defined load by defined rules to protect thegenerating units at the UGS and keep the supply of UtilityDistribution System (UDS) alive to the maximum extentpossible. Load shedding automatically acts in differentscenarios such as under frequency, islanding and tie linetrip. The load shedding is carried out by different logicsdepending on the available scenario:

– Utility grid connected (under frequency scenario)– Utility grid islanded– Tie line outage

• Manual load sheddingManual emergency strategies are defined via a specialdisplay by selecting one of the available manual loadshedding lists. A manual load shedding list containsall associated loads from the highest priority down tothe lowest priority. The loads that may be shed areeither marked by the operator or the required amountof load is entered by the operator and is assigned tothe lowest priority loads. An execute commandactivates manual load shedding.

• Under-frequency load sheddingUnder-frequency load shedding is used by Utility(UGS) to compensate outages of large generating unitsthat result in a gradual frequency fall. Consequently,low priority loads are shed to compensate for powerdeficit. In case of severe disturbances the followingmay be opted

– system islanding (splitting the distribution networkinto several sub networks)

– disconnecting the distribution network from theutility grid

– shedding of reactive loads

• Target violation load shedding – If the contractualimport target limit from a partner utility (UG) isviolated, the over-load is determined and marked orshed and the operator is alarmed.

• Equipment over-load load shedding – Load sheddingis also exercised to protect selected equipment(transformers, generators, tie-lines) from over-loadand subsequent damage.

• Island balanced load shedding – Island balanced loadshedding can be applied, when some parts of the

Interconnection between Utility, Supply company and State Electricity Boards

Utility generating station (UGS) Supply company generation

4 4

Utility load on 220kV R/Sgenerating station + supply

company

Part load fed from supplycompany interconnection

Utility load MW

Other utility loads

Other loads

Tie-lines

1 2

1 2

3

3

3

3

3

Tie-lines

SE

B in

terc

onne

ctio

n [U

tility

Grid

(UG

)]

Power export to utility at 220 kV

Load fed by supply companyat 22kV and 33kV

Load fed by supply company

Load fed to other HV consumers

1 Islanding between Utility and Supplier at Utility end setting 47.7 Hz + 0.3 s (typical)2 Islanding between Utility and Supplier at Supplier end setting 47.6 Hz + 0.15 s + Reverse Power (typical)3 Islanding between Utility and SEB at Supplier end setting 47.6 Hz + 0.3 s (typical)4 Generator under frequency settings 47.5 Hz + 1s over frequency 52.5 + 4 s (typical)

Figure 24.40 Position of a utility generating station (UGS) in an interconnected grid (Courtesy: Reliance Energy)

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protected system lose connection to each other or ifthe protected system loses connection with a partnersystem (UG in the present case).

• Emergency strategy logic – After positive identificationof a trigger event, the actual emergency strategy andcorresponding action is determined. It may beconducted in the following manner.

– Manual triggering – The operator activates theshedding of a given load or loads as per the loadshedding list.

– Alarm initiation – The respective emergencystrategy is activated by alarms.

– Hardware initiated triggering – Signals from under-frequency or over-load relays may directly causethe shedding of predetermined loads throughactivation of latching relays or a control logic.

– Network islanding – In case of severe emergencies,network islanding or disconnection from the utility(UG) can be performed intentionally.

– Load restoration – After load shedding action, theload shedding function determines the amount ofavailable power in the affected network or islands.The value of the loads that can be restored isestimated according to the last value before trippingand the power available.

In this manner we can tackle most of the emergencyevents, stabilize the disturbance impact of distributionnetwork on power system, and

– achieve saving of auxiliary power supply of powerplants and distribution network

– avoid unintended power feedback to a collapsedutility (UG), and

– get rid of high reactive loads in cable networks

24.11.4 EMS-SCADA: (Energy ManagementSolutions)

Energy management system (EMS)SCADA system when applied for the automation of apower generating and transmitting network is called EMS-SCADA with the following objectives,

– To automate generation and transmission systems andimprovise their dynamic stability level

– To provide cost-efficient power generation byoptimizing generation

– To identify and control abnormal network conditions– To reliably monitor energy management, generation

control, energy trading, substation automation andoutage management

– System integration – to focus on serving customerneeds vis-à-vis major vendors, meaning thereby co-ordination with multi-vendor SCADA-EMS

– To balance the source of energy and consumption ofenergy

– Data acquisition, analysis and communication systemsremain much the same as for DMS-SCADA. Nowthe system also integrates equipment and devices, suchas generators, transformers, swithchgears, UPS, PCCs,MCCs, VAr controls and metering system to monitorthe whole power generation, transmission anddistribution networks from a central location. The

EMS-SCADA may now be programmed to conductthe following functions,

– Load flow analysis– Cost allocation– Supply and demand management– Trending– Remote metering and energy auditing– Load scheduling and shedding, even rationing in

power deficit areas– Reactive power management to improve voltage

profile and stability of the system– Telemetry protocols

Difficulties have been experienced in integrating the latermodules/functions of SCADA related business processwith the existing system. Present philosophy is thereforeto adapt an open architecture and use standard RDBMSlike ORACLE & SYBASE that is vendor independent.This way modular integration can be possible.

Portability – Application software should operateconsistently on various operating systems of differentvendors.Interoperability – Information can be transferred betweencomputers/firmware of different vendors through standardprotocols.Scalability – Application software can migrate betweencomputers of different vendors and different scales, andthe system can be expanded as power system networkgrows.Inter-connectivity – Other systems can be accessed throughthe information network as if it were a load system (userportability).For more details one may refer to the works mentionedunder Further Reading.

