24/881

System voltage regulation and improving power 24 quality

Contents 24.11.8 Security to a SCADA system 24/927 Relevant Standards 24/930 24.1 Capacitors for improving system voltage regulation 24/883 List of formulae used 24/930 24.2 Series capacitors 24/883 Further Reading 24/931 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 24/887 24.6.1 Objectives 24/888 24.6.2 Analysis of an uncompensated transmission line 24/889 24.6.3 Power transfer 24/890 24.7 Influence of line length (Ferranti effect) 24/893 24.8 Optimizing power transfer through reactive control 24/896 24.8.1 Line length effect (sin q): 24/898 24.8.2 Influence of load angle (sin d) 24/898 24.9 Dynamic and transient stability of overhead lines (Applications of reactive controls) 24/906 24.9.1 Auto-reclosure schemes 24/907 24.10 Switching of large reactive banks 24/908 24.10.1 Thyristor-switched capacitor banks (TSCs) 24/909 24.10.2 Thyristor-controlled reactors (TCRs) 24/910 24.10.3 Transient-free switching 24/910 24.10.4 Response of SVC on a fault or line disturbance of a transient nature 24/911 24.10.5 Combined TSC, TCR and fixed capacitor banks 24/911 24.11 Automation of power network through Supervisory Control and Data Acquisition (SCADA) System 24/912 24.11.1 Application of a SCADA system 24/914 24.11.2 SCADA implementation 24/915 24.11.3 Implementation of load shedding and restoration 24/920 24.11.4 EMS-SCADA: (Energy management solutions) 24/922 24.11.5 Serial data transmission to a control and automation system via communication interfaces 24/922 24.11.6 Introduction to general protocols 24/924 24.11.7 The OSI (Open System Inter-connection) seven layers models 24/926

System voltage regulation and improving power quality 24/883 24.1 Capacitors for improving 1To neutralize and reduce substantially the content of inductive reactance of the line. Refer to a simple system voltage regulation transmission network with series compensation, shown in Figure 24.1. Another important application of capacitors is to improve 2To alter the circuit parameters L and C, to reduce the the voltage regulation of a power supply system. The line impedance and hence the voltage drop, and also regulation of a power system at the receiving end is enhance utilization, i.e. the power transfer capability defined by of the line. 3To improve the far end or the load-side voltage, in % Regulation other words, the voltage regulation and the stability Voltage at no load – Voltage at full load level of the system. = 100 Voltage at no load ¥ (24.1) Notes 1 Unlike the above, a shunt capacitor alters the load current by Higher regulation will mean a higher voltage fluctuation offsetting the reactive component of the current (Figure 23.2) at the receiving end, resulting in poor stability of the by improving the load p.f. and altering the characteristics of the load. system. Regulation up to 3–5% may be considered 2A series capacitor has little application in an LV system due to satisfactory. To improve the regulation of a system, power the high content of line resistance and very little of inductance. capacitors can be used in series at the receiving end of Any amount of reactive compensation will scarcely influence the system. the performance of the line, as a result of the high content of IR, compared to IXL. Series and shunt capacitors both provide the same 24.2 Series capacitors degree of compensation. But it is the correct reactive support that provides a more stable system less prone to The basic purpose of series capacitance is to offset the load and voltage fluctuations. Thus a judicious choice content of excessive line inductance, reduce the line between the shunt and the series capacitors is required. voltage drop, improve its voltage regulation and enhance In the following our main thrust is to arrive at the most the power transfer capability and hence the stability level appropriate type and extent of reactive support to achieve of the system. It can accordingly find application at all a higher level of utilization of a power transmission or high-current and high-impedance loads such as distribution system, on the one hand, and more stability, on the other. • An electric arc furnace, where heating is caused by arc plasma between the two electrodes. The arcing makes the circuit highly inductive, besides generating 24.3 Rating of series capacitors unbalanced currents (third harmonics), due to different touchdown arc distances in the three electrodes which make it a non-linear impedance load. Referring to Figure 24.2, this can be expressed by • An induction furnace, where the heating is due to 2 kVAr = 3 ◊◊ IX1 C (24.2) eddy current losses induced by the magnetic field. • Electric arc and resistance welding transformers as G for 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 symmetrical GT line, as discussed later. Transmitting-side • It can also be applied to an HV distribution network voltage Es that has a high series inductive reactance to improve its receiving-end voltage. Primary transmission In all these applications a shunt capacitance is of little (Generator side) relevance, as it will not be able to offset the line inductive reactance, XL, with XC, and hence will be unable to contain the switching voltage dips at the load end in furnaces Series capacitors and also voltage drops during a change of load in a Receiving-end transmission or HV distribution network. A shunt capacitor voltage Er offsets the reactive component of the current (Figure 23.2) while the line voltage drop, for the same line current, Secondary remains unaltered. Series capacitors are therefore more transmission appropriate where voltage regulation is the main criterion, (Load side) rather than line loss reduction. Summarizing the above, the main functions of a series capacitance can be stated Figure 24.1 A simple transmission network with series as follows: compensation 24/884 Electrical Power Engineering Reference & Applications Handbook where platforms for each phase, which are adequately insulated I = line current. The value of line current to be from the ground. Figure 24.3 shows such an installation. considered for calculating the size of capacitor banks must take account of the likely maximum load variation during normal operation or the over- 24.4 Advantages of series load protection scheme provided for the capacitors, compensation whichever is higher. X = capacitive reactance of the series capacitors per phase. C (i) Automatic voltage regulation: Since the VAr of a And voltage rating = I · XC. 2 series capacitor µ IC , the voltage regulation is This rating will be much less than the nominal voltage automatic, as the VAr of the series capacitors will of the system. But since the series capacitors operate at vary with a change in the load current. When the the line voltage, they are insulated from the ground and voltage drops, the line current will rise, to cope with from each phase according to the system voltage. For the same load demand and so will rise the VAr of the this purpose, they are generally mounted on individual capacitors also providing an automatic higher VAr

GT X RXL C G Load side I Series Es Line Er parameters capacitors Figure 24.2 The single-line diagram for Figure 24.1

Figure 24.3 The installation of HV capacitor banks (Courtesy: Khatau Junker Ltd) System voltage regulation and improving power quality 24/885

compensation. When the voltage rises, the current 1 fh = will fall and so will fall the VAr compensation. No 2LC (Section 17.6.3) switching sequence, as necessary in shunt capacitors, p ◊ is therefore required for series capacitors. The above can also be expressed by (ii) They may be connected permanently on the system, as they compensate the line reactance, which is fixed, XC ffh = ◊ (Equation (23.11) though the load reactance may be variable, unlike XL shunt capacitors, which are to be monitored for their addition or deletion during peak and off-peak load where periods respectively. The costs of switching fh = natural frequency of the series circuit equipment and operational difficulties are therefore f = nominal frequency of the system low in series capacitors. L = natural reactance of the line per phase, (iii) They also provide the same degree of p.f. improvement including that of generator and load as the shunt capacitors and do so by the leading voltage XL =2p · f · L phasor rather than the current phasor. C = series capacitance per phase 1 Xc = Limitations 2p ◊◊ fC (a) It is not advisable to use them on circuits that have The frequency, fh, will occur for only a few cycles fluctuating loads or frequent inrush currents, such as during an abrupt change in the line parameters, such switching of motor loads. During a start the latter as during a switching operation or occurrence of a will cause an excessive current, Ist, and proportionately fault etc. (Section 17.6.3). To ensure that the circuit raise the potential difference across the capacitor units remains inductive under all conditions of load (Ist · XC) and over-load them in addition to causing variations and fault, to avoid a capacitive mode of higher dielectric stresses. Series capacitors for such operation and an excessive charging voltage the installations must be designed for very high voltages, content of XL must remain higher than XC (XL > XC). say, up to Ist · XC/1.5, which will not be economical. The natural frequency, fh, therefore has to be Also, protection against over-voltages will still be necessarily lower than the power frequency of the essential as a safeguard against a similar contingency, system (fh < f ). This is an unusual transient as discussed later. phenomenon that occurs in a series compensated (b) It is possible that the natural (sub-harmonic) frequency system which is adjusted for its natural frequency to (1/2LC , p Section 17.6.3) of a system with series maintain XL > XC and may have far-reaching capacitors may fall below the fundamental frequency implications. In the sub-synchronous range of a steam and render the system more prone to resonance. Now turbine generator this frequency may cause a resonance resonance may occur below the fundamental with the rotating masses of the turbo-generator rotor frequency. This may prove fatal under certain loading and generate electromechanical oscillations in the conditions and influence the source of supply in the rotor. This may assume serious significance in large following way: generators which have a number of natural mechanical 1Ferro-resonance effects frequencies of the rotating masses, in the range of An L-C circuit is more prone to ferro-resonance 10–25 Hz. This frequency may coincide with the effects during voltage fluctuations as a result of natural frequency of the system during a line saturation of the iron core, which may be of a disturbance and magnify the oscillations of the rotating transformer or an inductor coil. On saturation, the masses beyond desirable limits. If unchecked, these inductance reduces drastically and becomes more oscillations may continue to magnify and result in prone to resonance with the capacitance of the the shearing off of the weakest part of the shaft. circuit. Voltage fluctuations may occur due to Although rare, serious damages have occurred in switching operations, particularly of an unloaded earlier years, when the turbine shaft had actually line or load fluctuations (Section 20.2.1(2)). sheared off because of this phenomenon. Hydro- Although the line impedance will provide a turbine generators are less prone to such oscillations, sufficient damping effect to automatically attenuate as their natural mechanical frequency lies below 10 such a state, precautions are mandatory to avert Hz. The natural frequency of a series compensated the same. An inductive compensation, of the order system may not reach this level. of 40–50%, may be adequate to improve the system These oscillations can be damped with the use parameters and also avert a ferro-resonance effect. of filter circuits or by bypassing all or part of the A more realistic approach to the problem is possible series compensation during a line disturbance. if a mathematical model of the ferro-resonance is Similar techniques are adopted while protecting the developed and supplemented by experiments to series capacitors against fault conditions, as noted produce data to design an appropriate series in Section 26.1.2(2) and illustrated in Figure 24.4 compensation scheme. (Figure 26.10 redrawn). For critical installations it 2 Sub-synchronous resonance (SSR) is essential to first evaluate the likely frequencies of A series compensated network will have its natural the rotating masses and then more exacting measures frequency expressed by be taken to avoid a resonance. 24/886 Electrical Power Engineering Reference & Applications Handbook

Ic (fault) 12 3

G Er X 1 Series reactor to add to L R Receiving end line impedance Es I (fault) 2 Isolators 4 3 I (fault) c Effective current 6 4 Damping resistor through capacitors 5 and coupling circuit 5 Auxiliary saturating reactor is nearly zero I (fault) 6 Main saturating discharge reactor Ӎ An R–L damping circuit Ic (fault) I (fault)

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

If a large induction motor is switched on such a 1 When the line resistance, R, is significant compared system it is possible that its rotor may lock-up at to the line inductive reactance, XL, there will be a the sub-synchronous speed and keep running at limited use of series capacitors (XC) in view of a higher slips. This situation is also undesirable, as large content of I.R. See the phasor diagram in Figure it would cause higher slip losses in addition to 24.5(b). Also refer to Figure 24.5(c) when R is higher stator current and over-voltage across the insignificant. Now the receiving-end voltage, Vr, can series capacitors. be improved by offsetting the reactive component 3 System fault level with the use of series capacitors. Since the line impedance, R + J (XL – XC), will 2When R << XL: Now XC (Figure 24.6(a)) will offset reduce with a series compensation, the fault level the inductive component and improve the p.f., capacity of the system will rise. It should not matter if the of the system and also the receiving-end voltage, as fault level of the system is determined by the illustrated in Figure 24.6(b). This advantage is not impedance of the source of supply as a customary, X ignoring any other impedance of the circuit (Section I R L 13.4.1(5)). Moreover, such a situation is automatically averted through the protection of the series capacitors, as discussed below, by which the capacitors are bypassed during a line fault, the line restoring its original impedance, hence the G E V Load original fault level. Nevertheless, when it is required s r to limit the system fault level, inductive coupling circuits may be provided to reduce the fault to the desired level. This is also discussed below: The fault current can be limited by providing a damping circuit, such as a short-circuit-limiting (a) Circuit diagram of an uncompensated line.

inductive coupling, across the series capacitors, as I · R illustrated in Figure 24.4. This can be a combination of an R–L circuit. During normal operation this circuit will provide a high impedance and remain immune. On a fault, the high voltage across the Es capacitors will cause a heavy inductive current f I · XL flow through the coupling circuit, which will Vr neutralize the capacitive current through the capacitors and help keep the capacitors almost out I Ӎ (b) When ’R ’ is significant of circuit (IC fault IL fault), similar to a shorting E switch, as discussed later. The normal condition is s restored as soon as the fault condition is cleared. It may also be regarded as a filter circuit, as it f would also help to damp the system harmonics. I I · XL Vr 24.5 Analysis of a system for series (c) When ‘R ’ is insignificant compensation Figure 24.5 Receiving-end voltage phasor diagram on load, Consider a simple system as shown in Figure 24.5(a). in an uncompensated line System voltage regulation and improving power quality 24/887

X X I R L C occurring on the other power system or the grid to which this system may be connected. Series capacitors have also proved to be an easy tool of relieving an already overstressed distribution network to meet ever-growing load demands, particularly when it is not practicable to add another line for reasons of V G Es r Load cost or space.

24.6 Reactive power management

Figure 24.6(a) Circuit diagram of a series compensated line 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 HV supply system, and achieve optimum utilization and a I · R higher level of stability. LV systems In LV systems reactive control is provided Es to improve the load p.f. and hence its load-carrying f With series com capacity, as discussed in Chapter 23. This is achieved by pensation Vr Without series compensation offsetting the inductive content of the load current at the C receiving or the consumer end by the use of shunt · X L I I capacitors. Hence support the system by reducing line · X I Series losses and improving its active load current (I cos ) compensation 1 f Vr carrying capacity. Despite emphasis to control the p.f. at the distribution or the consumer end, it is not possible to Figure 24.6(b) Phasor diagram of the series compensated follow this rule to the desired extent, due to many system constraints. One is ignorance or callousness on the part of consumer. It is therefore essential to compensate the omitted uncompensated load at the secondary possible through a shunt capacitor. Accordingly, it transmission. may be noted that the difference between the HV and EHV systems (132 kV and above): In these compensated and the uncompensated receiving-end systems even a shunt inductive control may become voltages will be significant only when the content of necessary to offset the excessive charging currents, caused I · R is low, compared to I · XL. by the distributed leakage capacitances (C1’s) of the line, In certain distribution networks the natural I · R particularly during no-load or light-load periods. It is drop itself may be sufficiently high to cause a dip at essential to relieve the system, particularly the generating the receiving end more than desirable even when the source, from an unwanted burden of reactive load (Figure reactive component is fully compensated. 24.23). Figures 24.7(b) and (c) show the distributed and Consequently, such a distribution network may have equivalent single-line diagrams of an uncompensated to be operated underutilized or the size of the current transmission line illustrated in Figure 24.7(a). The carrying conductors may have to be increased to reduce distributed leakage capacitances C1’s cause the line-charging the value of R, and hence the content of I · R, and currents (ic1’s) even when the far end of the line is open thus raise the capacity of the line. It may thus be circuited. Figure 24.8 describes a normal current profile concluded that of such charging currents. Capacitors play a vital role in the management of • In smaller cross-sectional areas of the current carrying reactive control in power transmission and distribution conductors of the distribution network, i.e. for low- systems. With industrial growth and growing demand capacity networks where R/X is high, series L for power for public services, utilities and consumer needs, compensation may be redundant. efficient reactive power management has become all the • For higher cross-sectional areas, i.e. for high-capacity more desirable. In the following text, we broadly consider networks where R/X is low, series compensation L the purpose and application of reactive power will be useful. management. The design of a power transmission or We will notice subsequently that series and shunt distribution system is a different subject and is beyond compensation are complementary. What a shunt capacitor the scope of this book. Reference may be made to works cannot do, a series capacitor does and vice versa. On a by many authors, some of which are provided in the secondary transmission system, say up to 66 kV, a shunt Further Reading at the end of the chapter. compensation may always be necessary to improve the Some developing countries, where reactive power power factor, as the load would mainly be inductive. A management practices have not been predominant, for series compensation may become essential, to improve whatever reason, consideration of cost being one, may the stability of the system, to cope with load fluctuations, suffer from fluctuating voltages, flickering lights, high switching of non-linear loads and voltage fluctuations line losses, reduced capacity of the power lines and 24/888 Electrical Power Engineering Reference & Applications Handbook

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G Generator Y

Charging current (I B 0 Sending Line length Receiving end end

Figure 24.8 Charging current profile on no load in a transmission Lumped leakage line G capacitances voltage boosters and generation of harmonics (because (a) Distributed line leakage capacitances of magnetic cores and use of electronic circuits in such appliances), which further erode the p.f. and quality of Generator the power. transformer (Figure 13.21) Note The reactive power should not be carried over long distances for it L L L Io 1 1 1 L1 may cause higher voltage drops and steep voltage gradients, on the G one hand, and higher line losses due to higher line currents, on the other. Hence, it will affect the utilization capability of the entire system, including that of the generating source, transformers, overhead lines, cables and other line equipment.