24.11.5 Serial data transmission to a control andautomation system via communicationinterfaces

A serial data transmission system is a means to transferdigital data to a remote control station from IEDs likerelays, sensors and meters through protocols and media.Media of transmission can be internet, radio (wireless),PLCC (power line carrier communication) or optic fibrecables (Section 23.5.2(F)). It can also be wired mediafor short distances (10–20m). The choice of any of themwould depend on economics and the required transmissionquality, safety (corruption of data and hacking),interference, rate of transmission and distance. Wirelesssystem is used for very long distances.

Application of multi-purpose microprocessor basednumerical relays as IEDs for power management andautomationNumerical relays are employed for power transmissionand distribution networks calling for monitoring, analyzingand diagnostic features in the relay, in addition to warningsignals and trip commands. With the application of state-of-the-art microprocessor based technology, numericalrelays are now being manufactured by many leadingmanufacturers worldwide. They are producing multi-

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purpose relays, clubbing into one composite unit dozensof different purpose protection relays, incorporatingfeatures like recording, display and storage of data besidesprocessing, analyzing, monitoring and diagnostic abilities.The selection of relays is now simpler and protection ofa system, equipment or a circuit much morecomprehensive and easy. So also monitoring of operatingconditions of a power generating unit, transmission ordistribution network, or of a machine (transformer, motor,generator, capacitors or reactor). Their feedback controlis simple, comprehensive and authentic. The communic-ation interfaces using different protocols can transmit allserial data related to protection or information such asfault currents and voltages, sequence of events, load dataand settings etc., on-line or off-line to a personal computeror a substation control and automation system. In short,with the application of the IEDs it is possible to make apower network remotely controlled and fully automatic.

These relays thus can ensure safety, reliability andstability of a power network or machine during operationthrough a single or minimal number of relays. Theprotective scheme can be engineered and interwired usingindividual protective relays. Multi-processing allowsintegration of main protective functions and otherprotection related tasks, such as synchronization checkinto one single numerical relay. The relay can monitorand control vital circuit parameters like DV, D f and Dq asrequired during a synchronizing check of two or moresources of power or generators. A few such relays areshown with the Figure 16.14 for the protection of agenerating station. See also Figure 13.47(c).

These relays may also be referred to as intelligentelectronic devices (IEDs) and can form a part of an EMSor DMS-SCADA power management system formonitoring and protection of a power network as discussedalready. These relays provide the bottom layer intelligencein a generation, transmission or distribution network.They perform processing of analog data to determine thefault location or faulty feeder as programmed and transmitthe same to the desired destination through Serial DataTransmission System.

As standard, modern numerical relays are fitted withone or several communication interfaces. Thesecommunication interfaces are designed based on variousStandards prevailing for physical interfaces andcommunication protocols. Communication interface forpersonal computer or laptop is usually provided as RS232C*on front of the protection relays and permits access to allsetting parameters and fault event data, using a relaysoftware. While a system interface is usually provided onthe rear side of the relays and permits communicationwith control and automation system on a variety ofcommunication protocols and physical interfaces. Theselection of physical interfaces will depend on the protocolarchitecture and its techno-economics. Protocols are a setof rules that allow the various stations connected to a fieldcommunication bus to spontaneously transmit the requireddata, to a defined destination as discussed next.

Almost all numerical protective relays can be integratedinto generation, transmission or substation control andautomation systems via system interfaces on a variety ofcommunication open type protocols. Modern numericalprotective relays have the following communicationprotocols:

– IEC 60870-5-103 It is an internationally standardizedprotocol for efficient communica-tion between protective relays andmaster control centre (MCC) andfollowed by power utilitiesworldwide.

– Profibus It is a protocol used in automationindustries and is used whenprotective relays are required tocommunicate with control andautomation system for their faultrecords, measured values, controlcommands and settings.

– Modbus Modbus is a widely usedcommunication protocol forautomation solutions in industries.It is used wherever protective relaysare used along with otherautomation intelligent devices(IEDs) such as PLCs. It is designedto emulate PLCs, transferringregister data to one another.

– DNP 3.0 DNP (Distributed NetworkProtocol Version 3) is a messagingbased communication protocolused in utilities.

– IEC 61850 It is the latest Etherneta basedStandard for communication,specifically designed for substationautomation in utilities andindustries to permit interoperabilityof IEDs of different manufacturers.

aEthernetEthernet only defines the physical layer and not the protocols. Ituses the Carrier Sense Multiple Access, Collision Detect (CSMA/CD) data-link protocols, which employ a broadcast method forcommunicating with nodes. When a station senses that the networkis idle and it is ready to send, it transmits its data packets to thenetwork. Since all nodes hear the data, each node checks to see ifthe packet is intended for it. The station that matches the destinationaddress in the packet is the one that responds. The collision detectionpart of CSMA/CD tells nodes to halt transmission if a collision isdetected and to try again later at a randomly determined delayedperiod. The Ethernet system consists of three basic elements:

– The physical medium – used to carry signals between computersand nodes

– The set of rules – that controls/arbitrates access to the Ethernetas it applies to several users

– The Ethernet frame-packets, that consist of a standard set ofbits are used to carry data over the Ethernet

For more details on protocols refer to the above mentioned IECspecifications and a few mentioned in the list of Standards.