V Es C1 C1 C1 C1 r 24.6.1 Objectives

i i i i The basic objectives of a reactive power management c1 c1 c1 c1 system can be identified by the following for LV and HV distributions:

(A) Quality of power (b) Distributed line parameters 1 Load balancing and reduction in negative phase sequence currents. In Section 16.12 we have discussed load X Io R1 1 balancing of two generators where more emphasis is placed on the active control of power through speed control of the prime movers rather than its field (reactive) control. Active load balancing is more appropriate for the optimum utilization of a machine rather than reactive X G Es c1 Vr control. But in the case of a power transmission or I distribution network it is the optimum utilization of o the available active power through efficient reactive power management that is more relevant. G A load unbalance is a common feature in a power (c) Equivalent circuit diagram on no load system, and can be the result of one or more of the following: Figure 24.7 Representing an open circuited transmission line •A higher neutral current in the LV distribution due to without compensation unequally distributed single-phase loads. • Saturation of power transformers as a result of periodic over-loading and load rejections. consequent over-loadings etc, leading to frequent trippings • Increased ripples in the rectifier circuits, causing and breakdowns. The active load current (I1 cos f) harmonics. becomes too low at low p.f.s. Frequent and wide voltage • Malfunctioning of some equipment, possibly because fluctuations lead to fusing of bulbs and failure of of a fault. fluorescent lights, besides requiring a voltage stabilizer • Oscillating torque in the rotating machines as a with each household appliance, such as TVs, air result of load variations and harmonics present in the conditioners, refrigerators, ovens and computers. system. All this increases the direct cost of the appliances, on • Feeding non-linear loads such as: the one hand, and additional burden on the already over- – Induction furnaces stressed lines, on the other, by permanent losses of such – Arc furnaces and arc welders System voltage regulation and improving power quality 24/889 – Steel rolling mills 24.6.2 Analysis of an uncompensated – Large motors with periodic loading transmission line – Thyristor drives – Railway traction which is mostly through d.c. drives (i) Current profile – And many loads which may have to be frequently A transmission line can be represented, as shown in Figure switched 24.7(b). In Tables 24.1(a) and (b), we show typical line All such loads generate harmonics and cause variations parameters for different system voltages and line in the fundamental power frequency of the supply configurations. Because of line charging capacitances, system leading to distortion in the sinusoidal waveform C ’s, between conductors, and conductors and ground, of the voltage. This distortion may affect the quality 1 as shown in Figure 24.7(a) (higher significance in HV of the supply system (voltage) beyond desirable limits. and EHV lines of 132 kV and above), and series inductance A non-sinusoidal and distorted supply system may L , there is a charging current, I , even at no load and adversely affect the different loads connected on 1 o even when the far end of the line is open-circuited (Figure the system, besides leading to outage of the system 24.7(c)). Figure 24.8 describes a normal profile for such itself. charging currents. This current rises with the rise in line 2 Maintaining a near-unity p.f. length and is highest at the generator end. As this 3 Maintaining the frequency to near constant by phenomenon is a function of system voltage, it is negligible suppressing the system harmonics. or nil in HV lines up to 66 kV. This current is totally 4 Maintaining the receiving-end voltage at almost the capacitive, ignoring the effect of line resistance, R . A rated voltage. 1 transmission line, being a high power transfer system, has a very low content of R (Table 24.1(a)). (B) Transmission of power 1 The magnitude of the charging current, Io, will depend upon the content of C1, which is a measure of line voltage, 1 Enhancing the steady-state power transfer capability size of the conductor, spacing between the conductors of the lines over long distances, or making short lines and between the conductors and the ground etc. Table capable of transferring larger powers. 24.2 provides the approximate values of charging current, 2 Improving the stability of the system by supporting Io, and charging power for a few system voltages with the voltage at key points. Without compensation, the different line configurations. The generated charging stability of the system becomes a limiting factor even reactive power, by the line charging capacitances (C1’s), for shorter line lengths and the system is rendered flows back to the generating source and has to be absorbed prone to frequent outages on small disturbances. by it, even on no load, or a part of it during light loads. 3 Reducing system oscillations and flickering caused It is a strain on the field windings of the generator, as the by voltage fluctuations and system harmonics as a machine under no-load or light-load conditions and with result of frequent and rapid changes in reactive power capacitive charging currents will have to operate under- demand, loss of load, loss of generation or a system excited, and under-excitation is not a healthy situation fault. Excessive voltage swings may cause tripping (see also Section 16.3.3) for a thermal turbo-generator of industrial drives and even system outages. High- because, speed SVCs (Static VAr Compensators, Section 24.10(2)) can overcome such situations by providing •A capacitive circuit magnifies the harmonic effects appropriate reactive power support during system when present in the system, as discussed in Section disturbances and maintaining a near-flat voltage profile 23.5.2, and gives rise to spurious voltages and currents, through the length of the transmission line. raising the normal V and I to Vh and Ich, respectively 4Providing voltage support when switching large (Equations 23.1 and 23.2). loads. •The stator windings are subject to over-capacitive 5 Improving voltage regulation: both over-voltages voltages as a result of this, and the end turns particularly (OVs) and under-voltages (UVs) are undesirable. An are endangered. OV may cause ageing of the equipment’s insulation • Reduced field current reduces the voltage generated, and can lead to a flashover or eventual breakdown of which may affect the system’s stability. the terminal equipment and line insulators. It may • The generator manufacturer can define the lowest also lead to saturation of power transformers operating excitation level below which the machine may be in the system. The transformers produce high currents, unstable. rich in harmonics, and cause ferro-resonance or sub- Figure 24.9 shows a typical output characteristic or synchronous resonances. A UV will result in higher reactive capability curve of a generator, illustrating the system loading than necessary and cause under- stability levels of the machine under different conditions utilization of the system capacity. of operation. The machine must operate within these In the following we consider the case of a transmission levels and the voltage profile within the specified voltage line, 132 kV and above, being more typical and complex limits, as noted in Table 24.3. for the purpose of reactive power control. Based on this, it would be easier to apply appropriate reactive control Example 24.1 Consider a 400 kV, triple-Zebra line, having a distributed to a distribution network and large inductive loads such 5 leakage capacitive reactance XC1 of 2.74 ¥ 10 W/ km from as an arc or induction furnace. Table 24.1(b). Then the charging power per phase per km, 24/890 Electrical Power Engineering Reference & Applications Handbook

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

Nominal Conductor Positive sequence components Zero sequence components voltage, Vr type R1 XL1 XC1 ZXX1 = LC11 ◊ R0 XL0 XC0 kV (r.m.s.) W /km W /km W /km WW/km W/km W/km

–2 –1 5 –1 5 765 Quad Bersimis 1.142 ¥ 10 2.619 ¥ 10 2.44 ¥ 10 252.8 2.633 ¥ 10 1.053 4.161 ¥ 10 (QB) –2 –1 5 –1 5 400 Twin Moose 2.979 ¥ 10 3.32 ¥ 10 2.88 ¥ 10 309.22 1.619 ¥ 10 1.24 4.46 ¥ 10 (TM) –2 –1 5 –1 5 400 Twin AAAC 3.094 ¥ 10 3.304 ¥ 10 2.82 ¥ 10 305.24 1.682 ¥ 10 1.237 4.37 ¥ 10 (TA) –2 –1 5 5 400 Quad Zebra 1.68 ¥ 10 2.544 ¥ 10 2.40 ¥ 10 247.09 9.133 0.950 3.73 ¥ 10 (QZ) –2 –1 5 5 400 Quad AAAC 1.566 ¥ 10 2.682 ¥ 10 2.29 ¥ 10 247.826 8.512 1.002 3.55 ¥ 10 (QA) –2 –1 5 5 400 Triple Zebra 2.242 ¥ 10 2.992 ¥ 10 2.74 ¥ 10 286.32 12.186 1.112 4.23 ¥ 10 (TZ) –2 –1 5 –1 5 220 Zebra 7.487 ¥ 10 3.992 ¥ 10 3.408 ¥ 10 368.846 2.199 ¥ 10 1.339 5.421 ¥ 10 (Z) –1 –1 5 –1 5 132 Panther 1.622 ¥ 10 3.861 ¥ 10 3.416 ¥ 10 363.169 4.056 ¥ 10 1.622 > 6 ¥ 10 (P)

Table 24.1(b)

Nominal Conductor Line inductance Line capacitance Velocity of Wavelength voltage, Vr Type propagation l = U/f X 1 L = L1 C = U = 1 XL1 1 2 f XC1 1 2 fX p ◊ p ◊◊ C1 LC11 a kV(r.m.s.) W/km henry (H) W/km n farad (nF) km/s km 765 QB 2.619 10–1 8.33 10–4 2.44 105 13.04 3.034 105 6.07 103 ¥ –1 ¥ –4 ¥ 5 ¥ 5 ¥ 3 400 TM 3.32 ¥ 10 10.56 ¥ 10 2.88 ¥ 10 11.05 2.927 ¥ 10 5.85 ¥ 10 400 TA 3.304 10–1 10.51 10–4 2.82 105 11.28 2.904 105 5.81 103 ¥ –1 ¥ –4 ¥ 5 ¥ 5 ¥ 3 400 QZ 2.544 ¥ 10 8.09 ¥ 10 2.40 ¥ 10 13.26 3.053 ¥ 10 6.11 ¥ 10 –1 –4 5 5 3 400 QA 2.682 ¥ 10 8.53 ¥ 10 2.29 ¥ 10 13.89 2.905 ¥ 10 5.81 ¥ 10 400 TZ 2.992 10–1 9.52 10–4 2.74 105 11.61 3.008 105 6.02 103 ¥ –1 ¥ –4 ¥ 5 ¥ 5 ¥ 3 220 Z 3.992 ¥ 10 12.70 ¥ 10 3.408 ¥ 10 9.34 2.904 ¥ 10 5.81 ¥ 10 –1 –4 5 5 3 132 P 3.861 ¥ 10 12.28 ¥ 10 3.416 ¥ 10 9.31 2.958 ¥ 10 5.92 ¥ 10 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.

2 load fluctuation and result in a line outage. These features, V1 PC1 = if not controlled, may render the system unstable. X C1 Overvoltages must be controlled within an acceptable 2 limit. Table 24.3 prescribes one such limit. P = 400 \ C1 5 To achieve the above, the charging power must be 2.74 ¥ 10 compensated at the generating end itself, and this can be = 0.584 MVAr/km achieved through a reactive power control as illustrated in Figure 24.11. Figure 24.12 illustrates general voltage (ii) Voltage profile and charging current profiles before a compensation and Figure 24.13 a desirable flat voltage profile that can be Since the charging current is capacitive in nature, the line achieved through a series compensation, discussed later. voltage drop at the far end would raise the terminal voltage on a no-load as shown in Figure 24.10. The charging current and rise in terminal voltage both at no-load or 24.6.3 Power transfer during an under-loading condition are undesirable. While the former would stress the generator windings, the latter It has been established that the active power transfer may cause a voltage swing during a load rejection or through a power system can be expressed by System voltage regulation and improving power quality 24/891

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1

ZXX

252.8 2315.0 1,747 1.81 2.40 1.036 309.22 517.4 747 0.80 0.56 1.074 305.24 524.2 757 0.82 0.567 1.082 247.09 647.5 935 0.96 0.67 1.03 247.826 645.6 932 1.01 0.70 1.082 286.32 558.9 807 0.84 0.584 1.045 368.846 131.2 344 0.37 0.142 1.082 W 363.169 48.0 210 0.22 0.051 1.063

estricted to about 400 km in length in r

5 5

5 5 5 5 5

5

10 10

10 10 10 10 10

10

¥ ¥

¥ ¥ ¥ ¥ ¥ ¥

and diminishes shar

2

1

r

/km

C

V

X

2.44 2.88 2.82 2.40 2.29 2.74 3.408 W 3.416

om excessive over-voltages due to capacitive charging. due to capacitive over-voltages om excessive

–1

–1 –1

–1

–1 –1 –1

–1

acteristics (approximate)

10

10 10

10

10 10 10

10

¥

¥ ¥ ¥ ¥ ¥ ¥

¥

1

/km

L

W

type

ypical basic line char

T

r

)

le 24.2

b

Charging reactive power is proportional to power reactive Charging

This reveals that on a 50 Hz system the phase displacement betw This reveals

Ta

Nominal Conductor X voltage, V voltage,

kV (r.m.s. 123 4 5 6 7 8 91011

765 QB 2.619 400 TM 3.32 400 TA 3.304 400 QZ 2.544

400 QA 2.682 400 TZ 2.992 220 Z 3.992 132 P 3.861

* Constant for a particular line irrespective of its length (Section 24.6.3). a generator and other connected equipment fr b 100 km. Accordingly, an uncompensated line should be r Accordingly, 100 km. 24.5). 24/892 Electrical Power Engineering Reference & Applications Handbook

90% generator Prime mover stability limit capacity

0.95 0.95 0.90 0.90 0.85

Per unit 0.85 Lagging pow

0.8 active power 0.8 0.75 0.75

0.7 0.7 er factor

Leading power0.6 factor 0.6

0.5 0.5

0.4 0.4

Rotor heating capacity 0.2 0.2

0.2 0.4 0.6 0.8 1.0

Exiter-control limit

1.0 0.8 0.6 0.4 0.2 0 0.2 0.4 0.6 0.8 1.0 Per unit Per unit Reactive power Reactive power (condenser mode) (generator mode)

Leading mode Lagging mode (field underexcited) (field overexcited)

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

Table 24.3 Permissible voltage variations during temporary X I R X1 CC system disturbances o 1

Nominal voltage Vr Rated maximum Rated minimum stability level stability level a b kV (r.m.s.) kV (r.m.s.) kV (r.m.s.) X G Es C1 Vr

765 800 728 Io 400 420 380 220 245 198 132 145 122 G a Figure 24.11 An open circuited series compensated transmission As in IEC 60694 (since withdrawn but we have retained it for line reference) b As in Manual on Transmission Planning Criteria, CEA (Central Electricity Authority). EEsr ◊ P = ◊ sin d (24.3) Z1 ◊ sin q I o The expression is free from p.f. A change in p.f. (cos f), however, will adjust the torque angle, . The higher the Es d p.f. (low f), the, greater will be the torque angle d and vice versa. For more details to arrive at the above derivation refer to the Further Reading at the end of the chapter. Assumption – that the line is lossless, i.e. R1 is

Io ·(XL–XC1) negligible. Vr where P = power transfer from one end of the line to the Figure 24.10 Receiving-end voltage rises on no-load receiving end per phase System voltage regulation and improving power quality 24/893

distribution authorities of that country, on the basis of conductor configuration, spacing between them and the ground. Typical data for a few voltage systems have been provided in Tables 24.1(a) and (b). sin = line length effect or Ferranti effect, discussed 1 q Vr later 2 = in radial lines this is determined for the entire Vr q

s length of line while for symmetrical lines, it is

E 1.0 /

/

r O calculated up to the midpoint, i.e. it refers to I V q/2 d = load angle or transmission angle. This is the torque angle between the receiving-end and transmitting end voltages, and is responsible for the required power transfer from the transmitting end to the I o receiving-end. 3 Note 0 This should not be confused with Dq as used in Section 16.10 in Sending Length of line Receiving connection with the paralleling of two generators. There it represented end end the electrical shift between the rotors of the two machines or supply 1 – Vr profile without compensation. buses. If it is not eliminated, it will cause a circulating current between the two machines or the buses when running in parallel 2 – Vr profile with the use of series capacitors. and will add to their heating. 3 – I charging current profile. o For short lines say, 200–300 km, for a 50 Hz system Figure 24.12 Voltage and current profiles when the line at sin Ӎ (in radians) the far end is open-circuited q q e.g. for a 250 km, 400 kV line, as considered earlier,

Io · XCC from Table 24.2, for line type TZ, –3 q = 59.85 ¥ 10 degree/km = 14.96∞ for 250 km Es and sin q = 0.258 In radians = p = 1.045 10–3 per km or 0.261 Vr q 180 ◊ q ¥ for 250 km (both are almost the same) 2 and q = p ◊ as in Equation (24.6) Io · X L l Then from Equation (24.8) noted later, Figure 24.13 Receiving-end voltage is flattened with the use of series capacitors L1 Z sin = ◊◊◊ 2p fLC 11 ◊ 1 q C1 E = phase voltage at the sending end s = L · 2 f · Er = phase voltage at the receiving end in radial lines 1 p (lines connected to single source of supply or = XL, i.e. the inductive reactance of the entire generation) and midpoint voltage in symmetrical line length. lines. (Symmetrical lines are those which are fed from both ends such as when the far end is connected and Equation (24.3) will become to a power grid.) Z = surge impedance of the line (SIL) EEsr ◊ 1 P = ◊ sin d (24.4) X L L1 = For short lines, this is a very useful derivative. C1 = constant for a particular line, irrespective of its length, although L and C will rise with the line 24.7 Influence of line length length (L = · L1 and C = · C1, if is the length of the line). (Ferranti effect) where L1, C1, and R1 are the line parameters, per phase The velocity of propagation of electromagnetic waves per unit length. In our subsequent analysis, we have and the line length have a great influence over the capacity ignored R1, being negligible. The standard line parameters of power transfer through a line under stable conditions are normally worked out for different system networks and also define the quality of the receiving-end voltage. operative in a country by the power transmission and The electromagnetic waves (electricity) travel with great 24/894 Electrical Power Engineering Reference & Applications Handbook speed, close to the speed of light (Section 17.6.6) and of the generator, or the bus to which the receiving end hence have a very long wavelength. Since may be connected, is termed the Ferranti effect. It constrains the line length within certain limits to transmit = U power under stable conditions, as discussed later. l f This phase shift (q) for a particular line length can be where calculated as follows: l = wavelength in km 2 q = p ◊ (24.6) 1 l U = (24.5) LC11 where q = phase shift between the transmitting-end and the =Velocity of propagation of electromagnetic waves receiving-end voltages, in radians or degrees, Ӎ 3.008 105 km/s for 400 kV line TZ (as determined ¥ depending upon the value of p considered, i.e. in Table 24.1(b) for the different line parameters considered). = 22 or 180 respectively. p 7 ∞ 3.008 10 5 = ¥ \ l 50 = line length in km. 3 For the various HV and EHV networks and their line = 6.02 ¥ 10 km parameters considered, q is calculated in Table 24.2 and The normal line lengths may vary from 200 km to 500 the voltage at the receiving-end, when it is open-circuited, km. As a result, the electromagnetic wave is able to travel scarcely a small fraction of its one full wavelength, Er cos q = Es (Figure 24.15) up to the far end of the line (Figure 24.14). The Es instantaneous voltage at the receiving-end therefore is Or Er = (24.7) never in phase with the voltage at the sending-end (Figure cos q 24.15). This phase displacement, which is caused neither For the 400 kV, TZ line considered above, Er, for a by the p.f. nor by the mechanical positioning of the rotor 400 km line length, = 400 59.85 10–3 = 23.94 . Receiving-end voltage q ¥ ¥ ∞ Er rises with q EEss = (E ) sin t \ Er = = s max w cos 23.94∞ 0.914 = (Es)max sin q Es(max) = 1.094 Es

Sending end The Ferranti effect therefore, raises the receiving-end voltage Es voltage and becomes a potential cause of increased voltage (q = 0) q fluctuations when existing in the system, similar to a 400 km E cos capacitor magnifying the harmonic quantities. The longer r q the line, the higher will be the voltage rise at the receiving- end. This will cause wider voltage fluctuations during load w t variations, particularly during light loads and load rejections. Beyond a certain line length, this effect may even render 3 l = 6.02 ¥ 10 km the line unsuitable for the safe transmission of power. For 2p radians or 360∞ very short lines, however, the effect may be negligible and Illustrating one wavelength may be ignored. The line length is therefore chosen so that the receiving-end voltage is maintained within the Figure 24.14 Phasor position of sending-end and receiving- permissible limits under all conditions of its far-end end voltages in an overhead line loading. Thus the receiving-end voltage is influenced by three factors: Er • 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 the I r line parameters. Since q 2 I p s Es q = ◊ l Figure 24.15 The line length effect even when the sending-end 2 f and receiving-end voltages and currents are maintained = p at unity p.f. U ◊ System voltage regulation and improving power quality 24/895

Vm = Em = Es Ê XL ˆ Es Er = 2fLC or 1 p 11◊ Á X ◊ ˜ (24.8) Ë C1 ¯ or q µ LC where l l L = L1 · and /2 /2 C = C1 · Figure 24.16(a) Series compensation by sectioning at the midpoint of the line Note Generally, an HV distribution network has a very short length (), 200 less than 10–15 km. Moreover, the leakage capacitance (C1) for system voltages up to 66 kV is almost negligible. The Ferranti effect is therefore not applicable to a distribution network. Stable power n For the same system frequency, the Ferranti effect o ti a transfer s can be reduced by n e p • Sectioning or sin effect: Line length compensation m d o c can be achieved by sectioning, i.e. by dividing the t in o line into two or more sections. This method indirectly -p 100 id

reduces the physical length of line ( ). Each section (%) M t compe ou ns now operates as an independent line and is max th a i tio compensated through series capacitors and shunt P W n reactors (as shown in Figure 24.23) controlling the voltage within the required limits, at all such sections since

EEsr ◊ P = ◊ sin d Z ◊ sin q Maximum power transfer is possible when d = 90∞. If the line is compensated, say, at the midpoint, as 045∞ 90∞ 180∞ shown in Figure 24.16(a), then the maximum power Load angle (d) transfer will improve to Figure 24.16(b) Rise in power transfer with mid-point compensation EEsm◊ d Pm = ◊ sin Z sin q 2 2 ◊ 2 be resorted to where series compensation at the far where Pm = compensated power transfer at the midpoint. end may not be adequate to restore the desirable level of line stability (particularly during light loads and Es = Em = Vm, which is the mid point voltage and load rejections). Such a situation may arise when the is held constant line length exceeds 300 km or so (Table 24.4). It is a different matter that such a situation will seldom arise. Zm, qm and dm are midpoint parameters and Power is rarely transported over very long distances Zm = Z/2 and through radial lines. A transmission line is normally symmetrical, as its far end will generally be connected qm = q/2 to a power grid at less than 1000 km or so. However, = /2 if such a situation arises, sectioning would be one viable dm d solution. 2 V 2 • Reducing the electrical line length by reducing the P = ◊ m sin d \ m ◊ product LC (Equation (24.8)). Z sin q 2 ◊ 2 X L = L = 2 P sin d 2p ◊ f ◊◊max 2 1 Maximum power is doubled by a midpoint C = 2p ◊◊ fX C compensation and occurs at d = 180∞, as shown in Figure 24.16(b). Thus by changing the location of the X LC = 1 L line compensation the utilization capacity of the line \ 2p ◊ f XC can be altered. For a midpoint compensation, the line can operate stably up to d/2 or so, i.e. at about 90∞. This product can be reduced by reducing XL, using This is a costly and cumbersome solution, and may series capacitance with a reactance XC¢ , which will 24/896 Electrical Power Engineering Reference & Applications Handbook

110 reduce XL to XL – XC¢ . This is where reactive control plays a major role. By meticulous reactive power management, the Ferranti effect can be controlled and the electrical line length increased to the desired level. 108 It is a different matter that the electrical length of the line cannot be raised infinitely, for reasons of stability, 106 as discussed later. s

To apply the corrective measures to limit the Ferranti of E

% 104 effect it is essential to first study its over-voltage (OV)

as

status at the far end of the line. Consider the earlier r

E system TZ of 400 kV 50 Hz and draw a voltage profile 102 as illustrated in Figure 24.17, for the voltages worked out as in Equation (24.7), at different lengths of the line. The voltages, for the sake of simplicity, are also 100 shown in Table 24.4. 050100 150 200 250 300 350 400 From the voltage profile it is evident that up to a Line length in km line length of almost 250 km the over-voltage at the Figure 24.18 Voltage profile of a 400 kV/400 km symmetrical far end is quite acceptable. For greater lengths than line on a no-load illustrating the Ferranti effect this, the far-end open-circuit voltage will rise beyond acceptable limits and may damage the line insulators and the terminal equipment. Moreover, during a line line length. (Figure 24.18.) In other words, such lines disturbance or load variation this voltage fluctuation can automatically transmit power, within permissible may assume more dangerous swings. Generally, a parameters, up to twice the length of a radial line, transmission line is connected through a power grid which is fed from only one end. In such cases, it is where more than one supply source may be feeding only the midpoint voltage that is more relevant and the system. When this is so, lines are called symmetrical must be considered for the purpose of Ferranti effect. as they are fed equally from both ends. The far end In the first case, if we had considered a safe line point shifts automatically to the middle of the line, length of 250 km, this would become 500 km for a diminishing the Ferranti effect, doubling the electrical symmetrical line. Figure 24.18 illustrates such a condition. Depending upon the length and type of 110 line, a line length compensation may be required. Most transmission lines are seen to be within permissible lengths and only a few may require such 108 a compensation. Nevertheless, it may be worth reducing the phase displacement between Er and Es to less than 15 electrical, to further improve the quality and 106 ∞

s stability level of power transmission.

of E of 104

% 24.8 Optimizing power transfer as

r E 102 through reactive control

Reactive power pulsates up and down averaging to zero 100 and therefore contributes nil to power consumption. It can 050100 150 200 250 300 350 400 be positive when being supplied or negative when being Line length in km received (consumed). Since the reactive power falls in quadrature with the active power, it is usually denoted as Figure 24.17 Voltage profile of a 400 kV/400 km radial line on a no-load illustrating the Ferranti effect ‘Q’ and the active power as ‘P’. Transmission and distribution of reactive power reduces the active power. As P + JQ is pre-determined, any content of Q will only Table 24.4 Far-end voltage, due to the Ferranti effect, in a 400 kV TZ type line, at different line lengths reduce P. Since reactive power is an inherent feature of an a.c. system it cannot be negated but its influence can be minimized by adopting to meticulous reactive power Es Line q from cos q Vr = management techniques as discussed below. cos q km Equation (24.6) in % of Es To transmit power over long distances is the basic and Table 24.2 requisite of economical transmission. Let us study Equation (24.3). If we are able to maintain a unity p.f. between the 100 5.985∞ 0.995 100.5 transmitting and receiving ends, then for a lossless line 200 11.97∞ 0.978 102.2 250 14.96 0.966 103.5 ∞ Es = Er = Vo 300 17.955∞ 0.951 105.1 400 23.94∞ 0.914 109.4 Under such a condition, the line will maintain a unity System voltage regulation and improving power quality 24/897 p.f. at all points of the line and the reactive power voltage at the transmitting end by an angle q, due to the generated, due to the distributed line charging capacitances Ferranti effect and that effect is considered in the above (C1), will be offset by the reactive power absorbed by derivation. Refer to Figure 24.15 for more clarity. In the 2 the distributed line inductances (L1). The generator is now above equation the element Vo /Z1 is an important not unduly stressed by the reactive power feedback, i.e. indicator of the power transfer capability of a line, and is 2 termed the natural loading or surge impedance loading Vo 2 (P ) of the line, i.e. = IXo ◊ L1 o XC1 2 2 where reactive power generated = VXo / C1 per phase Vo Po = per phase (24.10) per unit length and reactive power compensated (absorbed) Z1 2 = IXo ◊ L1 per phase per unit length. Io is the capacitive charging current Such a line is said to be naturally loaded and this assumption is true only when the power is being Vo transmitted at unity p.f. and there is a total balancing of or = XXC1 ◊ L1 Io reactive powers. Since Z1 is constant for an uncompensated line, so is Po, irrespective of its length. The magnitude of 1 this will depend upon the line voltage, size of conductors = ◊◊◊ 2p fL 1 and the spacings between them and from the ground 2p ◊◊ fC 1 (these parameters decide C1 and L1 and hence Z1). It is also an indicator of a normal loading capacity of a line. L1 = = Z1 The recommended practice is to load an uncompensated C1 line to near this value or a little above when the line is a little shorter, or a little less when the line is longer to (Z1 is termed the natural or surge impedance of the line SIL) retain the level of stability. Also refer to the load curves The voltage will now maintain a flat profile from the in Figure 24.19 for more clarity. transmitting end through the receiving end and all the To optimize this power transfer through reactive control insulators or terminal equipment would be equally stressed. let us study Equation (24.10) for the parameters that can If Vo is considered as the nominal phase voltage of be varied to achieve this objective. The active power the system then Equation (24.3) can be rewritten as transfer will depend upon the following factors: 2 • Nominal voltage of transmission (V ) is a policy decision Vo sin d o P = ◊ per phase (24.9) of a country, depending upon the likely power loading Z1 sin q of such lines and future power plans. Generally, the The concept behind the above equation is that the voltages levels of voltage, Vr, for primary and secondary and the currents, at the transmitting and receiving ends transmissions are gradually increasing to cope with are maintained at the same p.f. The voltage at the receiving growing power demands. A typical system of transmission end, however, will shift in phase with respect to the and distribution is illustrated in Figure 23.1.

1.0 1 Uncompensated 2 Partially compensated 3 Fully compensated

s

E

/

r V 0.5 123

0 1.0

Natural load (P /P0)

Figure 24.19 Capacity utilization load curves with and without compensation 24/898 Electrical Power Engineering Reference & Applications Handbook

• Load to be transferred, keeping suitable margins for Rewriting equation (24.9), a future increase in demand. • Likely expected load variations and p.f. of the load Po P = ◊ sin d (24.11) (which may be based on experience). sin q • Line length effect or Ferranti effect, sin , that will q For the system to remain stable under all conditions of determine the optimum line length which will also loading, switching, or any other line disturbances it is depend upon whether it is a radial or a symmetrical essential that an uncompensated line is loaded at much line. below this level. Otherwise disturbances of a minor nature • Surge impedance of the line, Z . 1 may result in undamped oscillations, and may even swing • Angle of transmission, . d the receiving-end voltage beyond acceptable limits. It Equation (24.3) defines the active power as independent may even cause an outage of the system. It is therefore of p.f. However, depending upon the p.f. of the load, this not practicable to operate an uncompensated line to its will adjust the load angle d. The larger the angle of optimum level. For this we will analyse this equation for transmission, the higher will be the power transfer. Figure sin q and sin d as follows. 24.20 illustrates the power transfer characteristics of a 250 km line selected from Table 24.5. 24.8.1 Line length effect (sin q ) The element P /sin can be considered as the steadystate 4 o q stability limit of the line, say Pmax. A line length 3.87 compensation can improve the voltage profile and hence 3.74 the power transfer capability of the line as follows. Figure 24.19 illustrates three power transfer or load 3.35 curves: 3 Curve 1: without any compensation, the voltage profile sags on small load variations and is not capable of 2.74 transferring even a natural load. Curve 2: with partial compensation, the voltage profile improves and the line is able to transfer more load than 2 above, but less than its natural loading. Voltage still sags 1.935 but the swing is more tolerable.

0

P Curve 3: The line is fully compensated. The voltage

/ P profile tends to be flat and the line is capable of transferring even more than the natural load without an appreciable sag in the voltage profile. 1 24.8.2 Influence of load angle (sin d ) A study of various systems has revealed that the load angle for an uncompensated line should be maintained at about 30∞ only. This means that an uncompensated 0 15 30 45 60 75 90 120 150 180 line may be loaded to just nearly half its steady-state Load angle (d) level to retain a high level of stability during load 123 fluctuations, particularly during light loads or load p radians rejections, switching of large inductive loads or any type of minor or major line fault.

P /P0, considered for a 250 km radial line length as per Table 24.5. When the line is compensated, and a near-flat voltage profile can be ensured so that during all such disturbances d P/P0 Stability level the receiving-end voltage will stay within permissible 00 limits, the load angle can be raised to 45–60∞ to achieve 15 1.000 1 Stable region a high power transfer. Of all the above parameters, system voltage is already 30 1.935 predefined and considering that it cannot be changed, 45 2.740 2 Stable when series compensated the only parameters that can be altered to optimize P are Z1 and q. Both parameters can be altered to any desired 60 3.350 Not so stable on severe line limit with the application of reactive power controls, 75 3.740 3 disturbances, even after a subject to series compensation 90 3.870 • The thermal capacity of the line conductors and • Retaining the stability limit of the system thus Figure 24.20 Variation in load transfer with change in transmission modified. angle d After we have assessed the optimum power level it System voltage regulation and improving power quality 24/899 becomes easy to decide the type and amount of reactive P = active load power control required to achieve this level, assuming Q = reactive load that the lines can be loaded up to their thermal capacity R1 = line resistance per phase. It has been ignored and and the optimum power derived above can be attained. the line is considered lossless Our main objective will now be to arrive at the stability Z1 = surge impedance of the line level of the system and the parameters that define this. As noted above, the stability level defines the maximum The voltage stability of a system is the measure of power that can be transferred through a line without voltage fluctuations which must remain within permissible causing a voltage fluctuation and angular difference limits during load fluctuation or rejection or other line beyond acceptable limits, or a consequent outage of the disturbances and even temporary faults. We may therefore line, during a load variation, or a temporary line solve the above equation for Vr and P, to study the disturbance. It should, in fact, maintain its continuity behaviour of the system under varying load conditions, even during a fast clearing of a major fault. To determine P. As there are two more variables, load p.f. and the line length, which will influence P and Vr, different sets of the effects of Z1 and q on the receiving-end voltage and consequently the transfer of power, P, within stable limits load curves can be drawn as illustrated in Figure 24.21, we will study the voltage equation of a lossless for different line lengths at different p.fs. (at near unity, to obtain the best performance). From a study of these transmission line (considering R1 = 0, for an easy illustration), feeding a load P at a p.f. cos curves one can identify the most appropriate line lengths f. which can extend the highest level of stability to the system. For example, set ‘a’ of curves are more 1 Radial lines ideal compared to set ‘b’, which correspond to very The transmitting-end voltage in terms of line parameters long line lengths, compared to the ideal line lengths of can be represented by set ‘a’. After identifying the likely line lengths we can then Es = Vr cos qr + JZ1 · I1 · sin qr (24.12) study the most appropriate p.f. at which the load must be where transmitted to maintain the highest level of stability. For Es = phase voltage at the transmitting-end our purpose, parts of the curves that lie near the rated Vr = phase voltage at the receiving-end voltage, say, within Vr ± 5%, alone are relevant for study. qr = line length effect or Ferranti effect at the end of the The line will perform best at p.fs. very near to unity and line, in degrees cause the least possible voltage fluctuations by maintaining I = load current a near-flat voltage profile over reasonable variations of load. Leading p.fs. are not considered for reasons of PJQ – = capacitive overvoltages. Vr

Lagging p.f. Line length Unity p.f. much longer than ideal Open end voltage Leading p.f. (Set ‘b’ curves) high to very high, Natural load out of stable limits Operating Open end voltage region within permissible limits 1.0 Po

Non-operating region

Leading p.f. Ideal line length

s

r

V E Unity p.f. according to line parameters (Set ‘a’ curves) Lagging p.f.

P Pmax P o P – Diminishes (referring to only 1.0 P P0 0 operating region) and lines operate underutilized.

Figure 24.21 A comparative study of load transfers for different line lengths at different p.fs. for an uncompensated line 24/900 Electrical Power Engineering Reference & Applications Handbook Inference The power factor can be improved with the use of The voltage stability level diminishes with an increase shunt capacitors at the load points or at the receiving end in the line length. For very long line lengths, the far-end as discussed in Chapter 23. It is not practical to have a voltage may swing from high to very high values during near-fixed loading for all hours of the day. Moreover, there load variations, rendering it unsuitable for operation near may also be seasonal loads which may upset the parameters the maximum load transfer level. During light loads too considered while installing the capacitor banks. Such a the steeply rising voltage profile may cause a high-voltage situation is overcome by readjusting the reactive needs swing on a small load variation. A load variation therefore of the line by providing switched capacitor banks a few will cause wide to very wide voltage fluctuations and of which can be switched-in or switched-out, depending render the system unsuitable rather than unstable for a upon the load demand. The switching may be automatic power transfer near the required level. For transfer of a with the help of a p.f. correction relay (Section 23.15). load under stable conditions the line lengths of the uncompensated lines will be too short and hence will not Influence of line length (Ferranti effect) be economically viable. We will seek a solution to these For each p.f. and line length the curve Vr versus P describes problems with the help of these curves which will provide a certain trajectory. Maximum power can be transferred an introduction to the utility of reactive power controls only within these trajectories. Each line length has a to improve the power transmission capacity of a line and theoretical optimum level of power transfer, Pmax, which its quality through the following discussion. is defined by Po /sinq. In Table 24.5 we have worked out these levels for different line lengths, for the system Influence of PF considered in Example 24.1. A line can be theoretically loaded up to these levels. • The power transfer capability of the line rises as the But at these levels, during a load variation, the far-end p.f. swings towards the leading region and diminishes voltage may swing far beyond the desirable limits of V as it swings towards the lagging region. Since a power r ± 5% and the system may not remain stable. With the supply system is not run at leading p.fs. for reasons use of reactive control it is possible to transfer power at of dangerous over-voltages that may develop (as a the optimum level (P ) and yet maintain the far-end result of overexcitation of the capacitors, Section 23.13) max (or midpoint in symmetrical lines) voltage near to Vr and across the terminal equipment it is advisable to run have a near-flat voltage profile. the system as close to unity p.f. as possible. Moreover, the field system of the generating machines is also Reactive control can alter the line length (µ LC ) designed for maximum operation at lagging p.fs. only, to the level at which the system will have the least possible as discussed in Section 16.4. At leading p.fs. (after a swings. It is evident from the curves of Figure 24.21 that certain limit) (see Figure 24.9) there is a possibility an uncompensated line of a much shorter length may not of its field system losing control and becoming be able, to transfer even its natural load (Po) successfully. ineffective. This is due to the steeply drooping characteristics of the • The receiving-end voltage rises with leading p.fs. and voltage profile at about this load point, which may subject droops with lagging. This is illustrated with the help the system to a much higher voltage swing than is desirable of phasor diagrams (Figures 24.22(a) and (b)). on small fluctuation of loads. • At unity p.f. the voltage variation and hence the To decide on the best reactive control for an existing regulation is the least and maintains a near-flat voltage transmission line one should choose the most appropriate profile. This is the best condition to provide the highest electrical line length that can transmit the optimum power level of system stability from a voltage point of view. from the load characteristics drawn in Figure 24.21. Then compensate the line with suitable reactive controls to obtain the required line length. For instance for the 400 Es I kV, 50 Hz system considered, we can choose a radial line with an electrical line length of 200–250 km and f then compensate the existing line according to 200–250

I · Xc km system to achieve the desired line length. The Vr compensation is provided so that the Pmax point, which Vr > Es (I · R ignored) lies far from the natural power transmission point Po, (a) Receiving-end voltage rises with leading p.fs. shifts within a stable region, i.e. near the Po region. Then from equation (24.8), Es q µ LC ◊◊ Say, for an actual line length of 800 km (symmetrical),

I · XL f Vr LC 400 ( 400 = midpoint Ferranti effect) Vr < Es (I · R ignored) q 400µ 1¢ ◊ 1¢ ¥ q

I which must be improved for, say, a 250 km radial line (b) Receiving-end voltage diminishes with lagging p.fs. i.e. q 250 µ LC11 ◊ ¥ 250

Figure 24.22 for q400 to be almost equal to q250, System voltage regulation and improving power quality 24/901

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

Pmax 1 1 Line length q from Equation (24.6) sin q = Vr /Es = % Po sin q cos q Radial line Symmetrical line km km

100 200 5.985∞ 0.104 9.61 100.5 200 400 11.97∞ 0.207 4.83 102.2 250 500 14.96∞ 0.258 3.87 103.5 300 600 17.955∞ 0.308 3.25 105.1 400 800 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.