Protocol converterFor different brands of IEDs at local and remote controlstations operable on different protocols, protocol converteris necessary to establish communication between the two

*RS232C – is an internally agreed Standard for serial datatransmission.

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IEDs. Presently manufacturers of various IEDs mayincorporate their own proprietary softwares conformingto different protocols for transmission of data, partly tomaintain their own secrecy and partly because there wasno common open type protocol applicable on them untilrecently. It therefore called for a protocol converter tomake an IED of one brand communicate with the IED ofanother brand. Handling of large number of protocolswas therefore cumbersome, costly, time consuming anddependent on one particular brand of IEDs duringmodification or expansion of an existing automationsystem. It also introduced some delays and caused errorsin the communication. It also meant high cost ofmaintenance for the user.

Evolution of IEC 61850

To overcome these problems IEC in 1995 organized ateam of experts of different countries, manufacturers andutilities and assigned them the job of evolving a commonprotocol for substation communications. After years ofrigorous working it has culminated in IEC 61850. It alsosurpasses IEC 60870-5 on interoperability. IEC 61850 isan open type protocol capable of communicating withdifferent IEDs without the use of protocol converter andcan easily define an international field communicationbus. The IEDs can now be built with only one protocolcalling for no protocol converter. For details see IEC 61850.

With the advent of new generation protocol IEC 61850,manufacturers are now obliged to gradually adapt to thisprotocol to bring harmony amongst different kinds ofIEDs produced by them to facilitate easy implementationof system automation by the user without the use of a

protocol converter. Many leading manufactures havealready implemented this and others are in the processof doing so.

24.11.6 Introduction to general protocols

Networks (hardware) provide computers the basic abilityof transferring bits from one computer to another. In orderto use networks we need a set of rules which all thenetwork’s members agree on. These rules are termedprotocols. Communication Protocol is a Standard,designed to specify how computers interact and exchangemessages. A protocol usually specifies:

• The format of the messages, and• Procedure to handle errors

In order to simplify the design and implementation ofprotocols, designers have designed a set of protocols,each having different responsibilities instead of oneprotocol to be responsible for all forms of communications.The set of protocols that implements the protocol stackis called a Protocol Suite and covers all forms ofcommunications as needed. For better application of aProtocol, the Protocol Suite is further sub-divided intovarious models as noted in Table 24.6.

Internet protocol suitesOf the many applications the different types of protocolsinvented so far, we shall limit our discussions to onlythose that are related to EMS or DMS–SCADA systems.In case of EMS-SCADA the chosen protocol suite shallbe capable to communicate between different SCADA

Table 24.6 Protocols specific models

1 MODBUS: There is no time synchronization via this protocol. For time synchronization purposes it is possible to use a separate timesynchronization interface.

2 Fault records: The transmission of fault records is not a part of the protocol. They can be read out with relays software. Fortransmission a separate interface for the front operating interface would be required.

3 Protection settings: This protocol does not support the transmission of protection settings. Only setting groups can be changed. Forthis purpose a separate interface or the front operating interface together with relays software would be required.

Protocols ÆSpecific functions Ø

Alarms (relays tocentral unit)

Commands (BC/central unit to relay)

Measured values

Time synchronization

Fault records2

(sampled values)

Protection settings3

IEC 60870-5-103

Availablewith timestamp

Available

Available

Available

Available

Fromseparateport

PROFIBUS-FMS

Availablewith timestamp

Available

Available

Available

Available

Available(with relayssoftware)

PROFIBUS-DP

Available withtime stamp

Available

Available

Available

On separate port(with relayssoftware)

Separate port(with relayssoftware)

DNP 3.0

Available withtime stamp

Available

Available

Available

On separateport (withrelays software)

Separate port(with relayssoftware)

MODBUS1

Available withtime stamp

Available

Available

Not available

On separateport (withrelays software)

Separate port(with relayssoftware)

IEC 61850

Availablewith timestamp

Available

Available

Available

Available

Available

Separateport relayssoftware

Availablewith timestamp

Available

Available

–

Available

Available

Communication port for Substation Automation System

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system levels within a utility and between different powerhandling companies and their utilities. For someunderstanding of the subject brief, definitions are givenbelow for general Protocols,

PPP – Point-to-Point Protocol – A protocol for creating a TCP/IP connection over a series of transmission systems both synchro-nous and asynchronous. PPP provides connections for host tonetwork or between two routers. It also has a security mechanism.PPP is well-known as a protocol for connections over regulartelephone lines using modems on both ends. This protocol iswidely used for connecting personal computers to the internet.

SLIP – Serial Line Internet Protocol – A point-to-point protocolto use over a serial connection, a predecessor of PPP. There isalso an advanced version of this protocol known as CSLIP(compressed serial line internet protocol) which reduces overheadon a SLIP connection by sending just a header informationwhen possible, thus increasing packet throughput.

TFTP – Trivial File Transfer Protocol – A Bay Networks router’ssupport of TFTP allows a network management station todownload configuration information to a router or group ofrouters and retrieve information from a router via Site Manageror Control Centre. Bay Networks routers include client andserver implementations of TFTP, enabling efficient transmissionand receipt of files across the internet network. TFTP providesfile transfer capabilities with minimal network overhead.Although TFTP uses UDP to transport files between networkdevices, it supports time-out and re-transmission techniques toensure data delivery and provides no security feature.