LC 400 = LC 250 of the system, it is not practical to achieve the optimum 11¢ ◊ ¢ ¥ 11◊ ¥ capacity utilization of the line without sacrificing the 2 level of stability, even when the required degree of LC = Ê 250 ˆ L C or 11¢¢ 400 ◊◊11 compensation is provided. Parameters that may influence Ë ¯ the stability can be one or more of the following: 2 X 250 X 1A small value of (X – X ), i.e. X approaching X , or L1¢ = Ê ˆ L1 L CC CC L XC1¢ Ë 400 ¯ XC1 will have more chance of a sub-synchronous resonance (SSR) with the rotating machines and a ferro-resonance Since a shunt capacitive compensation will reduce with the transformers during a switching sequence or X ( 1/c), it will not provide the desired compensation. C µ line disturbance. This can be achieved with the use of series compensation, 2 Higher harmonic contents may magnify the harmonic C remaining the same. Then 1 currents and affect the loading capacity of the line. 2 250 3A very close compensation, i.e. a low XL – XCC, may XX = Ê ˆ also raise the fault level of the system beyond desirable L1¢ 400 ◊ L1 Ë ¯ limits. = 0.39 · X L1 To overcome such situations within acceptable \ Compensation required = 0.61 XL1 per unit length. parameters during normal operation, it has been found l Series capacitors making up 0.61 XL1· may be introduced that an ideal series compensation for combined ‘electrical into the system to achieve the desired electrical line length. line length’ and ‘surge impedance’ is achieved at around 40–70% of XL, preferably in the range of 45–60% only. Influence of surge impedance (Z1) The level of compensation will depend upon the expected load fluctuations and the presence of harmonic disorders 1 in the system. Since Po µ Z1 Example 24.2 Z1 plays a very significant role in the power transfer Consider the 400 kV, 50 Hz system and apply the above capability of a line. By reducing the value of Z1, the theory. If the system has relatively fewer load fluctuations power transfer capability of a system can be increased. and the loads are reasonably linear, then we can consider a Since higher compensation to the extent of, say 75% of XL. Then 2 Vr L1 Po = and Z1 = Z 1 C1 V 2 P = r and in absolute terms = XXL1 C1 max ◊ Z1¢ or = XXL ◊ C Z1 XXL ◊ C or PPmax = o ¥ = Po Z1¢ (XXXLL – 0.75 ) ◊ C¢ This value can be reduced by decreasing the value of XL, which is possible by providing series capacitors in the Since there is no change in the line charging capacitance line. If XCC is the series compensation, then the modified (XXCC¢ = ), impedance PP = 1 = 2 P \ max o¥ 0.25 o ZXXX1¢ = (L – CC) ◊ C While it is possible that Pmax may be further raised by a still and hence any value of power transfer can be achieved closer compensation, this is not advisable to retain the stability level of the system. The above compensation is higher than up to the theoretical Pmax (Table 24.5). But for reasons of other parameters that may also influence the stability the line length compensation considered earlier and will further 24/902 Electrical Power Engineering Reference & Applications Handbook improve the electrical line length. Choose a combined series programme). TNA is an analogue method while EMTP compensation of the order of 60–75% of XL, preferably around is a digital method of system analysis. For details of 65% for better stability. system models and procedure to study a system, refer to Adding shunt capacitors would also reduce Z1 but would raise the electrical line length; hence it is not considered. Miller (1982). Moreover, on EHVs, the charging shunt capacitances, C1, as A transmission line may have to operate under different such require compensation during light loads or load rejections conditions of loading (I and p.f.) at different hours of to limit the voltage rise (regulation) at the far end or the the day, and then there may also be seasonal loads. The midpoint. Hence no additional shunt compensation is type of reactive compensation therefore must be decided recommended. for the varying load conditions, so that they are able to provide a continuous change in the VAr as demanded. It Note is normal practice to have a combination of series and Series compensation would mean a low value of Z1 and hence a higher system fault level. This need be kept in mind shunt reactive compensations to suit all conditions of while designing the system and selecting the switching devices loading, some fixed (unswitched) compensators for normal or deciding on the protective scheme or its fault setting. load conditions and the remainder variable, to switch ON or OFF depending upon the load conditions or load 2 Symmetrical lines fluctuations. The choice of different types of reactive compensators may be considered on the following basis: Equation (24.12) is now modified to 1 Shunt reactors These are provided as shown in Figure Es = Vm · cos qm + JZ1 · I1 · sin qm (24.13) 24.23 to compensate for the distributed lumped where capacitances, C1, on EHV networks and also to limit V = voltage at the midpoint of the line (Figure 24.18) temporary over-voltages caused during a load rejection, m followed by a ground fault or a phase fault within the qm = line length or Ferranti effect up to the midpoint of the line. prescribed steady-state voltage limits, as noted in Table 24.3. They absorb reactive power to offset the charging The rest of the procedure, even the inferences drawn power demand of EHV lines (Table 24.2, column 9). above, would remain the same as for a radial line. The The selection of a reactor can be made on the basis of only difference now is that the system would become the duty it has to perform and the compensation required. suitable for twice the lengths of the radial lines as a Some of the different types of reactors and their result of the midpoint effect which doubles the line length. characteristics are described in Chapter 27. Reactors add to ZZ( = X X ) and hence Conclusion 11 L1◊ C1 reduce surge impedance loading (SIL), Po. Most are A compensated line can transmit much more power than the fixed type, depending upon the maximum load its natural loading within stable limits and hence fulfil conditions, and the remainder are switched. The the requirement of economical power transfer. The above switchable reactors are switched only during a was a theoretical analysis which can provide quite accurate temporary disturbance, therefore they have no adverse results, depending upon the accuracy of the data assumed. effect on Po. Ideally they can be made fixed to The more scientific procedure to conduct this type of compensate 50–60% of C1 and the remainder switched study, however, would be through a load flow analysis in a few steps. The size and number of steps will of the steady-state component to study temporary over- depend upon the likely under-loading, open-circuiting voltages and transient analysis through a TNA (transient during offpeak periods or other temporary disturbances. network analyser) or an EMTP (electromagnetic transient The over-voltages that may occur under such

Transformer L1 L1 L1 L1 G

SCR C1 C1 SCRC1 C1 SCR C1 Vr

G G Intermediatory switching station SCR – Shunt compensating reactor

Figure 24.23 A shunt compensated transmission line System voltage regulation and improving power quality 24/903

conditions, and which must be controlled through these enhance SIL, Po, and electrical line length, and boost reactors, is a matter of system design practice adopted the receiving-end voltage as discussed in Section 24.8. by a country or its central power authorities and may be broadly based on our discussions in Section 24.6 Example 24.3 Application of series compensation on and Table 24.3. To determine more accurate over- an HV distribution network voltage conditions, however, a TNA or EMTP study Let us consider the primary distribution network of Example would be better for an existing system and earlier 23.2 as shown in Figure 24.25(a) feeding an LV load of 30MVA data and experience for a new system. at 0.98 p.f. through a 33/0.4 kV transformer. The following line parameters have been considered: Note Resistance of primary distribution overhead lines, Section On 132 kV networks the MVAr loading is light, as most of the B–B at the operating temperature, p.f. is controlled at the distribution level and the capacitive R = 0.13 /km per phase charging MVAr demand is low (Table 24.2, column 9). The 1 W charging MVAr is normally not compensated because, on load, Inductive reactance of this section at 50 Hz more than this is offset by the load p.f. XL1 = 0.4 W/km per phase 2 Shunt capacitors They are used generally for p.f. improvement of the system. They reduce Z and There is no leakage capacitance, C1, and hence no Ferranti 1 effect on such low voltages. We will use series compensation enhance SIL, Po, and boost the line voltage. They are to reduce the line voltage drop and improve the regulation normally switched and not permanently connected and hence the stability of the network as well as its load to avoid resonance on load rejection or an open circuit. transfer capability, Generally they are used for systems up to 33 kV, i.e. at the distribution end. But when the p.f. is not fully Load p.f. = 0.98 (– -11.48∞) compensated at the distribution end it can be In Example 23.2 the system was not capable of transmitting compensated at the secondary transmission level of its full capacity. Let us consider that with the use of series 66 kV or 132 kV also. Capacitors at such voltages compensation it can be fully loaded up to may be connected through dedicated transformers, 30 MVA 0.98 = 29.4 MW. as illustrated in Figure 24.24. ¥ The impedance of the transformer

Note 2 zp V On 66 kV networks the MVAr loading is normally high and Z = r ¥ 3 (from Equation (13.3)) therefore one practice is to instal MVAr meters and adopt a 100 kVA ¥ 10 manual switching during variation of MVAr beyond the 26 permissible level, purely as a cost consideration. = 10 33 ¥ 10 ¥ 6 100 30 ¥ 10 3 Series capacitors These are used for line length compensation to help transmit power over long = 3.63 W distances and also improve the stability level of the For ease of calculation, let us consider the impedance of network. They are usually installed at the line ends the transformer as its leakage reactance, ignoring resistance or at the selected locations. They reduce Z1 and and draw an equivalent circuit diagram as in Figures 24.25(b) and (c). Assuming the length of the primary distribution line to be 15 km, the total line parameters will become 66 or 132 kV line XL = 3.63 + 15 ¥ 0.4 + 3.63 = 13.26 W and R = 0.13 ¥ 15 Dedicated = 1.95 transformer W Receiving-end voltage before series compensation To study the voltage fluctuation at the receiving-end with Switching fluctuations of loads, let us do so in terms of variation in device the transmitting-end voltage, assuming the receiving-end Capacitor voltage remains constant at 33 kV. We are doing this for banks ease of calculation and for drawing the phasor diagram, Figure 24.26. To study the impact of series compensation we consider the full-rated current of the transformer and the line for optimum utilization of the entire system.

33 –3 EIZs = + 1 ◊◊ 10 in kV G 3 Ê 525 ˆ Figure 24.24 Use of dedicated transformer to connect = 19.05 + – – 11.48∞ ¥ (1.95 + J 13.26) capacitors on networks 66 kV and above Ë 1000 ¯ 24/904 Electrical Power Engineering Reference & Applications Handbook

B G 30 MVA, HV 132/33 kV zp = 10% LV LV 11/400 kV HV R = 1.95 W

Primary XL = 6 W transmission Series XC capacitors HV 400/132 kV 30 MVA, HV LV 33/0.4 kV zp = 10% LV

Secondary Shunt transmission capacitors B

132/33 kV HV B LV LV loads = 30 MVA at 0.98 p.f.

Section (b) Details of Section B–B B–B under Primary consideration distribution 12 345 BB

HV 3.63 W 1.95 6.0 W 3.63 W 33/0.4 kV W XC LV 1 Leakage reactance of transmitter-end transformer. B 2 Resistance of overhead lines of Section B–B. 3 Inductive reactance of overhead lines of Section B–B. Secondary 4 Capacitive reactance of series capacitors. distribution 5 Leakage reactance of receiving-end transformer. 30 MVA (a) Typical primary distribution network (c) Equivalent circuit of Section B–B

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

6.96 kV = 19.05 + 1.00 – J 0.20 + 1.38 + J 6.82 = 22.43 kV Es = 21.43 + J 6.62 = 22.43 tan–1 6.62 21.43 17.16∞ = 22.43 17.16 (Figure 24.26) 11.48 – ∞ ∞ Vr = 19.05 kV 1.024 kV 525 A \ Voltage drop = 22.43 – 19.05 = 3.38 kV Figure 24.26 Receiving-end voltage after shunt compensation or 15.07% of Es It is difficult to operate such a system on full load. It = 19.05 + 0.525 ¥ 1.95 – – 11.48∞ + 0.525 is bound to have wide voltage and load fluctuations, more so on a line disturbance. Such a system may have 13.26 (90 – 11.48 ) ¥ – ∞ to be operated well below its rated capacity to retain its = 19.05 + 1.024[cos (–11.48 ) + J sin (–11.48 )] stability, even when the voltages on the primary and the ∞ ∞ secondary transformers are adjusted so that the required + 6.96 (cos 78.52∞ + J sin 78.52∞) rated voltage is available at the receiving-end. A voltage swing of 15% between a full load to a load rejection = 19.05 + 1.024(0.98 – J 0.199) + 6.96(0.199 + J 0.98) condition is too wide and may lead to outage of the System voltage regulation and improving power quality 24/905 system on a line disturbance. Since there is no further = 2668 = 98.8 say, 100 kVAr scope to improve the above situation with the help of 3 ¥ 9 shunt capacitors (the p.f. is already at 0.98), let us do so and the voltage rating of each unit with the help of series compensation. Since the far-end p.f. is being maintained at a high level, the system can = 4.62 = 1.54 kV achieve some stability. A series compensation to the extent 3 of, say 60% of the total line impedance should not be The improved line impedance excessive, as the line already has some series resistance. = 1.95 + J 13.26 – J 8.0 Moreover, the transformers will have some resistance too which has been ignored in the above analysis and = 1.95 + J 5.26 hence the chances of a sub-synchronous or ferro-resonance occurring will be remote. and the improved transmitting-end voltage, the load remaining same; \ Series compensation = 0.6 (1.95 + J 13.26) Es = 19.05 + (0.525 – – 11.48∞) (1.95 + J 5.26) = 8.04 W (in absolute terms) = 19.05 + 1.024 (0.98 – J 0.199) + 2.761 (0.199 + J 0.98) Say, XC = 8 W and size of series capacitors, = 19.05 + 1.00 – J 0.02 + 0.55 + J 2.71 = 20.6 + J 2.51 5252 8 = ¥ 1000 = 20.75 tan–1 2.51 = 2205 kVAr per phase 20.6 For 10% load variation, to be on the safe side, the = 20.75 – 6.95∞ capacitors must be rated for: \ voltage drop = 20.75 – 19.05 = 1.7 kV or 8.2% of Es = (1.1)2 2205 ¥ This is also the regulation of the system. See the phasor = 2668 kVAr representation shown in Figure 24.27(b). and voltage across the capacitors, Inferences VC = I · XC 1 Raising the compensation from 60% to, say, 70% may further improve the above situation but this may = 525 ¥ 1.1 ¥ 8 not be advisable to maintain a high level of stability = 4.62 kV during line disturbances. Moreover, the p.f. of the system has already reached a high of cos 6.95∞, i.e. If we consider three units in series and nine in parallel 0.99, which also is not advisable. To be safer, the (Figure 24.27(a)) then the size of each unit level of shunt compensation should be slightly reduced.

Note Since the load variation on an HV distribution network will be only nominal, and the network will also have enough resistance, N1

132/33 kV * 33/0.4 kV Load 29.4 MVA 3 3 at 0.98 p.f. Z = 3.63 0.975 W W W 0.975 W W Z = 3.63 W Note (1) The capacitors are shown in the centre of the line which being the best location. But N2 * 27 Nos. 100 kVAr each they can be provided near the receiving- Shunt capacitors end transformer also. N1 (Series group) = 3 2240 kVAr per (2) They are to be mounted on platforms, N2 (Parallel group) = 9 phase insulated for 19.05 kV from the ground. (for arrangement (3) The normal practice is to mount each refer to Figure phase units on separate platforms, 23.18b) insulated for 33 kV from each other.

4.62 kV 2700 kVAr per phase

Figure 24.27(a) Application of series compensation on an HV distribution network 24/906 Electrical Power Engineering Reference & Applications Handbook

6.96 kV high tension lines in the open and also save the scarce land area. Underground cabling is more expensive than = 22.43 kV Es an overhead system, but is more safe in congested areas. * The use of an overhead or underground system will = 20.75 kV depend upon the location, safety and convenience, Es 2.761 kV besides consideration of cost. See Lakervi and Holmes 17.16∞ 6.95∞ in the Further Reading for more details. 11.48∞ V = 19.05 kV r 1.024 kV 525 A Note Countries like the USA and Japan have adopted underground * Series compensation cabling for transmission of power up to 1000 MW at 550 kV. Note In fact Es is the fixed phasor and Vr the variable. But for ease of 7To provide reactive support for any power system or drawing, we have considered Vr as the base phasor. network, suffering from voltage fluctuations or high line losses or when it is felt that the system cannot Figure 24.27(b) Receiving-end voltage after shunt and series transfer the required load it is important to carry out compensations a field study first, to identify areas and suitable locations where reactive support would be more appropriate. A it should be possible to compensate the system up to 70% or so, procedure along the lines of Example 24.3 to determine to further improve the regulation of the network, say up to 5% the amount and type of reactive support should then of Es, without jeopardizing the level of stability. The application be adopted. engineer can take a more judicious decision, knowing the condition of the network to be compensated. Above we have dealt primarily with the technical aspects of reactive controls. For commercial implications, 2 The voltage variation with the series compensation, see Lakervi and Holmes. although high, at about 8.2%, is still manageable by adjusting the tappings on the transmitting-end transformer, for which a transformer with higher 24.9 Dynamic and transient stability tappings may be selected or a transformer with a higher of overhead lines (Applications secondary voltage may be chosen, say, at 36 kV or so. For minor adjustments, the tappings on the receiving- of reactive controls) end transformer may be used. With this, the above system can be utilized to its optimum capacity. A. Dynamic stability 3 The phasor displacement between the transmitting The dynamic stability of a power system defines whether and the receiving ends, with the use of series it can restore normal operation following a major compensation, is reduced and the receiving-end voltage disturbance, such as on has moved closer to the transmitting-end voltage, which will provide more stability to the system during a line • The outage or failure of a generating unit disturbance. • Failure of the overhead line or a transformer and 4 Even a higher cross-section of line conductors would • Abrupt change of load like, sudden opening of the be able to improve the above situation by reducing line or switching of large loads causing severe power the line resistance and hence the voltage drop. fluctuations. 5 It will be pertinent to note that series compensation The highest level of power it can transmit during such on HV lines will be more effective when the line disturbances without disturbing its synchronism is its inductive reactance itself is high, as when the line is dynamic stability limit. It is also a function of moment individually feeding highly inductive loads, such as of inertia of the rotating masses of the generating source, an induction or an arc furnace or other similar loads. prime-mover and the generator (see function of a flywheel Nevertheless, it can also be effectively applied on Section 3.9). Higher the inertia longer the period the over-loaded distribution networks similar to the one system can sustain the line disturbances noted above and we have considered above, to raise the line capacity keep the system in tandem. But no extra rotating masses and reduce the voltage dip at the receiving end. are usually added to supplement the stability level of the 6For large concentrations of loads, such as for an industrial system in view of already large rotating masses on the or a residential area and where addition of more loads system. in future is likely, forecasts of a realistic loading of Damping the power oscillations on such disturbances lines may fail. Therefore, for growing cities particularly, and restoring the power system to stable limits are the it is advisable to instal initially a slightly larger primary main objectives of reactive control. From the load curves distribution network to cater for the increasing power one can observe that an uncompensated line may have needs. It is felt that for such load centres, an 11 kV or dangerous power swings on small fluctuations of load, even 33 kV distribution is inadequate. The which may lead to loss of synchronism between two commensurate primary distribution for such locations generators and even cause an outage of the line. To keep may be considered at 66 kV, and in residential and this system stable during such disturbances, it must be industrial areas or public places underground cabling operated at much below its steady-state stability level. should be adopted to minimize the risk of running such Consider a typical case during a line disturbance when System voltage regulation and improving power quality 24/907 the line is not adequately compensated. A transmission insulators which may occur because of humidity or network is being fed by more than one generator. When during rainy season. Dirt, dust and soot deposited on a line disturbance occurs say due to abrupt loading the the insulators providing the tracking path current flow to the excessive load will be shared more Note by the machine nearest to the load point and less by the The arc occurring before the breaker can be termed as primary arc and one installed a little away due to difference in line that occurring during the interruption of the breaker as secondary arc. impedances up to the load point. This will upset the earlier tandem operation of the machines and they will In most cases, such disturbances are of a momentary become unequally loaded and may fall out of step. The nature. Field studies have revealed that such causes one near the point of disturbance will slow down more contribute nearly 90% of the total trippings. During such than the other. The machine that shares the smaller amount faults, the interrupters at both ends of the transmission of the load will slow down less and feed more, becoming line may trip as a result of travelling waves in both overstressed. Now it will slow down and the other will directions because of flashover at the insulators and their pick-up. The situation will reverse thus and so the situation discharging through the ground. It becomes a case of will continue creating a hunting effect. The following ground fault. Switching surges may also raise the potential may result depending upon the dynamic stability limit of of the overhead lines and cause similar arcing insulators. the system. Three phase faults • In a reasonably stable system the situation is controlled –two phase or three phase short-circuits or ground faults promptly and the normal condition is restored. The and setting and the speed of the protective relays should –switching surges. be commensurate with such a situation to restore the normal condition as quickly as possible, • If not, the machine being loaded most may fall out, 24.9.1 Auto-reclosure schemes which may not necessarily be the one nearer the fault, Auto-reclosing on a power system, normally for overhead or lines, after a transient fault is a type of protective closing and •The situation may have a cascading effect until all network automation to avoid a supply interruption on such the machines fall out, resulting in a total blackout. faults and to improve system’s transient stability limit. To achieve a better level of dynamic stability it is It may be applied to an overhead transmission or a long desirable that the line be loaded a little less than the HV distribution system to reclose the interrupters on optimum power it is capable of transmitting to sustain such a trip and maintain the continuity of the supply the system disturbances without an outage. The load curves system, preventing loss of synchronism and helping to (Figure 24.19) provide a guide to determine the level at achieve a high level system stability. We discuss below which the line should be operated and from this can be these schemes for single and three phase faults. assessed the magnitude of disturbances that the line can safely sustain and recover promptly without an outage. – Single phase faults – Since such faults are of transient Series reactive support can provide a restoring force to nature, the scheme may be applied even on a per-pole sustain such disturbances and become essential, whenever basis, allowing the healthy phases to remain intact the line loading is expected to be more than the SIL (Po) and the reclosing necessitated only in the affected (generally on 132 and 220 kV networks). phase to further enhance the system’s transient stability. Series reactive support has been found extremely useful Now it would require an independent interrupting on existing lines even up to 11 kV, which are required to mechanism and individual relaying and tripping scheme cater for higher power demands than were originally for each pole which is a costly affair but desirable. envisaged (see Example 24.3). The reclosing sequence will initiate as described below for a 50 Hz system (illustrated just for the sake of B. Transient stability clarity). To be on the safe side the total duration of A transient stability limit refers to the maximum power fault may be considered about 20 cycles. This is known that the system (all the generators feeding the network) as rapid reclosing scheme and is almost the minimum can deliver on a transient fault without loss of synchronism. possible time to reclose after a fault, when the breakers Such transient faults are caused due to system disturbances may successfully close and hold. as discussed in Section 17.3 and summarized below, It is possible that the breakers may trip on the first reclosing, as the fault may not have cleared by then, Single phase faults because the other two healthy phases may also be – due to passing objects like birds, gales and storms feeding the fault through electrostatic (leakage) hitting the overhead lines capacitances and prolonging the de-ionisation of the – due to arcing grounds or arcing insulators insulators’ arc or the arcing grounds. In single pole – lightning strikes (not switching surges which tripping a delayed reclosing can still be adopted by necessarily is a three phase fault) shifting the timer to a delayed mode permitting another – system harmonics and over-voltages also enhance the time gap of about 500 ms (25 cycles) after the first trip. electrostatic flashovers Therefore in delayed reclosing the total closing time – arcing faults may also occur without actually there from the initiation of fault up to the second reclosing being a fault due to electrostatic discharges at the can be up to 1.12 second or so as noted below, 24/908 Electrical Power Engineering Reference & Applications Handbook First reclosing – Three phase faults – These faults may lead to two or (i) Dead time of the Ӎ 140–180 ms (7–9 cycles) three phase trippings hence more severe. To maintain stability the system must be restored within 200–300 breaker (duration the ms (10–15 cycles) after the tripping of the breaker, line remains disconnected, permitting a total fault time as to account for the prolonged arcing and other factors) Ӎ (200–300) ms + (40) ms + (40–80) ms + (80–100) ms through a closing timer Ӎ 360–520 ms or 18–26 cycles (ii) From commencement of Ӎ 40 ms (2 cycles) (Table fault up to trip command 19.1) Delayed reclosing may be possible now also depending Ӎ upon the system parameters, permitting a dead time (iii) Tripping time of the 40–80 ms (2–4 cycles) up to 10–15 cycles. breaker (Table 19.1) The above schemes are only suggestive and timings for illustration to outline the reclosing schemes that a (iv) Reclosing time Ӎ 80–100 ms (4–5 cycles) transmission or an HV distribution network can adapt to (Table 19.1) enhance the stability level of the network. Actual timings and philosophy for fast and/or delayed reclosing will Ӎ Total reclosing time 300–400 ms (15–20 cycles) depend upon the system parameters, rate of occurrence from the instant of of transient faults and other considerations based on field commencement of fault experiences, system stability level and factors noted before. Small variations may also occur due to variation in the Second reclosing operating times of interrupters and protective relays.

Ӎ 400 ms (20 cycles) + 500 ms (25 cycles) + 40 ms Note The critical drives connected on the power network such as auxiliary (2 cycles) + 40–80 ms (2–4 cycles) + 80–100 ms drives in a power station, a process plant, industry or other important (4–5 cycles) (second reclosing) installations, which may fall out during this momentary interruption can still be saved by incorporating in their switching circuits a re- Ӎ 1060–1120 (53–56 cycles) acceleration feature as discussed in Section 7.18.5 (Figure 7.19).

i.e. up to 1.12 second or so Reclosing relays The delayed reclosing supplements the fast reclosing Reclosing relays are available for single phase and three to still save the system from a swing and a consequent phase reclosings and can be programmed for 1–4 shots trip. By then the fault would clear in all probability to as per the reclosure scheme. The relay operates when the allow the breakers to reclose and hold, thus maintaining recloser dead-time delay has elapsed. For dead-time a the continuity of supply once again, saving the system separate time delay setting provision can be made in the from falling out of synchronism and a tandem trip of relay, while the reclaim time can be adjusted through a all the feeding lines of a power grid. If the fault persists separate time delay relay. The relay an IED (intelligent and the breakers trip again, the breakers will lock- electronic device) has communication interfaces for out, tripping the other two phases as well, and will connecting it to a power network control and automation not close again until the fault is removed and the or a SCADA system. Figure 24.27(c) shows the general breakers are reset. over-view of an auto-reclosure relay. Delayed reclosing may be adopted where the system has large inter-connections (mesh system) as at a power grid, and where loss of one phase may not cause a 24.10 Switching of large reactive loss of synchronism in such a duration and hence banks restore the transient stability of the whole system. When the network is not very complex and may be The series capacitors are connected in series with the inter-connecting only a few transmission lines, some power lines to provide reactive support to an individual power handling agencies may adopt to only single load or to a power distribution or transmission system. closing permitting a higher dead time of about 1 sec They are therefore switched with the power lines and are to account for contingencies and delays in fault clearing thus permanently connected devices. (total fault duration 1.16–1.22 sec). It is possible that But the shunt capacitors and reactors can provide the breakers may trip now also. If so, they will lock- reactive control through unswitched, i.e. permanently out tripping the other two phases also. connected, banks (fixed VAr) or through switched banks It is possible that the breakers may hold but trip (variable VAr). The unswitched VAr may be used to aid again within a few seconds. If this occurs within 25 stability against possible over-voltages of the network, sec or so (reclaim time) the breakers will not reclose during a load rejection or an open circuit while the and will be locked-out tripping the other phases as switched VAr is used to maintain the level of p.f. and well. If tripping occurs after 25 sec or so, it will be stability during load variations. VAr switching can be considered a fresh fault and the same reclosing done in three ways. sequence will repeat as after the first tripping and so on. 1 Manual control This is through switching devices System voltage regulation and improving power quality 24/909

permissible limits (Section 26.1.1(2)) by carefully arranging the units as discussed in Section 23.15.1. 3 Static VAr compensators (SVCs) or soft switching of capacitor banks Whenever a large reactive control is required, the SVC is always a preferred method. The static VAr controllers are more expensive, but respond very quickly. They cause no switching transients and limit the magnitude of a disturbance, through extremely fast controls. They can handle large currents and peak inverse voltages, except voltage transients, such as switching surges or lightning strikes. The surges may have a front time as low as 1–2 ms only (Section 17.3.3) while the switching time of a static device (a thyristor) may be as high as one cycle, as discussed later. But surges can be taken care of by a surge arrester. The use of an SVC or a manual switching will largely depend upon the characteristics of the line, the type of load it is feeding and its importance. For a system having almost the same type of load demand during the day, manual switching may serve the purpose as noted above. But for a system with wide fluctuations, an SVC alone will be suitable. The decision will vary from one system to another and 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 is performed at the instant when the current wave is passing through its natural zero. Static devices in various combinations and feedback control systems, which Figure 24.27(c) Over-view of an auto-reclosure relay (Source: may be computer-aided, can almost instantaneously Siemens) (£ 1 cycle) generate or absorb reactive power, as may be demanded by the system. Correction is quick and by switching in or switching out a few units. In manual matches the fast-changing load parameters of the power switching it will be possible only in steps, and may network at the receiving end. They are capable of not provide a smooth compensation and may also maintaining a near-constant voltage profile at all times cause switching transients (Section 23.5.1). Moreover, at the receiving end. The correction achieved is accurate conventional switching methods (mechanical switching and smooth, besides being extremely fast and free through contactors and breakers), are sluggish due to from surges. They may be installed at strategic locations the time of closing and interruption, which may be as along the line or at the receiving end. The selection of much as three or four cycles, depending upon the location is an important aspect to optimize the size of type of interrupter (Section 19.5 and Table 19.1) as compensator and a more efficient voltage regulation. well as the minimum time required for the discharge of the capacitors. Human sluggishness may also A fast VAr control is achieved through thyristor introduce some delay. They are therefore ill-suited to switching, which by itself is capable of a stepless variation. meet the system’s rapidly fluctuating needs. But switching of capacitors, which are switched in banks, However, power systems that cater to almost fixed is not stepless. The SVCs may be of the following types. loads at a time and whose variations occur only at specific times of the day may not require a fast 24.10.1 Thyristor-switched capacitor banks response. In such cases, it is possible to provide manual (TSCs) switching methods which will give enough time between two switchings. Manual switching, however, Thyristor-switched capacitor banks are normally has certain shortcomings, due to the human factor connected in parallel with several banks of shunt capacitors such as its accuracy and diligence, as noted above. to control the system voltage. Feedback sensors and The recommended practice is therefore to select fast controls monitor the voltage level. When the voltage reactive controls as noted below. swings to either side of the preset value, a few banks are 2 Auto control When auto-control is selected through switched in or switched out. This is illustrated in Figures p.f. or voltage control, care must be taken against 24.28(a) and (b). Point a indicates the operating point frequent switchings of the capacitors when the load under normal conditions. During a load variation or is of a varying nature which may cause the capacitors disturbance the voltage dips and the operating point shifts also to switch frequently. Fast switchings can be made to b. With the use of TSC, the load point is shifted back possible by providing special discharge devices, and to c. Since the control is in steps, it may be coarse. The by controlling the number of switchings to within steps may be limited to save on the cost of thyristors. 24/910 Electrical Power Engineering Reference & Applications Handbook

al load line Norm a

)

r

V

( Switching instants c

oltage Load line on a disturbance E1

b

Receiving-end v System voltage

E2

Capacitor induced emf 1 set of banks2nd set of banks (with harmonic disorders)

Ir Figure 24.28(b) Improvement in loading by use of a TSC Figure 24.28(a) Switching instants for a TSC compensator

This step change in voltage can, however, be smoothed independently control each phase and the TCR can be and a stepless reactive control achieved with the use of used for phase balancing. When a phase angle is controlled, a TCR (thyristor-controlled reactor) in parallel and a stepless reactive power control can be achieved, except operating it with the TSC banks in tandem. Such a scheme for generation of harmonics during the control process. can be tailored to suit even the smallest reactive need of The gate control at peak voltage (a = 90∞) can allow full a system. The combination can be termed hybrid conduction of the reactor. The conduction can be controlled compensators. One such scheme is illustrated in Figure by varying the gate angle, a. For example, partial 24.31 and discussed later, in more detail. conduction is possible with a between 90∞ and 180∞, but In TSCs the thyristors are used in anti-parallel to switch a from 0 to 90∞ is not used, as then the circuit would a capacitor bank ON or OFF but without any phase angle produce asymmetrical currents with d.c. components. control. A TSC therefore does not by itself generate any The effect of increasing the gate angle is to reduce the harmonics, unlike a TCR. harmonic components of the current, and hence the power losses in the thyristor controller and the reactor. If the 24.10.2 Thyristor-controlled reactors (TCRs) reactors and the thyristors are connected in delta, triple harmonics can be eliminated and filter circuits would be These consist of two oppositely poled thyristors, as shown necessary only for the remaining harmonic quantities. in Figure 24.29 and conduct on alternate half cycles at Various combinations of thyristor circuits are possible to the fundamental frequency. Reactors may be switched obtain a desired phase displacement between the voltage or phase angle controlled. Three-phase SVCs can and the current (cos f) and hence suppress the various harmonic contents present in the system. (Section 6.13 provides more details on this.) See also Further Reading at the end of this chapter. Interrupter The number of thyristors in series, each selected for an impulse voltage of a little less than the impulse voltage withstand level of the terminal equipment (Table 11.6) Reactor can effectively limit the switching overvoltages within V desired safe limits. Then connecting them in anti-parallel will mean that the voltage will be forward for either of the opposing thyristors, hence protecting the system Opposite poled thyristors against overvoltages in either direction.

For practical approach, the 24.10.3 Transient-free switching whole reactor is divided into two parts. One part is To switch ON a charged capacitor connected after the thyristor, to limit the fault current In a thyristor circuit if a charged capacitor is left ungated at a current zero there will be no conduction of current Figure 24.29 Scheme for a thyristor-controlled reactor (TCR) while the capacitor will still hold the full d.c. charge, as System voltage regulation and improving power quality 24/911 illustrated in Figure 24.30, equal to positive or negative remain stable, without an outage, during disturbances of peak of the system voltage. For a transient-free switching such a transitory nature. Similarly, the SVC will stay the capacitor is switched when the system voltage and immune to lightning and switching surges. the capacitors’ induced e.m.f. have the same polarities and coincide almost in magnitude. This situation may 24.10.5 Combined TSC, TCR and fixed take up to one full cycle (Figure 24.30) and can delay capacitor banks the switching by one cycle when switched immediately after a switch OFF. The system’s protective devices may With the combination of switched capacitors and reactors be introduced with an additional time delay of at least (TSCs and TCRs), also known as a hybrid combination, one quarter to one half cycle to bypass disturbances of a each phase voltage can be closely monitored to maintain transitory nature. a near balanced and flattened profile at all times at the receiving end. A typical scheme is illustrated in Figure To switch OFF a charged capacitor 24.31 which comprises: This can be achieved at any current zero which occurs •A few fixed capacitor banks which are normally every half cycle (Figure 24.30). energized. When they are required to be switched, they cause a switching delay due to the closing or opening of the interrupting device, besides generating Reactor switching the switching surges. To avoid delays and switching Unlike a capacitor, an energized reactor on a switch-off surges, they may also be made as TSCs, if cost is of retains no charge at a current zero and can be switched little consideration and faster and more accurate ON or OFF on a current zero at any point on the voltage corrections are more important, in view of highly wave without causing a transient. Hence there is a delay fluctuating and non-linear load demands. of, at most one half of a cycle between two consecutive •A few TSCs for finer reactive controls. switchings of a reactor. The balance of the two oppositely •A few TCRs to balance the reactive power supply. poled thyristors, however, is monitored through the gate They may generate harmonics, which must be control to avoid even harmonic quantities, although odd suppressed to avoid any resonance. TSCs and TCRs harmonics will still be generated when the gating angles are monitored through a feedback control system. are balanced, i.e. are equal for both the thyristors. •A filter circuit to absorb the harmonic currents generated by TCRs and in certain conditions, when 24.10.4 Response of SVC on a fault or line TCR is ‘OFF’, also generate capacitive reactive power. Refer to Figure 24.33 for more clarity. disturbance of a transient nature Consider a normal load line (1) (Figure 24.32) having An SVC offers an extremely low response time, of the the initial operating point at (a). On a disturbance, the order of just one cycle as noted above. But this time is load line shifts to (2) and the operating point to (b). The sufficiently high to respond against disturbances of a TCR would respond and some inductive reactance (X ) transient nature. For instance, during a fault condition, L will be shed to raise the content of XC. The load line will as expressed by the current–time oscillogram of Figure become less inductive and more capacitive to help the 14.5, the SVC will respond during the transient period voltage rise to point (c) within one cycle. If the voltage only and not during the sub-transient period. The is still below the preset value, some capacitors can be subtransient period may be less than a cycle and not fall switched ON either electromechanically or through TSCs, within the response range of an SVC. But a reactive depending upon the system adopted. The delay at point correction is also not needed for conditions of such a (c) will depend upon the method of switching of the transient nature, which is taken care of by the surge capacitor banks. The voltage will now jump to point (d) arresters (Chapter 18). A system is normally suitable to and final correction is achieved up to point (e). The sequence a–e would complete in less than two cycles if The next similar all the components are thyristor switched. The sequences condition occurs DC charge on from a-b-c-d-e can be reduced to a-b-e allowing a little One cycle after one cycle a switch off over- or undershoots from c to d. AC voltage Vmax V wave form max Notes 1 Reactive control is also possible through synchronous condensers. As they rotate, the rotor stores kinetic energy which tends to absorb sudden fluctuations in the supply system, such as sudden loadings. They are, however, sluggish in operation and very expensive compared to thyristor controls. Their rotating masses add inertia, contribute to the transient oscillations and add to the fault level of the system. All these factors render them less suitable for such applications. Their application is therefore gradually disappearing. ‘I 0’ at every one-half of a cycle 2 Reliability of shunt or series power capacitors is of utmost importance for the security of the system on which they are Figure 24.30 A delay up to one cycle in transient-free switching installed. Their failure may disturb the system or result in a ON, of a charged capacitor system outage. 24/912 Electrical Power Engineering Reference & Applications Handbook

400 kV transmission or 132 kV distribution line

Interrupter

V.T Transformer for reactive power supply. Secondary at say, 11 kV Reactive power supply bus