FTP – File Transfer Protocol – FTP enables transferring of textand binary files over TCP connection. FTP allows to transferfiles according to a strict mechanism of ownership and accessrestrictions. It is one of the most commonly used protocolsover the internet. The Bay Networks router’s support of FTPenables a network management station to initiate router-to-host, host-to-router, and router-to-router data transfers over TCPvia Site Manager or Control Centre. This implementation supportsRFC 959 (File Transfer Protocol) to ensure that data is transferredreliably and efficiently. FTP is supported on all Bay Networksrouters and by all the router’s LAN, serial and ATM interfaces.

Telnet – Virtual Terminal Protocol – Telnet is a terminal emulationprotocol, defined in RFC854*, for use over a TCP connection.It enables user to login to remote hosts and use their resourcesfrom the local host. Bay Networks enhance router installationand maintenance by supporting Telnet, the simple remote terminalprotocol. Through incoming Telnet sessions, Bay Networksrouter’s Command Console Interface or the Technician Interfacecan be accessed by a local or remote terminal. Outbound Telnetsupport enables Technician Interface to also originate an outgoingTelnet session to another Bay Networks router or to other networkequipment that accepts inbound Telnet. This provides access toremote routers in non-routine situations when Control Centre,Site Manager, or SNMP is unavailable.

SMTP – Simple Mail Transfer Protocol – This protocol isdedicated for sending Email messages originated on a localhost, over a TCP connection, to a remote server. SMTP definesa set of rules which allows two programmes to send and receivemail over the network. The protocol defines the data structurethat would be delivered with information regarding the sender,the recipient (or several recipients) and, of course, the mail’s body.

HTTP – Hyper Text Transport Protocol – A protocol used to

transfer hyper-text pages across the world wide web (www).Hyper-text pages are complex documents that may integrateinto text, images, sounds and animations. Each page may alsocontain hyperlinks to other web documents.

SNMP – Simple Network Management Protocol – SNMP isthe standard protocol used to monitor and control IP routersand attached networks. This transaction-oriented protocolspecifies the transfer of structured management informationbetween SNMP managers and agents. An SNMP manager,residing on a workstation, issues queries to gather informationabout the status, configuration, and performance of the router.An SNMP agent, operating in each Bay Networks router, respondsto the queries issued by the manager and generates activityreports. In addition to responding to SNMP queries, the router’sSNMP agent software transmits unsolicited reports, referred toas traps, to the SNMP manager when events, such as the numberof network collisions, exceed user-configured thresholds.

UDP – User Datagram Protocol – A simple protocol that transfersdatagram (packets of data) to a remote computer. UDP providesan unreliable, connectionless datagram transport service for IP.This protocol is used for transaction-oriented utilities such asthe IP standard SNMP and TFTP. Like TCP, UDP works withIP to transport messages to a destination and provides protocolports to distinguish between software applications executingon a single host. Unlike TCP, however, UDP avoids the overheadof reliable data transfer mechanism by not protecting againstdatagram loss or duplication.

AP – Application level protocols – They are used on top ofTCP/IP to transfer user and application data from one origincomputer system to one destination computer system. These APmay be for file transfer protocol (FTP), Telnet, Gopher or HTTP.

TCP – Transmission Control Protocol – Like UDP, a protocolthat enables a computer to send data to a remote computer.Unlike UDP, TCP provides a reliable, connection-oriented,transport layer service for IP. Using a handshaking scheme,TCP provides the mechanism for establishing, maintaining andterminating logical connections between hosts. Additionally,TCP provides protocol ports to distinguish multiple programmesexecuting on a single device by including the destination andsource port number with each message. TCP provides reliabletransmission of byte streams, data flow definitions, dataacknowledgments, data re-transmissions and multi-plexingmultiple connections through a single network connection.

IP – Internet Protocol – IP is a connectionless datagram deliveryprotocol that performs addressing, routing and control functionsfor transmitting and receiving datagrams over a network. IP isthe underline protocol for all other protocols in the TCP/IPprotocol suite. IP defines the means to identify and reach atarget computer on the network. Computers in the IP world areidentified by unique numbers which are known as IPaddress. TCP/IP protocol is developed for local area networks(LAN) and internet applications and has become a standardprotocol for UNIX/LINUX.

ARP – Address Resolution Protocol – In order to map an IPaddress into a hardware address the computer uses the ARPprotocol which broadcasts a request message that contains anIP address, to which the target computer replies with both theoriginal IP address and the hardware address oftenly calledMAC address. Once a routing decision has been determined,the router forwards the packet to the next hop network, providingthe best path to the packets’ ultimate destination. To accomplishthis, the MAC-layer address of the next hop interface is addedto the datagram and the packet is forwarded out of the appropriaterouter interface. If the next hop MAC-layer address is not known,the router first broadcasts an ARP request packet to determine*RFC 854 is a Telnet or file transfer Protocol Specification.

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the MAC-address of the next hop interface. When the destinationwith the matching IP address receives the broadcast, it respondswith its MAC-layer address, which is entered in the originatingrouter’s cache for future use.

NNTP – Network News Transport Protocol – A protocol usedto carry USENET posting between News clients and USENETservers.