Interrupter

Line side reactor Some fixed reactor to limit inrush current to filter out sub- and suppress harmonics harmonic components

Opposite poled thyristors to 3 switch capacitors or reactors 4 * Voltage regulator and feedback * control system

1 2

Note: * Capacitors and reactors may be D connected to eliminate triple harmonics 1 Thyristor switched capacitors 3 Filter circuit to absorb harmonic currents caused by TCR 2 Thyristor controlled variable reactor (TCR) 4 A few filter circuits for different harmonics (it may also be a saturated reactor)

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

3 Generally, SVCs are designed for 11 or 33 kV and connected to microprocessors and digital signal processing intelligent a higher voltage system through a dedicated transformer through technologies that are prompt, accurate and more the tertiary of the main transformer. Figure 24.33 illustrates a importantly reliable, human involvement in monitoring typical SVC system using a dedicated transformer. 4 Since reactive controls are normally meant for large to very and control of complex activities in industries and power large installations, the practice so far has been to use thyristors management can be kept to the minimum. Automation only for such applications. With the advent of IGBTs, IGCTs and enhances the integrity, reliability and dynamic stability other devices (Section 6.7) installations of any capacity can now level of a system. Such supervisory systems are becoming be switched through these state-of-the-art semiconductor devices. the state-of-the-art, around the world to monitor and Likely applications besides power distribution and transmission system control complex activities in power management and industries like steel, cement, chemical, fertilizers, – Rolling mills petrochemical, refineries etc. achieving, – Industrial heating through arc and induction furnaces (Section 25.1.4). See also Section 6.7.4. – Improved reliability – Better quality of service – Better outage management 24.11 Automation of power network – Striving to become customer centric –Timely revenue realization and reduced losses through Supervisory Control – Enabling trading and sourcing in optimum manner and Data Acquisition (SCADA) Besides financial benefits, automation is sometimes the system only way to cut down a chaotic situation. A distribution system without SCADA-DMS can have three to four Introduction hours of painful downtime which can be brought down by SCADA-DMS to just a few minutes. In this age of mechanization, SCADA has become an There are consulting agencies who undertake study inevitable tool for automation. With the availability of of such complex systems and work out scientific, logical System voltage regulation and improving power quality 24/913

400 kV line 3 1

Dedicated a 400/33 kV transformer

) r d V

( e c b 7th 5th 2 harmonic harmonic Fixed filter filter capacitor banks TCR say, 90 MVAr 0–190 10 MVAr 40 MVAr MVAr

Receiving end voltage

Filter circuits

Range of compensation available Capacitive : 0 to +140 MVAr O Inductive : 0 to –140 MVAr Capacitive Inductive Illustration: Load current (a) When the TCR is ON, MVAr support = –190 Now filter circuits would also be on to suppress 1 – Normal load line harmonics and absorb capacitive MVAr = +50 Net maximum reactive support available = –140 MVAr 2 – Load line on a disturbance (overloading) \ (b) When the TCR is OFF, fixed capacitor banks 3 – Corrected load line would supply capacitive MVAr = +90 Note: Similarly, load lines can be drawn on a load rejection, or the The filter circuits would also supply generator or the line outages. capacitive MVAr = +50 \ Net maximum reactive support available = +140 MVAr Figure 24.32 Voltage regulation during overloading through Figure 24.33 Typical SVC at 400 kV through a dedicated reactive management transformer and efficient SCADA solutions through automation. dislodge the synchronism between the generating units, Industrial automation is on the rise and so also the transmitting stations and distribution networks and automation of ever rising power generation and complex throw the whole power network out of tandem to transmission and distribution networks. A power eventually trip or cause a total blackout as noted in automation system also provides the following Section 24.9. management support, Using microprocessor based intelligent technology it is – The automation schemes rely on data from IEDs* now possible to produce relays and measuring devices (relays, sensors, meters) and PLCs/RTUs placed at which can record, compute, compare (like a comparator), all critical locations. They measure essential parameters analyse and diagnose, make prompt decision and relay and environmental conditions like generation, loading, out prompt remedial activity, as per the program stored status of transformers and distribution networks and in their memory, to control a remote mechanical or transform them to real-time and historical data and electrical operation in a power network or generating deliver to the system or application and decision makers station as needed. A few such relays are mentioned in for further action. Section 16.8. These relays as IEDs (intelligent electronic – Continuous process monitoring of a power system – devices) can record numerous operating conditions of without automation and feedback controls it is various machines, equipment and devices operating in practically impossible to provide stability and the generating station related to flow, temperature, continuity to a complex power network catering huge pressure, speed, voltage, current, frequency, p.f. or any loads in a city, state or a whole country, inter-connecting such data and the loading conditions and vital parameters a number of generating units, transmission and of each transmission or distribution line connected on distribution networks, their load control centres and the network. They compute all such data, compare them feeding stations etc. spread over a large geographical with the data programmed in their memory, analyse and area. In a complex network a line disturbance followed diagnose them for any corrective action and can relay by human error, or power system element failure may out prompt warning signals or a remedial action to the related generating unit or the load dispatching or load * IEDs – Intelligent electronic devices. control station. 24/914 Electrical Power Engineering Reference & Applications Handbook SCADA-EMS/DMS is an energy management software 24.11.1 Application of a SCADA system system to provide such complex networks, the required management support and the necessary automation. The SCADA basic functions main functions of SCADA are, Based on the discussions we have had so far the basic functions of a SCADA system as applied to a power –Acquisition of field data from the equipment and distribution system can be summarized as below, devices installed in the field, process them and use them for the control of remote devices – to provide real-time, accurate and consistent –Telemetry – to transfer the data processed to different information of the power system sites/operators. The data can be analogue or digital – to maintain database and history of system parameters stored by RTUs (Remote Terminal Units)/FRTUs to review and analyse past operating data to provide (Feeder Remote Terminal Units) or IEDs like relays, an insight for future corrective actions, also sensors and meters. management information reports – to locate the fault quickly, isolate it and restore the These are the basic blocks on which is built the utility system control system. – to maintain records, store statistical data and transmit SCADA system constitutes a combination of computer the same to desired destinations hardware/software and communication technologies. The – to provide inputs for better network planning field system comprises a network of microprocessors – to improve availability of system and (PLC’s (Section 13.3.6) or RTU’s) in association with a – to optimize the system based on real-time calculations number of other IEDs like digital and numerical relays for different protections, pre-warning alarm, recording Other functions and metering facilities. All possible causes of destabilization and their remedies are simulated in the – Data acquisition software program at a control centre to achieve prompt – Control restoration of stable conditions and avoid a destabilization – Alarm and event handling or tripping of a line or the whole system as far as possible. –Trending The software used possesses scalability to migrate between – History and archiving computers of different vendors and different scales and – Reporting are expandable. – Load shedding A very important area constituting the energy – Reactive power control management system is telemetry – a data transfer and –Voltage control communication network, to relay out data and messages – Load balancing to different control stations in an efficient, distortion and disturbance free communication network such as through Automation scheme It shall mean a Serial Data Transmission System discussed in Section – Monitoring 24.11.5. The relays’ communication open type protocols – Decision making and are noted in the same section. – Control In case of EMS-SCADA the main controlling and and shall be accomplished through a centralized monitoring station (master control centre (MCC)) is SCADA system. located centrally over-viewing through the SCADA energy management system (EMS) all its generating units and SCADA main ingredients control stations (transmission networks) for their optimum It covers large geographical areas and relies upon the operation within desirable parameters. The sub-energy communication network and may comprise the following management stations are located at different field points depending upon the level of automation and feedback like at generating stations and feeding and load control requirements, centres operating in tandem, to monitor and regulate their operating conditions and load balancing through remedial –At field levels (generation, transmission or distribution action such as load shedding, load transfer, starting and centres), the SCADA will comprise Remote Terminal synchronizing a standby generating unit or any such Units (RTUs) or PLCsa for remote telemetry, Input/ activity. Output (I/O) racks, transducers and auxiliary relay In the event of a line disturbance or a fault of transient panels. nature as discussed in Section 24.9, the energy management system so achieved will be capable to restore the operating a Note parameters within desirable limits in the least possible Earlier it were RTUs that were usually employed because of time. Such as through an auto-reclosing as noted in Section their compatibility with various communication protocols. This 24.9.1 and avoid a voltage swing or outage of the system feature is now available with PLCs also. Both are computers as far as possible. Worse, if the faulty section is not able and possess good programmability and compatibility with various communication protocols and can be employed for this purpose. to restore its normal operation within permissible time, it can be taken out. If it is a generating unit, carry out load – System level components: These are located at the re-distribution from the available power to the various Control centre level and comprise Front End Processors dispatch stations and load centres without jeopardizing (FEPs), Database servers, Man Machine Interfaces the dynamic stability and continuity of the network. (MMIs), Video projection system etc. Critical system System voltage regulation and improving power quality 24/915 level components, mainly Front End Processors and 24.11.2 SCADA implementation Database servers have redundancy. There are multiple MMIs with provision to view the entire network from For implementation of SCADA system, remote data each of them. acquisition and its control are the key areas. To implement The MMI program operates on the MCC computer. this, following are the pre-requisites, A single line mimic diagram of the whole plant or –Availability of auxiliary contacts for status monitoring process can be displayed on the monitor for quicker of circuit breakers (CBs) comprehension and remedial action by the operator – Suitability of closing & tripping mechanisms of circuit with the real-time system. Similarly can be displayed breakers for remote operation bar charts, trend curves of key areas, alarm displays –Availability of CTs, VTs, CVTs and transducers for (it can be programmed to display all requisite data monitoring of feeder power flow and information such as tag number, trip value, time, –Availability of auxiliary contacts from protection relays date or any other data or information as desired) and – Assessment of retrofitting requirements if any (usually daily logs or management information reports of the with the old installations) process. Typical diagrams representing a few of these – Suitability of remote control of OLTCs (on-load tap details are shown in Figures 24.34 (i-v). changers) on power transformers – Communication media: It comprises the media for – Space in substations for installations of RTUs or PLCs communication between field and system level components and can be fibre optic, leased lines, private System planning microwave networks etc., and the associated end The following factors may be kept in mind, terminal equipment. The communication media shall also have redundancy. – System architecture (layout) – Serial data transmission via communication interfaces – System sizing and scalability (Section 24.11.5) – Communication network

Note • System architecture (layout) The above is the vital data collection and transfer system and is highly vulnerable to intrusion by unscrupulous persons and must Usually the SCADA system can have one Master be adequately secured for their integrity and reliability as discussed Control Centre (MCC) and one Backup Control Centre in Section 24.11.8. (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) 24/916 Electrical Power Engineering Reference & Applications Handbook

Figure 24.34(ii) Typical bar chart

Figure 24.34(iii) Typical trend curves System voltage regulation and improving power quality 24/917

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 operational The operator decides after calling the administrator or requirements of the network upon severe contingencies operators at the MCC if it was necessary to switch over to the MCC. For the sake of reference a typical layout to the Back-up Control Centre (BCC) or if the situation is illustrated in Figure 24.35. MCC is the master unit would be recovered in a short while. This philosophy of SCADA system and responsible for storing the has gained momentum especially post-September 11, data collected by the remote stations and generating 2002 catastrophe of USA. action plan. It can be networked to work stations for sharing the information. • System sizing and scalability The system sizing requirements are governed by the Location of MCC – It should be located at a central data flow between location with easy accessibility to the entire distribution area. A typical layout of control room area is shown – Substation equipment (status, control and power in Figure 24.36. Figure 24.37 shows a typical layout flow) and RTUs of a SCADA system. –RTUs and Master Control Centre (MCC) –Master Control Centre (MCC) and Backup Control Location of BCC – Anywhere with easy accessibility Centre (BCC) to the distribution area. The system can be designed keeping in view the Switch-over procedure from MCC to BCC – All Remote future expansions and additions in the installed MMIs and RTUs are connected in normal condition to capacity that may take place in course of time. the master control centre (MCC). In case of total stop of MCC for whatever reason, the situation is signalled • Communication network immediately to the operator in a conspicuous manner. For optimum and reliable operation of the SCADA 24/918 Electrical Power Engineering Reference & Applications Handbook

MCC - BCC link and speed MCC/BCC remote MMI link MCC BCC and speed 10 Mbit 10 Mbit Video screen 2 Mbit 2 Mbit

WAN

2 Mbit Operator consoles

Supervisory console Figure 24.35 Typical control centre configuration interconnected with dedicated link and Wide Area Network (WAN) (Courtesy: Reliance Energy)

system, communication network for exchange of information between field systems and control centre systems (MCC) plays a crucial role. Redundancy is essential to be built in the communication system to Conference room ensure minimum downtime. For real time monitoring Engineer incharge and control of the system, the following update times (considered typical for an MMI) can be chosen Figure 24.36 Typical layout of a SCADA system MCC control room – Control 4–6 seconds (from command execution to back indication on MMI)

Light users LU1 LU2 LUn Main users (PCs/Web) (consoles)

Control Centre ( ter MC as C) M 2 1 ICCP System control Backup Control Transco CC Centre (BCC) WAN

Grid station Grid station Communication media RTU #1 RTU #nth

Bay switch Bay switch Protection relay Protection relay Bay switch Bay switch Protection relay Protection relay

Figure 24.37 Typical system architecture of SCADA-DMS (Courtesy: Reliance Energy) System voltage regulation and improving power quality 24/919

–Status 4–6 seconds (from RTU to updation – The media is independent from public utilities and in MMI) services – Analog 10 seconds (from RTU to updation in – Redundancy is possible by using ring structures MMI) Implementation of DMS (Distribution Management To achieve response times as indicated above the System) and Business Integration Concepts can be following key factors must be considered. summarized in the following manner, –Processing capabilities of the RTUs or PLCs – SCADA system (with its functions noted above) is – Processing capabilities of the Front-End Processors inter-connected to the grid stations with MCC and – SCADA architecture integrated with DMS functionality to achieve, – Communication media: speed, reliability and • Distribution Network Power Flow availability • Fault Isolation and Service Restoration The communication media shall provide adequate • Switching Procedure Management bandwidth to carry the data-flow of the RTUs or PLCs •Voltage and VAr Control installed with provisions for future expansions, so that • Capacitor Bank Control there is no over-loading at any point in the communication – System is also integrated with business processes such as, network especially during high load and burst scenarios. In view of the need for DMS functionalities, • Automatic Meter Reading system (AMR) communication planning should be based on liberal • ERP (Enterprise Resource Planning) system software capacity (kbs) per Grid Station. In addition to the • TCS (Trouble Call System) software bandwidth requirements, the following criteria are also • Any other requirement critical for selecting the communication media. –Independent inter-connection of grid stations with BCC – Reliability – Inter-connection between MCC and BCC –Availability – Integration of DMS-SCADA with other systems – Data Security With the help of DMS-SCADA system a power network – Communication Protocols: The media should be can be integrated with other networks. A typical block capable of supporting standard protocols as noted diagram indicating information exchanges between the in Section 24.11.5 or any other not covered there. different systems is shown in Figure 24.38. Figure 24.39 For communication media, fibre optic cable is shows the hardware configuration. The above is only a recommended because, broad overview of a DMS-SCADA system giving a general idea about SCADA architecture, its application – It provides highest availability, reliability, and utility. The basic requirements would vary from bandwidth and data security application to application, type of power system, its – Modern communication protocols as well as complexity and requirements. The same logical approach additional services are available almost without can be adapted when applying a SCADA system to restrictions generation, transmission or an industry.

Status data CIS GIS (Customer information Maps. equipment (Geographical system) Customer data information system)

Trouble tickets (substations) Equipment data Outage data System & SCADA-DMS equipment faults

Load profiles, (substation alarms)

AMR (automatic meter reading Billing & settlement ERP system system)

Figure 24.38 Block Diagram indicating work flow between various business processes (Courtesy: Reliance Energy) 24/920 Electrical Power Engineering Reference & Applications Handbook

GPS (Global DMS & other DMs & other positioning IS&R applications SCADA IS&R applications SCADA system) & Time BCC MCC Display Multi-port Routers Routers LAN LAN

GPS & Time Display Remote FEP FEP Video Video WS PC projector CNP (ICCP) To RTUs projector CNP (ICCP) To RTUs system system Console Console Console Console Printers Console Console Console Console 2 B&W printers 1 colour printers

Colour printers Web UI server

Fire walls

Console Console Console Console Corporate Network PDS WAN PDS LAN To other Routers system CMS Data Web consoles DMS warehouse Printers FEP Colour CNP (ICCP) printers PDS Router Data Acquisition Network processor To RTUs DAN To remole FEPs RTUs and IEDS

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

Below we discuss a simple SCADA scheme for auto- (Utility Grid connected, Tie line outage, Utility islanded) load shedding in a power utility distribution and substations’ is carried out in SCADA MMI (Man Machine Interface) network. The scheme can be modified to suit any complex based on identified breakers. The load is shed in the power network for load shedding, rationing, load transfer individual receiving station (RS) proportional to the or re-distribution of power as per the network requirements. loading on individual receiving station. A logic is also Most of the modern substations apply the new generation implemented in SCADA MMI for generating an over- microprocessor based IEDs like relays, sensors and load trigger in case of tie line outage or a UGS unit trip measuring devices, while the old ones that are looking for condition. The breaker status & load per RS are sent an automation can be retrofitted with similar IEDs. from individual RS to SCADA MMI over a communication system. 24.11.3 Implementation of load shedding and Network status (Utility Grid connected, Tie line outage, restoration (Figure 24.40) Utility (UGS) islanded), amount of load to be shed and over-load trigger is sent from SCADA MMI to individual Below we describe typical implementation of load RS over a communication system. The SCADA MMI at shedding functionality in SCADA for a utility that has Utility Generating Station (UGS) acts as master, while its own generating station, plus it imports power from a the SCADA units in the individual RS work as slaves. supply company which is connected to the State Electricity The load shedding (LS) takes place on trigger from under Board (SEB), which in turn is further supported by the frequency relay stage or the over-load trigger received national grid of a country. from SCADA MMI. It takes place as per the priority Load shedding scheme defined by the operator at the respective RS or as per the The load shedding (LS) scheme, network determination defined program. System voltage regulation and improving power quality 24/921

Interconnection between Utility, Supply company and State Electricity Boards

Utility generating station (UGS) Supply company generation

4 4

Utility load on 220kV R/S generating station + supply company

Tie-lines Tie-lines 2 1 3 Power export to utility at 220 kV Part load fed from supply 1 2 company interconnection 3

3 Load fed by supply company at 22kV and 33kV Utility load MW 3

Other utility loads Load fed by supply company 3

SEB interconnection [Utility Grid(UG)]

Load fed to other HV consumers Other loads

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)