RARP – Reverse Address Resolution Protocol Server – A RARPserver allows hosts to obtain IP addresses from the router. Hostsadd to the network broadcast a RARP request, specifying itselfas the source and supplying its MAC-layer address in the frame’sDestination Hardware Address field. When the RARP serverreceives the RARP request, it enters an IP address in the RARPrequest destination IP address field, changes the message typeto a ‘reply’, and sends the packet back to the host that transmittedthe request, using the host’s MAC-layer address.

24.11.7 The OSI (Open System Inter-connection)seven layers models

A layering model is the most common way to divide aprotocol suite. Each layer defining a set of messageprotocol functions. In the present case it dividescommunication protocol to sub-parts and describe themindividually. Through OSI the communication process hasbeen divided into seven basic layers as shown in Table24.7 describing functions involved in communicationbetween systems. These layers define how the data flowsfrom one end of a communication network to anotherend and vice versa. The seven layers reference modelintroduced by ISO around 1980s has since undergonemany changes and modifications. The layers noted beloware however valid for our present discussions.

The top 3 layers – physical, data-link and networkdefine the components of the communication networkwhile the bottom 3 layers session, presentation andapplication represent the functions of the end system.The middle layer transport links the top and bottom layers.The overall communication process is thus divided into

7 pre-defined layers to simulate common developmentof individual components.

With the rapidly rising use of the internet, there is anurgency to develop mechanisms for accommodating moreProtocol Suites. Literally thousands of combinations ofprotocol suites can be created with the large domains ofavailable protocol systems. The main protocol functionsthat have found widespread use in the substationenvironment are noted in Table 24.8.

Some common definitionsBrief definitions of most commonly used terms on internetand functions of protocols are noted below for a generalreference,

World Wide Web (www) – To cope-up with the increasingsize and complexity of the Internet, tools have been devisedto help access the network to locate the desiredinformation. These tools are often called navigators ornavigation systems.

Uniform Resource Locators (URL) – A resource of theInternet is unambiguously identified by an URL, whichis a pointer to a particular resource at a particular location.A URL specifies the protocol used to access a serversuch as HTTP, FTP etc. as noted later and the location ofa file on that server.

Web Server – It is a software program on a Web hostcomputer that answers requests from web clients, typicallyover the Internet. All web servers use a language orprotocol to communicate with the web clients and iscalled Hyper Text Transport Protocol (HTTP) as notedunder protocols. All types of data can be exchanged amongweb servers and clients using this protocol, includingHyper Text Markup Language (HTML), graphics, soundand video.

Domain Name – This is the name that identifies a website.For example, “microsoft.com” is the domain name ofMicrosoft’s website. A single web server can servewebsites for multiple domain names, but a single domainname can point to only one machine. For example, AppleComputer has Websites at www.apple.com,www.info.apple.com, and www.store.apple.com. Each ofthese sites could be served on different machines. Eachdomain name (like www.electricalengineering-book.com)

Table 24.8 Possible combinations of Protocol Suites with OSIlayers

Internet Protocol Suites

Telnet

FTP

SMTP

SNMP

HTTP

TCP, UDPIPARP, RARP

Not specified

OSI-Seven layer models

Application 7

Presentation 6

Session 5

Transport 4

Network 3

Data-Link 2

Physical 1

Æ

Table 24.7 The OSI seven layer models

Layer No. Layer Responsibilities

1. Physical Basic hardware components for networksi.e. RS-232 specification

2. Data Link Frame format for transmitting frames overthe net, i.e. bit/byte stuffing, checksum,error control, flow control

3. Network Address assignment, packets’ forwardingmethods (routing)

4. Transport Transfer correctness

5. Session Establishing a communication session,security, authentication, i.e. passwords

6. Presentation Computers represent data in different ways(character, integer). The protocolstherefore need to translate the data to andfrom the local node.

7. Application Specifications for applications using thenetwork, such as, how to send a request,how to specify a file name over the net,how to respond to a request etc.

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is translated into a numeric internet address called IPaddress (like 194.56.78.3).

Internet – This is a global network of computers calledthe ‘Net’. The internet or ‘Net’ connects computers usinga variety of different operating systems or languageslike UNIX, DOS, Windows, Macintosh and others. Tofacilitate and permit the communication between thesesystems and languages, the language the internet uses iscalled TCP/IP. TCP/IP protocol supports three basicfunctions on the internet.

– Transmitting and receiving electronic mails– Logging onto remote computers the ‘Telnet’, and– Transferring files and programs from one computer

to the other (FTP)

Intranet – Some companies use the same mechanism asthe web to communicate within the company. In thiscase, this mechanism is called “Intranet”. These companiesuse the same networking/transport protocols and locallybased web servers to provide access to their companyprofile, product details, data sheets, application orwhatever. It is possible to hide confidential data or detailsfrom people other than authorized by using a specialequipment called a ‘Firewall’.

Firewall – A Firewall protects one or more computerswith Internet connections from access by externalcomputers connected to the Internet. A Firewall is anetwork configuration, usually created by hardware andsoftware, that form a boundary between networkedcomputers within the Firewall from those outside theFirewall. The Firewall can be configured using ‘proxies’or ‘socks’ to control the access. The computers withinthe Firewall thus, form a secured sub-network with internalaccess capabilities and shared resources that cannot beaccessed from outside computers.

Proxy Server – An HTTP Proxy is a special server thatallows an access to the Internet. It typically runs inconjunction with Firewall software. The Proxy Serverwaits for a request (for example from HTTP) from insidethe Firewall, forwards it to the remote server outside theFirewall, reads the response, and sends out the responseback to the client.

A single computer can run multiple servers, each serverconnection is identified with a port number. A ProxyServer, like an HTTP Server or an FTP Server, occupiesa port. A connection uses standardized port numbers foreach protocol. That is why the end user has to select aspecific port number for each defined Proxy Server.

HTTP Caching – It is an Application Level protocolused by the TCP connections between web browsers andHTTP Proxy Servers. Consequently, IP Datagramsexchanged between the web browsers and HTTP ProxyServers comprise HTTP data. Since HTTP Proxy Serversterminate and manage the HTTP connections, they seeand handle the HTTP data comprised in the IP Datagramsand they can store a local copy of HTTP data in aninternal cache.

Socks and Socks Server – Socks is a protocol whichdoes some form of encapsulation of Application Level

protocols (for instance FTP, Telnet, Gopher, HTTP). UsingSocks, the Application Level traffic between a systemrunning a Socks Client software and a system running aSocks Server software is encapsulated in a virtual Sockstunnel between both systems. Socks is mainly used bysystems within an Intranet in order to gain a securedaccess to systems located outside the Intranet.

A Socks Server acts as a relay between the systemswithin the Intranet and the systems outside the Intranet,thus hiding the internal systems from the external Internet.It is considered as one form of Firewall. A Socks Server(also called Socks Gateway) is a software that allowscomputers inside a Firewall to gain access to the Internet.A Socks Server is usually installed on a server positionedeither inside or on the Firewall. Computers within theFirewall access the Socks Server as Socks Clients toreach the Internet.

Protocol Gateway – A gateway converts conversationsfrom one protocol or communication language to another.Often RTUs or PLCs are used as gateways betweensubstations data and SCADA or DMS or EMS protocols.

Port (Virtual) – A computer on the internet using TCP/IP protocols uses various numbered ‘virtual’ ports todifferentiate between the various servers the computermay be connected to. For example – Telnet server isassigned port 23.

Port (Physical) – An interface on a computer to whichone can connect a device. Personal computers have varioustypes of ports. Internally, there are several ports forconnecting disk drives, display screens, and keyboards.Externally, personal computers have ports for connectingmodems, printers, mice, and other peripheral devices.

Remote Terminal Unit (RTU) – It is a stand alone smallcomputer on microprocessor system specifically designedfor real-time processing of input and output of data. TheRTU’s function is to control process equipment at theremote fields, acquire data from the equipment and transferit back to the master control centre (MCC). Under directionof the MCC, the RTU turns switches on & off, and opens& closes valves. Data acquisition is performed when theMCC scans the inputs provided by the RTUs orProgrammable Logic Controllers (PLCs).

Router – A ‘router’ is a computer that inter-connectstwo networks and routes messages intelligently from onenetwork to the other. Routers are capable to select thebest transmission path between networks.

24.11.8 Security to a SCADA system

To conceive and design a good SCADA system it isessential to focus on high reliability and redundancy ofits hardware and software systems. Equally important isto protect it from hackers and unscrupulous intruderswho may sabotage or corrupt the whole power networkvia the SCADA system causing disruption of power evena blackout and other damages. Large power networksthat may jeopardize normal life and make big news itemis a big lure to such people to play mischief and satisfytheir lust.

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To access an unknown network: This can be possiblethrough,

– Insider information – using this, one can access systemIED’s like protective devices, sensors and measuringinstruments and change their settings such as to renderthem redundant or behave erratic – make them operatewhen not needed, causing service interruption or stayimmune when actually needed, damaging the mainequipment they are protecting, generator, transformer,bus and power lines.

– Trojan Horse – the hacker may access the systeminformation through a backdoor

– Network analyser – a network analyser can be attachedwith the SCADA network and feed erroneouscommands to the IEDs or the SCADA system. It can(subject to the command of the hacker) result in

• Shutdown of a particular area or the whole network• Alter the metering or historical data• Use SCADA system as a backdoor to the corporate

IT system to extract confidential data such ascustomer credit and personal identify references.

Earlier misconceptions about securitySome misconceptions that utilities companies carriedinitially and which are carried still against such securitysystem can be the following,

– The earlier practice was to keep a SCADA systemseparate from corporate networks. The SCADA systemtherefore operated in isolation and was considered tobe immune from hackers and intruders. But it is notso today as corporate networks are usually associatedwith SCADA system to enable access to their engineersto monitor SCADA system from remote corporateoffices. The corporate network thus gets exposed tooutside networks and becomes vulnerable to an easyalien access. Due to integration, security controlsbetween the SCADA system and the corporate networkget impaired and slacken in their security ring.

– Similarly, vulnerability to the SCADA system fromhackers and intruders can emerge through thecommunication system between the SCADA and thecorporate communication network.

– With the advances in IT, to presume that a hacker orintruder not equipped with adequate technology maynot be able to invade through the intricate SCADAsystem is an ostrich ideology and undermines thecapabilities of today’s bright brains. Moreover,surveillance by such perversive minds to obtain ‘insiderinformation’ is not a very difficult task. More so whenthey are indirectly turned wiser through the publishedmaterials by the consultants and SCADA serviceproviders themselves who publicize their literatureand data through ‘Net’ and printed catalogues for thepromotion of their business. This information may beenough to provide guidance to the eagle eyes watchingout for such data/information.

– Corporate’s own websites are also a potential sourceof providing useful information about their IT system,names of important persons, their e-mail addresses andmuch more, as a soft gateway to break into the system.