Utility (UGS) load shedding requirements • Under-frequency load shedding Load shedding is implemented as a fast acting system Under-frequency load shedding is used by Utility which sheds defined load by defined rules to protect the (UGS) to compensate outages of large generating units generating units at the UGS and keep the supply of Utility that result in a gradual frequency fall. Consequently, Distribution System (UDS) alive to the maximum extent low priority loads are shed to compensate for power possible. Load shedding automatically acts in different deficit. In case of severe disturbances the following scenarios such as under frequency, islanding and tie line may be opted trip. The load shedding is carried out by different logics depending on the available scenario: – system islanding (splitting the distribution network into several sub networks) – Utility grid connected (under frequency scenario) – disconnecting the distribution network from the – Utility grid islanded utility grid –Tie line outage – shedding of reactive loads • Manual load shedding •Target violation load shedding – If the contractual Manual emergency strategies are defined via a special import target limit from a partner utility (UG) is display by selecting one of the available manual load violated, the over-load is determined and marked or shedding lists. A manual load shedding list contains shed and the operator is alarmed. all associated loads from the highest priority down to • Equipment over-load load shedding – Load shedding the lowest priority. The loads that may be shed are is also exercised to protect selected equipment either marked by the operator or the required amount (transformers, generators, tie-lines) from over-load of load is entered by the operator and is assigned to and subsequent damage. the lowest priority loads. An execute command • Island balanced load shedding – Island balanced load activates manual load shedding. shedding can be applied, when some parts of the 24/922 Electrical Power Engineering Reference & Applications Handbook

protected system lose connection to each other or if EMS-SCADA may now be programmed to conduct the protected system loses connection with a partner the following functions, system (UG in the present case). • Emergency strategy logic – After positive identification – Load flow analysis of a trigger event, the actual emergency strategy and – Cost allocation corresponding action is determined. It may be – Supply and demand management conducted in the following manner. –Trending – Remote metering and energy auditing – Manual triggering – The operator activates the – Load scheduling and shedding, even rationing in shedding of a given load or loads as per the load power deficit areas shedding list. – Reactive power management to improve voltage – Alarm initiation – The respective emergency profile and stability of the system strategy is activated by alarms. –Telemetry protocols – Hardware initiated triggering – Signals from under- frequency or over-load relays may directly cause Difficulties have been experienced in integrating the later the shedding of predetermined loads through modules/functions of SCADA related business process activation of latching relays or a control logic. with the existing system. Present philosophy is therefore – Network islanding – In case of severe emergencies, to adapt an open architecture and use standard RDBMS network islanding or disconnection from the utility like ORACLE & SYBASE that is vendor independent. (UG) can be performed intentionally. This way modular integration can be possible. – Load restoration – After load shedding action, the Portability – Application software should operate load shedding function determines the amount of consistently on various operating systems of different available power in the affected network or islands. vendors. The value of the loads that can be restored is Interoperability – Information can be transferred between estimated according to the last value before tripping computers/firmware of different vendors through standard and the power available. protocols. In this manner we can tackle most of the emergency Scalability – Application software can migrate between events, stabilize the disturbance impact of distribution computers of different vendors and different scales, and network on power system, and the system can be expanded as power system network – achieve saving of auxiliary power supply of power grows. plants and distribution network Inter-connectivity – Other systems can be accessed through – avoid unintended power feedback to a collapsed the information network as if it were a load system (user utility (UG), and portability). – get rid of high reactive loads in cable networks For more details one may refer to the works mentioned under Further Reading. 24.11.4 EMS-SCADA: (Energy Management Solutions) 24.11.5 Serial data transmission to a control and Energy management system (EMS) automation system via communication SCADA system when applied for the automation of a interfaces power generating and transmitting network is called EMS- SCADA with the following objectives, A serial data transmission system is a means to transfer digital data to a remote control station from IEDs like –To automate generation and transmission systems and relays, sensors and meters through protocols and media. improvise their dynamic stability level Media of transmission can be internet, radio (wireless), –To provide cost-efficient power generation by PLCC (power line carrier communication) or optic fibre optimizing generation cables (Section 23.5.2(F)). It can also be wired media –To identify and control abnormal network conditions for short distances (10–20m). The choice of any of them –To reliably monitor energy management, generation would depend on economics and the required transmission control, energy trading, substation automation and quality, safety (corruption of data and hacking), outage management interference, rate of transmission and distance. Wireless – System integration – to focus on serving customer system is used for very long distances. needs vis-à-vis major vendors, meaning thereby co- ordination with multi-vendor SCADA-EMS Application of multi-purpose microprocessor based –To balance the source of energy and consumption of numerical relays as IEDs for power management and energy automation – Data acquisition, analysis and communication systems Numerical relays are employed for power transmission remain much the same as for DMS-SCADA. Now and distribution networks calling for monitoring, analyzing the system also integrates equipment and devices, such and diagnostic features in the relay, in addition to warning as generators, transformers, swithchgears, UPS, PCCs, signals and trip commands. With the application of state- MCCs, VAr controls and metering system to monitor of-the-art microprocessor based technology, numerical the whole power generation, transmission and relays are now being manufactured by many leading distribution networks from a central location. The manufacturers worldwide. They are producing multi- System voltage regulation and improving power quality 24/923 purpose relays, clubbing into one composite unit dozens Almost all numerical protective relays can be integrated of different purpose protection relays, incorporating into generation, transmission or substation control and features like recording, display and storage of data besides automation systems via system interfaces on a variety of processing, analyzing, monitoring and diagnostic abilities. communication open type protocols. Modern numerical The selection of relays is now simpler and protection of protective relays have the following communication a system, equipment or a circuit much more protocols: comprehensive and easy. So also monitoring of operating conditions of a power generating unit, transmission or – IEC 60870-5-103 It is an internationally standardized distribution network, or of a machine (transformer, motor, protocol for efficient communica- generator, capacitors or reactor). Their feedback control tion between protective relays and is simple, comprehensive and authentic. The communic- master control centre (MCC) and ation interfaces using different protocols can transmit all followed by power utilities serial data related to protection or information such as worldwide. fault currents and voltages, sequence of events, load data – Profibus It is a protocol used in automation and settings etc., on-line or off-line to a personal computer industries and is used when or a substation control and automation system. In short, protective relays are required to with the application of the IEDs it is possible to make a communicate with control and power network remotely controlled and fully automatic. automation system for their fault These relays thus can ensure safety, reliability and records, measured values, control stability of a power network or machine during operation commands and settings. through a single or minimal number of relays. The – Modbus Modbus is a widely used protective scheme can be engineered and interwired using communication protocol for individual protective relays. Multi-processing allows automation solutions in industries. integration of main protective functions and other It is used wherever protective relays protection related tasks, such as synchronization check are used along with other into one single numerical relay. The relay can monitor automation intelligent devices and control vital circuit parameters like V, f and as (IEDs) such as PLCs. It is designed D D Dq to emulate PLCs, transferring required during a synchronizing check of two or more register data to one another. sources of power or generators. A few such relays are – DNP 3.0 DNP (Distributed Network shown with the Figure 16.14 for the protection of a Protocol Version 3) is a messaging generating station. See also Figure 13.47(c). based communication protocol These relays may also be referred to as intelligent used in utilities. electronic devices (IEDs) and can form a part of an EMS – IEC 61850 It is the latest Etherneta based or DMS-SCADA power management system for Standard for communication, monitoring and protection of a power network as discussed specifically designed for substation already. These relays provide the bottom layer intelligence automation in utilities and in a generation, transmission or distribution network. industries to permit interoperability They perform processing of analog data to determine the of IEDs of different manufacturers. fault location or faulty feeder as programmed and transmit the same to the desired destination through Serial Data aEthernet Transmission System. Ethernet only defines the physical layer and not the protocols. It As standard, modern numerical relays are fitted with uses the Carrier Sense Multiple Access, Collision Detect (CSMA/ CD) data-link protocols, which employ a broadcast method for one or several communication interfaces. These communicating with nodes. When a station senses that the network communication interfaces are designed based on various is idle and it is ready to send, it transmits its data packets to the Standards prevailing for physical interfaces and network. Since all nodes hear the data, each node checks to see if communication protocols. Communication interface for the packet is intended for it. The station that matches the destination personal computer or laptop is usually provided as RS232C* address in the packet is the one that responds. The collision detection on front of the protection relays and permits access to all part of CSMA/CD tells nodes to halt transmission if a collision is detected and to try again later at a randomly determined delayed setting parameters and fault event data, using a relay period. The Ethernet system consists of three basic elements: software. While a system interface is usually provided on the rear side of the relays and permits communication – The physical medium – used to carry signals between computers with control and automation system on a variety of and nodes – The set of rules – that controls/arbitrates access to the Ethernet communication protocols and physical interfaces. The as it applies to several users selection of physical interfaces will depend on the protocol – The Ethernet frame-packets, that consist of a standard set of architecture and its techno-economics. Protocols are a set bits are used to carry data over the Ethernet of rules that allow the various stations connected to a field communication bus to spontaneously transmit the required For more details on protocols refer to the above mentioned IEC specifications and a few mentioned in the list of Standards. data, to a defined destination as discussed next. Protocol converter For different brands of IEDs at local and remote control *RS232C – is an internally agreed Standard for serial data stations operable on different protocols, protocol converter transmission. is necessary to establish communication between the two 24/924 Electrical Power Engineering Reference & Applications Handbook

IEDs. Presently manufacturers of various IEDs may protocol converter. Many leading manufactures have incorporate their own proprietary softwares conforming already implemented this and others are in the process to different protocols for transmission of data, partly to of doing so. maintain their own secrecy and partly because there was no common open type protocol applicable on them until 24.11.6 Introduction to general protocols recently. It therefore called for a protocol converter to make an IED of one brand communicate with the IED of Networks (hardware) provide computers the basic ability another brand. Handling of large number of protocols of transferring bits from one computer to another. In order was therefore cumbersome, costly, time consuming and to use networks we need a set of rules which all the dependent on one particular brand of IEDs during network’s members agree on. These rules are termed modification or expansion of an existing automation protocols. Communication Protocol is a Standard, system. It also introduced some delays and caused errors designed to specify how computers interact and exchange in the communication. It also meant high cost of messages. A protocol usually specifies: maintenance for the user. • The format of the messages, and • Procedure to handle errors Evolution of IEC 61850 To overcome these problems IEC in 1995 organized a In order to simplify the design and implementation of team of experts of different countries, manufacturers and protocols, designers have designed a set of protocols, utilities and assigned them the job of evolving a common each having different responsibilities instead of one protocol for substation communications. After years of protocol to be responsible for all forms of communications. rigorous working it has culminated in IEC 61850. It also The set of protocols that implements the protocol stack surpasses IEC 60870-5 on interoperability. IEC 61850 is is called a Protocol Suite and covers all forms of an open type protocol capable of communicating with communications as needed. For better application of a different IEDs without the use of protocol converter and Protocol, the Protocol Suite is further sub-divided into can easily define an international field communication various models as noted in Table 24.6. bus. The IEDs can now be built with only one protocol calling for no protocol converter. For details see IEC 61850. Internet protocol suites With the advent of new generation protocol IEC 61850, Of the many applications the different types of protocols manufacturers are now obliged to gradually adapt to this invented so far, we shall limit our discussions to only protocol to bring harmony amongst different kinds of those that are related to EMS or DMS–SCADA systems. IEDs produced by them to facilitate easy implementation In case of EMS-SCADA the chosen protocol suite shall of system automation by the user without the use of a be capable to communicate between different SCADA

Table 24.6 Protocols specific models

Communication port for Substation Automation System Separate 1 port relays Protocols Æ IEC 60870- PROFIBUS- PROFIBUS-DP DNP 3.0 MODBUS IEC 61850 software Specific functions Ø 5-103 FMS Alarms (relays to Available Available Available with Available with Available with Available Available central unit) with time with time time stamp time stamp time stamp with time with time stamp stamp stamp stamp Commands (BC/ Available Available Available Available Available Available Available central unit to relay) Measured values Available Available Available Available Available Available Available Time synchronization Available Available Available Available Not available Available – Fault records2 Available Available On separate port On separate On separate Available Available (sampled values) (with relays port (with port (with software) relays software) relays software) Protection settings3 From Available Separate port Separate port Separate port Available Available separate (with relays (with relays (with relays (with relays port software) software) software) software)

1 MODBUS: There is no time synchronization via this protocol. For time synchronization purposes it is possible to use a separate time synchronization interface. 2 Fault records: The transmission of fault records is not a part of the protocol. They can be read out with relays software. For transmission 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. For this purpose a separate interface or the front operating interface together with relays software would be required. System voltage regulation and improving power quality 24/925 system levels within a utility and between different power transfer hyper-text pages across the world wide web (www). handling companies and their utilities. For some Hyper-text pages are complex documents that may integrate understanding of the subject brief, definitions are given into text, images, sounds and animations. Each page may also below for general Protocols, contain hyperlinks to other web documents. PPP – Point-to-Point Protocol – A protocol for creating a TCP/ SNMP – Simple Network Management Protocol – SNMP is IP connection over a series of transmission systems both synchro- the standard protocol used to monitor and control IP routers nous and asynchronous. PPP provides connections for host to and attached networks. This transaction-oriented protocol network or between two routers. It also has a security mechanism. specifies the transfer of structured management information PPP is well-known as a protocol for connections over regular between SNMP managers and agents. An SNMP manager, telephone lines using modems on both ends. This protocol is residing on a workstation, issues queries to gather information widely used for connecting personal computers to the internet. about the status, configuration, and performance of the router. An SNMP agent, operating in each Bay Networks router, responds SLIP – Serial Line Internet Protocol – A point-to-point protocol to the queries issued by the manager and generates activity to use over a serial connection, a predecessor of PPP. There is reports. In addition to responding to SNMP queries, the router’s also an advanced version of this protocol known as CSLIP SNMP agent software transmits unsolicited reports, referred to (compressed serial line internet protocol) which reduces overhead as traps, to the SNMP manager when events, such as the number on a SLIP connection by sending just a header information of network collisions, exceed user-configured thresholds. when possible, thus increasing packet throughput. UDP – User Datagram Protocol – A simple protocol that transfers TFTP – Trivial File Transfer Protocol – A Bay Networks router’s datagram (packets of data) to a remote computer. UDP provides support of TFTP allows a network management station to an unreliable, connectionless datagram transport service for IP. download configuration information to a router or group of This protocol is used for transaction-oriented utilities such as routers and retrieve information from a router via Site Manager the IP standard SNMP and TFTP. Like TCP, UDP works with or Control Centre. Bay Networks routers include client and IP to transport messages to a destination and provides protocol server implementations of TFTP, enabling efficient transmission ports to distinguish between software applications executing and receipt of files across the internet network. TFTP provides on a single host. Unlike TCP, however, UDP avoids the overhead file transfer capabilities with minimal network overhead. of reliable data transfer mechanism by not protecting against Although TFTP uses UDP to transport files between network datagram loss or duplication. devices, it supports time-out and re-transmission techniques to ensure data delivery and provides no security feature. AP – Application level protocols – They are used on top of TCP/IP to transfer user and application data from one origin FTP – File Transfer Protocol – FTP enables transferring of text computer system to one destination computer system. These AP and binary files over TCP connection. FTP allows to transfer may be for file transfer protocol (FTP), Telnet, Gopher or HTTP. files according to a strict mechanism of ownership and access restrictions. It is one of the most commonly used protocols TCP – Transmission Control Protocol – Like UDP, a protocol over the internet. The Bay Networks router’s support of FTP that enables a computer to send data to a remote computer. enables a network management station to initiate router-to- Unlike UDP, TCP provides a reliable, connection-oriented, host, host-to-router, and router-to-router data transfers over TCP transport layer service for IP. Using a handshaking scheme, via Site Manager or Control Centre. This implementation supports TCP provides the mechanism for establishing, maintaining and RFC 959 (File Transfer Protocol) to ensure that data is transferred terminating logical connections between hosts. Additionally, reliably and efficiently. FTP is supported on all Bay Networks TCP provides protocol ports to distinguish multiple programmes routers and by all the router’s LAN, serial and ATM interfaces. executing on a single device by including the destination and source port number with each message. TCP provides reliable Telnet – Virtual Terminal Protocol – Telnet is a terminal emulation transmission of byte streams, data flow definitions, data protocol, defined in RFC854*, for use over a TCP connection. acknowledgments, data re-transmissions and multi-plexing It enables user to login to remote hosts and use their resources multiple connections through a single network connection. from the local host. Bay Networks enhance router installation and maintenance by supporting Telnet, the simple remote terminal IP – Internet Protocol – IP is a connectionless datagram delivery protocol. Through incoming Telnet sessions, Bay Networks protocol that performs addressing, routing and control functions router’s Command Console Interface or the Technician Interface for transmitting and receiving datagrams over a network. IP is can be accessed by a local or remote terminal. Outbound Telnet the underline protocol for all other protocols in the TCP/IP support enables Technician Interface to also originate an outgoing protocol suite. IP defines the means to identify and reach a Telnet session to another Bay Networks router or to other network target computer on the network. Computers in the IP world are equipment that accepts inbound Telnet. This provides access to identified by unique numbers which are known as IP remote routers in non-routine situations when Control Centre, address. TCP/IP protocol is developed for local area networks Site Manager, or SNMP is unavailable. (LAN) and internet applications and has become a standard protocol for UNIX/LINUX. SMTP – Simple Mail Transfer Protocol – This protocol is dedicated for sending Email messages originated on a local ARP – Address Resolution Protocol – In order to map an IP host, over a TCP connection, to a remote server. SMTP defines address into a hardware address the computer uses the ARP a set of rules which allows two programmes to send and receive protocol which broadcasts a request message that contains an mail over the network. The protocol defines the data structure IP address, to which the target computer replies with both the that would be delivered with information regarding the sender, original IP address and the hardware address oftenly called the recipient (or several recipients) and, of course, the mail’s body. MAC address. Once a routing decision has been determined, the router forwards the packet to the next hop network, providing HTTP – Hyper Text Transport Protocol – A protocol used to the best path to the packets’ ultimate destination. To accomplish this, the MAC-layer address of the next hop interface is added to the datagram and the packet is forwarded out of the appropriate router interface. If the next hop MAC-layer address is not known, *RFC 854 is a Telnet or file transfer Protocol Specification. the router first broadcasts an ARP request packet to determine 24/926 Electrical Power Engineering Reference & Applications Handbook the MAC-address of the next hop interface. When the destination 7 pre-defined layers to simulate common development with the matching IP address receives the broadcast, it responds of individual components. with its MAC-layer address, which is entered in the originating With the rapidly rising use of the internet, there is an router’s cache for future use. urgency to develop mechanisms for accommodating more NNTP – Network News Transport Protocol – A protocol used Protocol Suites. Literally thousands of combinations of to carry USENET posting between News clients and USENET protocol suites can be created with the large domains of servers. available protocol systems. The main protocol functions RARP – Reverse Address Resolution Protocol Server – A RARP that have found widespread use in the substation server allows hosts to obtain IP addresses from the router. Hosts environment are noted in Table 24.8. add to the network broadcast a RARP request, specifying itself as the source and supplying its MAC-layer address in the frame’s Some common definitions Destination Hardware Address field. When the RARP server Brief definitions of most commonly used terms on internet receives the RARP request, it enters an IP address in the RARP and functions of protocols are noted below for a general request destination IP address field, changes the message type reference, to a ‘reply’, and sends the packet back to the host that transmitted the request, using the host’s MAC-layer address. World Wide Web (www) – To cope-up with the increasing size and complexity of the Internet, tools have been devised 24.11.7 The OSI (Open System Inter-connection) to help access the network to locate the desired seven layers models information. These tools are often called navigators or navigation systems. A layering model is the most common way to divide a protocol suite. Each layer defining a set of message Uniform Resource Locators (URL) – A resource of the protocol functions. In the present case it divides Internet is unambiguously identified by an URL, which communication protocol to sub-parts and describe them is a pointer to a particular resource at a particular location. individually. Through OSI the communication process has A URL specifies the protocol used to access a server been divided into seven basic layers as shown in Table such as HTTP, FTP etc. as noted later and the location of 24.7 describing functions involved in communication a file on that server. between systems. These layers define how the data flows Web Server – It is a software program on a Web host from one end of a communication network to another computer that answers requests from web clients, typically end and vice versa. The seven layers reference model over the Internet. All web servers use a language or introduced by ISO around 1980s has since undergone protocol to communicate with the web clients and is many changes and modifications. The layers noted below called Hyper Text Transport Protocol (HTTP) as noted are however valid for our present discussions. under protocols. All types of data can be exchanged among The top 3 layers – physical, data-link and network web servers and clients using this protocol, including define the components of the communication network Hyper Text Markup Language (HTML), graphics, sound while the bottom 3 layers session, presentation and and video. application represent the functions of the end system. The middle layer transport links the top and bottom layers. Domain Name – This is the name that identifies a website. The overall communication process is thus divided into For example, “microsoft.com” is the domain name of Microsoft’s website. A single web server can serve websites for multiple domain names, but a single domain Table 24.7 The OSI seven layer models name can point to only one machine. For example, Apple Computer has Websites at www.apple.com, Layer No. Layer Responsibilities www.info.apple.com, and www.store.apple.com. Each of these sites could be served on different machines. Each 1. Physical Basic hardware components for networks domain name (like www.electricalengineering-book.com) i.e. RS-232 specification 2. Data Link Frame format for transmitting frames over Table 24.8 Possible combinations of Protocol Suites with OSI the net, i.e. bit/byte stuffing, checksum, error control, flow control layers 3. Network Address assignment, packets’ forwarding Internet Protocol Suites OSI-Seven layer models methods (routing) 4. Transport Transfer correctness Telnet Application 7 5. Session Establishing a communication session, FTP security, authentication, i.e. passwords SMTP Presentation 6 6. Presentation Computers represent data in different ways SNMP (character, integer). The protocols Session 5 therefore need to translate the data to and HTTP from the local node. TCP, UDP Æ Transport 4 7. Application Specifications for applications using the IP Network 3 network, such as, how to send a request, ARP, RARP Data-Link 2 how to specify a file name over the net, Not specified how to respond to a request etc. Physical 1 System voltage regulation and improving power quality 24/927 is translated into a numeric internet address called IP protocols (for instance FTP, Telnet, Gopher, HTTP). Using address (like 194.56.78.3). Socks, the Application Level traffic between a system running a Socks Client software and a system running a Internet – This is a global network of computers called Socks Server software is encapsulated in a virtual Socks the ‘Net’. The internet or ‘Net’ connects computers using tunnel between both systems. Socks is mainly used by a variety of different operating systems or languages systems within an Intranet in order to gain a secured like UNIX, DOS, Windows, Macintosh and others. To access to systems located outside the Intranet. facilitate and permit the communication between these A Socks Server acts as a relay between the systems systems and languages, the language the internet uses is within the Intranet and the systems outside the Intranet, called TCP/IP. TCP/IP protocol supports three basic thus hiding the internal systems from the external Internet. functions on the internet. It is considered as one form of Firewall. A Socks Server –Transmitting and receiving electronic mails (also called Socks Gateway) is a software that allows –Logging onto remote computers the ‘Telnet’, and computers inside a Firewall to gain access to the Internet. –Transferring files and programs from one computer A Socks Server is usually installed on a server positioned to the other (FTP) either inside or on the Firewall. Computers within the Firewall access the Socks Server as Socks Clients to Intranet – Some companies use the same mechanism as reach the Internet. the web to communicate within the company. In this case, this mechanism is called “Intranet”. These companies Protocol Gateway – A gateway converts conversations use the same networking/transport protocols and locally from one protocol or communication language to another. based web servers to provide access to their company Often RTUs or PLCs are used as gateways between profile, product details, data sheets, application or substations data and SCADA or DMS or EMS protocols. whatever. It is possible to hide confidential data or details from people other than authorized by using a special Port (Virtual) – A computer on the internet using TCP/ equipment called a ‘Firewall’. IP protocols uses various numbered ‘virtual’ ports to differentiate between the various servers the computer Firewall – A Firewall protects one or more computers may be connected to. For example – Telnet server is with Internet connections from access by external assigned port 23. computers connected to the Internet. A Firewall is a network configuration, usually created by hardware and Port (Physical) – An interface on a computer to which software, that form a boundary between networked one can connect a device. Personal computers have various computers within the Firewall from those outside the types of ports. Internally, there are several ports for Firewall. The Firewall can be configured using ‘proxies’ connecting disk drives, display screens, and keyboards. or ‘socks’ to control the access. The computers within Externally, personal computers have ports for connecting the Firewall thus, form a secured sub-network with internal modems, printers, mice, and other peripheral devices. access capabilities and shared resources that cannot be Remote Terminal Unit (RTU) – It is a stand alone small accessed from outside computers. computer on microprocessor system specifically designed Proxy Server – An HTTP Proxy is a special server that for real-time processing of input and output of data. The allows an access to the Internet. It typically runs in RTU’s function is to control process equipment at the conjunction with Firewall software. The Proxy Server remote fields, acquire data from the equipment and transfer waits for a request (for example from HTTP) from inside it back to the master control centre (MCC). Under direction the Firewall, forwards it to the remote server outside the of the MCC, the RTU turns switches on & off, and opens Firewall, reads the response, and sends out the response & closes valves. Data acquisition is performed when the back to the client. MCC scans the inputs provided by the RTUs or A single computer can run multiple servers, each server Programmable Logic Controllers (PLCs). connection is identified with a port number. A Proxy Router – A ‘router’ is a computer that inter-connects Server, like an HTTP Server or an FTP Server, occupies two networks and routes messages intelligently from one a port. A connection uses standardized port numbers for network to the other. Routers are capable to select the each protocol. That is why the end user has to select a best transmission path between networks. specific port number for each defined Proxy Server. HTTP Caching – It is an Application Level protocol 24.11.8 Security to a SCADA system used by the TCP connections between web browsers and HTTP Proxy Servers. Consequently, IP Datagrams To conceive and design a good SCADA system it is exchanged between the web browsers and HTTP Proxy essential to focus on high reliability and redundancy of Servers comprise HTTP data. Since HTTP Proxy Servers its hardware and software systems. Equally important is terminate and manage the HTTP connections, they see to protect it from hackers and unscrupulous intruders and handle the HTTP data comprised in the IP Datagrams who may sabotage or corrupt the whole power network and they can store a local copy of HTTP data in an via the SCADA system causing disruption of power even internal cache. a blackout and other damages. Large power networks that may jeopardize normal life and make big news item Socks and Socks Server – Socks is a protocol which is a big lure to such people to play mischief and satisfy does some form of encapsulation of Application Level their lust. 24/928 Electrical Power Engineering Reference & Applications Handbook

To access an unknown network: This can be possible – Similarly, there may be inadvertent lapses by the through, engineers and consultants while working out the network architecture leaving out some soft areas for – Insider information – using this, one can access system an easy access by the intruders. The most conspicuous IED’s like protective devices, sensors and measuring weak link for hackers and intruders is the increasing instruments and change their settings such as to render networking of the SCADA system by way of them redundant or behave erratic – make them operate when not needed, causing service interruption or stay • Expanded use of public protocols to inter-connect immune when actually needed, damaging the main IEDs and SCADA systems (e.g. TCP/IP over equipment they are protecting, generator, transformer, Ethernet LANs/WANs*) bus and power lines. • Increased dial-in and network access to remote –Trojan Horse – the hacker may access the system sites through public communication services information through a backdoor (phones and internet) – Network analyser – a network analyser can be attached with the SCADA network and feed erroneous Remedy commands to the IEDs or the SCADA system. It can (subject to the command of the hacker) result in It is essential to secure the SCADA system for a safe operation. Enough research has gone into identifying the • Shutdown of a particular area or the whole network risk areas a hacker or intruder may invade through and • Alter the metering or historical data the extent of damage it can cause to the SCADA system •Use SCADA system as a backdoor to the corporate and the power systems connected to it. A variety of tools IT system to extract confidential data such as and techniques can be used to counter such invasions. customer credit and personal identify references. Some such means are noted below for a general reference to those associated with the SCADA system, Earlier misconceptions about security Some misconceptions that utilities companies carried –A reference architecture illustrated in Figure 24.41 initially and which are carried still against such security gives a graphical representation of the access interfaces system can be the following, of a particular power organization for analysing the security information. The box containing the substation – The earlier practice was to keep a SCADA system LAN, router, firewall, local MMI, database server, separate from corporate networks. The SCADA system RTUs and IEDs represent the information components therefore operated in isolation and was considered to inside the substation. External to the substation is the be immune from hackers and intruders. But it is not remote SCADA that interfaces with the substation by so today as corporate networks are usually associated either a dedicated channel or over the utility WAN. with SCADA system to enable access to their engineers – Distribution and energy management system (DMS to monitor SCADA system from remote corporate & EMS) network operations also interface with the offices. The corporate network thus gets exposed to substation over the WAN and have access to the outside networks and becomes vulnerable to an easy substation information. These systems can also have alien access. Due to integration, security controls dedicated channels to the substation, but they are not between the SCADA system and the corporate network shown in the figure for graphical simplicity. get impaired and slacken in their security ring. – Access from the Internet, other WAN and DMS/EMS – Similarly, vulnerability to the SCADA system from network operations over the Utility WAN represent hackers and intruders can emerge through the opportunities for information security threats that must communication system between the SCADA and the be countered. Thus, information security for SCADA corporate communication network. and automation systems requires the specification of –With the advances in IT, to presume that a hacker or Discretionary Access Control, Object Reuse, intruder not equipped with adequate technology may Identification and Authentication and Audit not be able to invade through the intricate SCADA requirements. system is an ostrich ideology and undermines the – There are several techniques and processes that can capabilities of today’s bright brains. Moreover, be used to safeguard IEDs, RTUs, PLCs, controllers, surveillance by such perversive minds to obtain ‘insider communications processors, SCADA systems and information’ is not a very difficult task. More so when virtually every type of programmable digital device they are indirectly turned wiser through the published used in electric power systems control and protection. materials by the consultants and SCADA service First and foremost for network security is to restrict providers themselves who publicize their literature access and call for user authentication and then and data through ‘Net’ and printed catalogues for the safeguard the communication packets from eagle eyes promotion of their business. This information may be via encryption and verification of packet transmission enough to provide guidance to the eagle eyes watching and receipts. out for such data/information. – Corporate’s own websites are also a potential source of providing useful information about their IT system, names of important persons, their e-mail addresses and * LAN – Local Area Network much more, as a soft gateway to break into the system. WAN – Wide Area Network System voltage regulation and improving power quality 24/929

Utility WAN

Remote SCADA DMS and EMS

Database Server IRIG-B Timing Wire Router Local MMI

Firewall

Substation ethernet LAN

Hard wire

Relay IED Remote terminal unit IED

Instrument transformer Instrument transformer Instrument transformer switchgear and other sensors switchgear and other sensors switchgear and other sensors Figure 24.41 A simplified SCADA hardware configuration on interconnected network for analysing security requirements (Source: Wise Owl™)

Areas vulnerable to intrusions Discretionary access control – Excessive information by the utility companies on – Periodic security checks to ensure the integrity and the Net for the benefit of consumer exposes the reliability of the SCADA system communication network to the invaders –Take all such measures that provide a firewall at all – Often SCADA system and corporate communication vulnerable points that may lead to the integrity and networks are inter-linked exposing the SCADA reliability of the system from all external threats and network to unscrupulous persons intrusions – Inadvertent omissions while working out the SCADA – Immediately locating and identifying the hacker or architecture leaving out areas that an intruder can intruder as soon as he penetrates the network and locate and access through the SCADA system remedying the same – Design a security network architecture Following are some broad measures that may be taken – Conduct a thorough risk analysis to assess the risk to secure an IT system (with particular reference to a and remedy that SCADA system). Conclusion Security measures Most old systems have no security features. Such systems Identification and Authentication need to be upgraded and retrofitted with security systems for the integrity and reliability of the system. ISO 17799 – Meticulous and confidential allotment of user is a comprehensive set of controls comprising best practices identification (ID) numbers and passwords to the in information security and is essentially an internationally authorized users and their close monitoring. recognized generic information security Standard. – Protection of password files The above is a brief account of system security for a – Similar allotment of names to SCADA files and reference to those in the field of EMS-DMS SCADA programs systems. We have touched upon only the preliminaries – Adequate checks and controls to access these files of hacking and intrusions and their adverse consequences and programs by authorized users only on the integrity and reliability of an energy or distribution 24/930 Electrical Power Engineering Reference & Applications Handbook management SCADA system and the urgency of installing Today internet security is a big business. There are security systems to protect these essential services. For individuals and consulting firms who can stand guard to details on the subject and solutions of the problems one such systems, identify vulnerable areas and suggest may refer to the literature and international Standards firewalls and other measures to maintain integrity and published on the subject. Some such references and privacy to these networks. Most new systems now Standards are mentioned at the end of the chapter. incorporate security systems as standard.

Relevant Standards

IEC Title IS BS 60358/1990 Coupling capacitors and capacitor dividers. 9348/1998 BS 7578/1992 – 60694/2001 Common specifications for high voltage switchgear and 12729/2000 BS EN 60694/1997 – controlgear standards. 60870-5-103/1997 Telecontrol equipment and systems – transmission – – – protocols. 61850 (part 1 to 4) Communication networks and systems in substations. – – – – Information technology – Code of practice for – – 17799/2000 information security management. Relevant US Standards ANSI/NEMA and IEEE ANSI/IEEE-519/1993 Guide for harmonic control and reactive compensation of static power converters. IEEE-824/1994 Standard for series capacitors in power systems. NEMA/CP-1/2000 Shunt capacitors, both LV and HV. Notes 1 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 a continuous process by different Standards organizations. It is therefore advisable that for more authentic references, one may consult the relevant organizations for the latest version of a Standard. 2 Some of the BS or IS Standards mentioned against IEC may not be identical. 3The year noted against each Standard may also refer to the year it was last reaffirmed and not necessarily the year of publication.

List of formulae used d = load angle or transmission angle EEsr ◊ P = ◊ sin d (24.4) Capacitors for improvement of system regulation X L X = inductive reactance of the whole line length Voltage at no load – Voltage at full load L Regulation = Voltage at no load Influence of line length (24.1) Velocity of propagation of electromagnetic waves Rating of series capacitors 1 2 U = kVAr = 3 IX C (24.2) (24.5) ◊◊1 LC11 and voltage rating = I1 · XC. L1 and C1 are the line parameters per phase per unit length

I1 = line current 2p q = ◊ (24.6) XC = capacitive reactance of the series capacitors per phase l q = phase shift between the transmitting and receiving- Reactive power management end voltages in radians or degrees 22 EEsr ◊ = or 180 respectively P = ◊ sin d (24.3) p 7 ∞ Z1 ◊ sin q P = power transfer from one end of the line to the = line length in km receiving end per phase l = wavelength in km E = phase voltage at the transmitting end s Voltage at the receiving end, when it is open-circuited, Er = phase voltage at the receiving end, in radial lines and midpoint voltage, in symmetrical lines E Z = surge impedance of the line E = s (24.7) 1 r cos sin q = line length effect or Ferranti effect q System voltage regulation and improving power quality 24/931

Line length effect or Ferranti effect 2 Central Board of Irrigation and Power, India, Static VAr Compensators, Technical Report No. 41, March (1985). = 2fLC (24.8) 3 Central Board of Irrigation and Power, India, Workshop on qp 11◊ Series Compensation in Power Systems, Nov. (1986). 4 Central Board of Irrigation and Power, India, Workshop on Optimizing the power transfer through Reactive Power Compensation Planning and Design, Dec. reactive control (1993). 5Westinghouse Electric Corporation, Electrical Transmission and Distribution, East Pittsburgh, Pennsylvania, USA. 2 Vo sin d 6 Engbarg, K. and Ivner, S., Static VAr Systems for Voltage Control P = ◊ per phase (24.9) during Steady State and Transient Conditions, May 1981. Z1 sin q Reactive Power Compensation Department, Sweden, May Vo = nominal phase voltage (1981). Natural loading or surge loading of a line, 7Erinmez, I.A. (ed.), Static VAr Compensators, Cigre Working 2 Group 38.01, Task Force No. 2 on SVC (1986). Vo Po = per phase (24.10) 8 IEEE – Delhi Section, Advance Level Course on Reactive Power Z1 Control in Electrical Power Systems, December (1984). 9Kundor, P., Power System Stability and Control, McGraw- Po P = ◊ sin d (24.11) Hill, New York. sin q 10 Lakervi, E. and Holmes, E.J., Electricity Distribution Network Design, Peter Peregrinus, London. Analysis of radial lines 11 Miller, T.J.E., Reactive Power Control in Electric Systems, John Wiley, New York (1982). Es = Vr cos qr + J Z1 · I1 · sin qr (24.12) 12 Prasad, J. and Ambarani, V., Static VAr Compensator for Industries, BHEL, India, 59th R&D Session, Feb (1994). Es = phase voltage at the transmitting end. 13 Research Station, M.P. Electricity Board, Central Board of Vr = phase voltage at the receiving end Irrigation and Power, India, Series Capacitor Application to qr = line length effect or Ferranti effect at the end of Sub-transmission Systems Case Studies. Technical Report No. the line, in degrees 66, Nov. (1988). I1 = load current 14 Weeks, W.L., Transmission and Distribution of Electrical Energy (Design aspects), Harper & Row, New York. Z1 = surge impedance of the line 15 Integrated Substation Automation using an EEM System, Power Measurement (a global company for energy information Analysis of symmetrical lines technology). E = V · cos + J Z · I · sin (24.13) 16 Holstein, Dennis K., Substation Information Security, OPUS s m qm 1 1 qm Publishing (2004). Vm = voltage at the midpoint of the line 17 Young, Michael A., SCADA Systems Security GSEC Practical Requirements (v1.4b), Option 1 (2004). qm = line length or Ferranti effect up to the midpoint of the line 18 SCADA systems and their security. Beacon – Institute of Electrical and Electronics Engineers (Inc.), 21, No. 1, IEEE Delhi Section House Journal, (2002). 19 Understanding SCADA System Security Vulnerabilities, Riptech Further Reading Inc., Alexandria, Virginia, USA, (2001). 20 EMS-SCADA Overview, MICON Systems (http: www. 1 Central Board of Irrigation and Power, India (Indian National miconsystems.com) Committee for Cigre), Electric Power Transmission at voltages 21 Jammes Antoine, intelligent LV switchboards, Schneider (Merlin of 1000 kV and Above, Oct. (1984). Gerin), Technical paper n∞186, June (1997).