– Similarly, there may be inadvertent lapses by theengineers and consultants while working out thenetwork architecture leaving out some soft areas foran easy access by the intruders. The most conspicuousweak link for hackers and intruders is the increasingnetworking of the SCADA system by way of

• Expanded use of public protocols to inter-connectIEDs and SCADA systems (e.g. TCP/IP overEthernet LANs/WANs*)

• Increased dial-in and network access to remotesites through public communication services(phones and internet)

Remedy

It is essential to secure the SCADA system for a safeoperation. Enough research has gone into identifying therisk areas a hacker or intruder may invade through andthe extent of damage it can cause to the SCADA systemand the power systems connected to it. A variety of toolsand techniques can be used to counter such invasions.Some such means are noted below for a general referenceto those associated with the SCADA system,

– A reference architecture illustrated in Figure 24.41gives a graphical representation of the access interfacesof a particular power organization for analysing thesecurity information. The box containing the substationLAN, router, firewall, local MMI, database server,RTUs and IEDs represent the information componentsinside the substation. External to the substation is theremote SCADA that interfaces with the substation byeither a dedicated channel or over the utility WAN.

– Distribution and energy management system (DMS& EMS) network operations also interface with thesubstation over the WAN and have access to thesubstation information. These systems can also havededicated channels to the substation, but they are notshown in the figure for graphical simplicity.

– Access from the Internet, other WAN and DMS/EMSnetwork operations over the Utility WAN representopportunities for information security threats that mustbe countered. Thus, information security for SCADAand automation systems requires the specification ofDiscretionary Access Control, Object Reuse,Identification and Authentication and Auditrequirements.

– There are several techniques and processes that canbe used to safeguard IEDs, RTUs, PLCs, controllers,communications processors, SCADA systems andvirtually every type of programmable digital deviceused in electric power systems control and protection.First and foremost for network security is to restrictaccess and call for user authentication and thensafeguard the communication packets from eagle eyesvia encryption and verification of packet transmissionand receipts.

* LAN – Local Area Network WAN – Wide Area Network

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Areas vulnerable to intrusions

– Excessive information by the utility companies onthe Net for the benefit of consumer exposes thecommunication network to the invaders

– Often SCADA system and corporate communicationnetworks are inter-linked exposing the SCADAnetwork to unscrupulous persons

– Inadvertent omissions while working out the SCADAarchitecture leaving out areas that an intruder canlocate and access through the SCADA system

Following are some broad measures that may be takento secure an IT system (with particular reference to aSCADA system).

Security measures

Identification and Authentication

– Meticulous and confidential allotment of useridentification (ID) numbers and passwords to theauthorized users and their close monitoring.

– Protection of password files– Similar allotment of names to SCADA files and

programs– Adequate checks and controls to access these files

and programs by authorized users only

Discretionary access control

– Periodic security checks to ensure the integrity andreliability of the SCADA system

– Take all such measures that provide a firewall at allvulnerable points that may lead to the integrity andreliability of the system from all external threats andintrusions

– Immediately locating and identifying the hacker orintruder as soon as he penetrates the network andremedying the same

– Design a security network architecture– Conduct a thorough risk analysis to assess the risk

and remedy that

ConclusionMost old systems have no security features. Such systemsneed to be upgraded and retrofitted with security systemsfor the integrity and reliability of the system. ISO 17799is a comprehensive set of controls comprising best practicesin information security and is essentially an internationallyrecognized generic information security Standard.

The above is a brief account of system security for areference to those in the field of EMS-DMS SCADAsystems. We have touched upon only the preliminariesof hacking and intrusions and their adverse consequenceson the integrity and reliability of an energy or distribution

Figure 24.41 A simplified SCADA hardware configuration on interconnected network for analysing security requirements(Source: Wise Owl™)

Utility WAN

Remote SCADA DMS and EMS

Database Server

IRIG-B Timing Wire

Local MMI

Router

Firewall

Substation ethernet LAN

Hard wire

Remote terminal unitRelay IED

IED

Instrument transformerswitchgear and other sensors

Instrument transformerswitchgear and other sensors

Instrument transformerswitchgear and other sensors

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List of formulae used

Capacitors for improvement of system regulation

Regulation = Voltage at no load – Voltage at full load

Voltage at no load(24.1)

Rating of series capacitors

kVAr = 3 12

C◊ ◊I X (24.2)

and voltage rating = I1 · XC.

I1 = line currentXC = capacitive reactance of the series capacitors per phase

Reactive power management

PE E

Z =

sin

sin s r

1

◊◊ ◊q d (24.3)

P = power transfer from one end of the line to thereceiving end per phase

Es = phase voltage at the transmitting endEr = phase voltage at the receiving end, in radial lines

and midpoint voltage, in symmetrical linesZ1 = surge impedance of the line

sin q = line length effect or Ferranti effect

d = load angle or transmission angle

PE E

X =

sin s r

L

◊ ◊ d (24.4)

XL = inductive reactance of the whole line length

Influence of line length

Velocity of propagation of electromagnetic waves

UL C

= 1

1 1(24.5)

L1 and C1 are the line parameters per phase per unit length

q p

l = 2

◊ � (24.6)

q = phase shift between the transmitting and receiving-end voltages in radians or degrees

p = 227

or 180∞ respectively

� = line length in km

l = wavelength in km

Voltage at the receiving end, when it is open-circuited,

EE

rs =

cos q (24.7)

Relevant Standards

IEC

60358/1990

60694/2001

60870-5-103/1997

61850 (part 1 to 4)

–

Title

Coupling capacitors and capacitor dividers.

Common specifications for high voltage switchgear andcontrolgear standards.

Telecontrol equipment and systems – transmissionprotocols.

Communication networks and systems in substations.

Information technology – Code of practice forinformation security management.

IS

9348/1998

12729/2000

–

–

–

BS

BS 7578/1992

BS EN 60694/1997

–

–

–

–

–

–

–

17799/2000

ANSI/IEEE-519/1993IEEE-824/1994NEMA/CP-1/2000

Relevant US Standards ANSI/NEMA and IEEE

Guide for harmonic control and reactive compensation of static power converters.Standard for series capacitors in power systems.Shunt capacitors, both LV and HV.

Notes1 In the table of relevant Standards while the latest editions of the Standards are provided, it is possible that revised editions have become

available or some of them are even withdrawn. With the advances in technology and/or its application, the upgrading of Standards is acontinuous process by different Standards organizations. It is therefore advisable that for more authentic references, one may consult therelevant organizations for the latest version of a Standard.

2 Some of the BS or IS Standards mentioned against IEC may not be identical.3 The year noted against each Standard may also refer to the year it was last reaffirmed and not necessarily the year of publication.

management SCADA system and the urgency of installingsecurity systems to protect these essential services. Fordetails on the subject and solutions of the problems onemay refer to the literature and international Standardspublished on the subject. Some such references andStandards are mentioned at the end of the chapter.

Today internet security is a big business. There areindividuals and consulting firms who can stand guard tosuch systems, identify vulnerable areas and suggestfirewalls and other measures to maintain integrity andprivacy to these networks. Most new systems nowincorporate security systems as standard.

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Line length effect or Ferranti effect

q p = 2 1 1f L C ◊ � (24.8)

Optimizing the power transfer throughreactive control

PVZ

= sin sin

per phaseo2

1◊ d

q (24.9)

Vo = nominal phase voltageNatural loading or surge loading of a line,

PVZo

o2

1 = per phase (24.10)

PP

= sin

sin oq d◊ (24.11)

Analysis of radial lines

Es = Vr cos qr + J Z1 · I1 · sin qr (24.12)

Es = phase voltage at the transmitting end.Vr = phase voltage at the receiving endqr = line length effect or Ferranti effect at the end of

the line, in degreesI1 = load currentZ1 = surge impedance of the line

Analysis of symmetrical lines

Es = Vm · cos qm + J Z1 · I1 · sin qm (24.13)

Vm = voltage at the midpoint of the lineqm = line length or Ferranti effect up to the midpoint of

the line

Further Reading

1 Central Board of Irrigation and Power, India (Indian NationalCommittee for Cigre), Electric Power Transmission at voltagesof 1000 kV and Above, Oct. (1984).

2 Central Board of Irrigation and Power, India, Static VArCompensators, Technical Report No. 41, March (1985).

3 Central Board of Irrigation and Power, India, Workshop onSeries Compensation in Power Systems, Nov. (1986).

4 Central Board of Irrigation and Power, India, Workshop onReactive Power Compensation Planning and Design, Dec.(1993).

5 Westinghouse Electric Corporation, Electrical Transmissionand Distribution, East Pittsburgh, Pennsylvania, USA.

6 Engbarg, K. and Ivner, S., Static VAr Systems for Voltage Controlduring Steady State and Transient Conditions, May 1981.Reactive Power Compensation Department, Sweden, May(1981).

7 Erinmez, I.A. (ed.), Static VAr Compensators, Cigre WorkingGroup 38.01, Task Force No. 2 on SVC (1986).

8 IEEE – Delhi Section, Advance Level Course on Reactive PowerControl in Electrical Power Systems, December (1984).

9 Kundor, P., Power System Stability and Control, McGraw-Hill, New York.

10 Lakervi, E. and Holmes, E.J., Electricity Distribution NetworkDesign, Peter Peregrinus, London.

11 Miller, T.J.E., Reactive Power Control in Electric Systems,John Wiley, New York (1982).

12 Prasad, J. and Ambarani, V., Static VAr Compensator forIndustries, BHEL, India, 59th R&D Session, Feb (1994).

13 Research Station, M.P. Electricity Board, Central Board ofIrrigation and Power, India, Series Capacitor Application toSub-transmission Systems Case Studies. Technical Report No.66, Nov. (1988).

14 Weeks, W.L., Transmission and Distribution of Electrical Energy(Design aspects), Harper & Row, New York.

15 Integrated Substation Automation using an EEM System, PowerMeasurement (a global company for energy informationtechnology).

16 Holstein, Dennis K., Substation Information Security, OPUSPublishing (2004).

17 Young, Michael A., SCADA Systems Security GSEC PracticalRequirements (v1.4b), Option 1 (2004).

18 SCADA systems and their security. Beacon – Institute ofElectrical and Electronics Engineers (Inc.), 21, No. 1, IEEEDelhi Section House Journal, (2002).

19 Understanding SCADA System Security Vulnerabilities, RiptechInc., Alexandria, Virginia, USA, (2001).

20 EMS-SCADA Overview, MICON Systems (http: www.miconsystems.com)

21 Jammes Antoine, intelligent LV switchboards, Schneider (MerlinGerin), Technical paper n∞186, June (1997).