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M.I.E.T. ENGINEERING COLLEGE

(Approved by AICTE and Affiliated to Anna University Chennai)

TRICHY – PUDUKKOTTAI ROAD, TIRUCHIRAPPALLI – 620 007

DEPARTMENT OF ELECTRICAL AND

ELECTRONICS ENGINEERING

COURSE MATERIAL

EE6603 - POWER SYSTEM OPERATION AND CONTROL

III YEAR – VI SEMESTER

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M.I.E.T. ENGINEERING COLLEGE

(Approved by AICTE and Affiliated to Anna University Chennai)

TRICHY – PUDUKKOTTAI ROAD, TIRUCHIRAPPALLI – 620 007

DEPARTMENT OF ELECTRICAL AND ELECTRONICS ENGINEERING (SYLLABUS)

Sub. Code : EE6603 Branch/Year/Sem : EEE/III/V

Sub Name : POWER SYSTEM OPERATION AND CONTROL Batch : 2016-2020

Staff Name : E.MUTHUKUMARAN Academic Year : 2019-2020

EE6603 POWER SYSTEM OPERATION AND CONTROL L T P C

3 0 0 3 UNIT I INTRODUCTION 9

An overview of power system operation and control - system load variation - load characteristics -load curves and load-duration curve - load factor - diversity factor - Importance of load forecasting and quadratic and exponential curve fitting techniques of forecasting – plant level and system level controls . UNIT II REAL POWER - FREQUENCY CONTROL 9

Basics of speed governing mechanism and modeling - speed-load characteristics – load sharing between two synchronous machines in parallel - control area concept - LFC control of a single-area system - static and dynamic analysis of uncontrolled and controlled cases - two-area system – modeling - static analysis of uncontrolled case - tie line with frequency bias control - state variable model - integration of economic dispatch control with LFC. UNIT III REACTIVE POWER–VOLTAGE CONTROL 9

Generation and absorption of reactive power - basics of reactive power control - excitation systems – modeling - static and dynamic analysis - stability compensation - methods of voltage control: tap changing transformer, SVC (TCR + TSC) and STATCOM – secondary voltage control. UNIT IV UNIT COMMITMENT AND ECONOMIC DISPATCH 9 Formulation of economic dispatch problem – I/O cost characterization – incremental cost curve – coordination equations without and with loss (No derivation of loss coefficients) - solution by

direct method and λ-iteration method - statement of unit commitment problem – priority-list

method – forward dynamic programming. UNIT V COMPUTER CONTROL OF POWER SYSTEMS 9

Need for computer control of power systems - concept of energy control centre - functions – system monitoring - data acquisition and control - system hardware configuration – SCADA and EMS functions - network topology - state estimation – WLSE - Contingency Analysis - state transition diagram showing various state transitions and control strategies. TOTAL : 45 PERIODS

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TEXT BOOKS:

1. Olle.I.Elgerd, „Electric Energy Systems theory - An introduction‟, Tata McGraw Hill Education Pvt.Ltd., New Delhi, 34th reprint, 2010. 2. Allen. J. Wood and Bruce F. Wollenberg, „Power Generation, Operation and Control‟, John Wiley & Sons, Inc., 2003. 3. Abhijit Chakrabarti, Sunita Halder, „Power System Analysis Operation and Control‟, PHI learning Pvt. Ltd., New Delhi, Third Edition, 2010. REFERENCES:

1. Nagrath I.J. and Kothari D.P., „Modern Power System Analysis‟, Tata McGraw-Hill, Fourth Edition, 2011. 2. Kundur P., „Power System Stability and Control, Tata McGraw Hill Education Pvt. Ltd., New Delhi, 10th reprint, 2010. 3. Hadi Saadat, „Power System Analysis‟, Tata McGraw Hill Education Pvt. Ltd., New Delhi, 21st reprint, 2010. 4. N.V.Ramana, “Power System Operation and Control,” Pearson, 2011. 5. C.A.Gross, “Power System Analysis,” Wiley India, 2011.

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POWER SYSTEM OPERATION AND CONTROL

UNIT 1 – INTRODUCTION

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1.1 SHORT TERMS

Connected load

The term connected load means the sum of continuous ratings of all the

equipments connected to supply systems.

Load curve

Load on the power system is seldom constant. It varies from time to time. The

curve showing the variation of load on the power station with respect to time is known as

a load curve. It can be plotted on a graph taking load on Y-axis and time on X-axis. There

are three types, Daily load curve, Monthly load curve, Yearly load curve.

Load duration curve

When the load elements of a load curve are arranged in the order of descending

magnitudes the curve then obtained is called load duration curve. This type of curve

which indicates the variation of load, but with the loads arranged in descending order of

magnitude, i.e, the greatest load on the left and lesser loads towards right.

Load factor

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The load factor defined as the ratio between the average demand to the maximum

demand. The load factor can be written as

𝐿𝑜𝑎𝑑 𝐹𝑎𝑐𝑡𝑜𝑟 =𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝐷𝑒𝑚𝑎𝑛𝑑

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐷𝑒𝑚𝑎𝑛𝑑

Diversity factor

The ratio of the sum of individual maximum demand on power station is known as

diversity factor.

𝐷𝑖𝑣𝑒𝑟𝑠𝑖𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟 =𝑆𝑢𝑚 𝑜𝑓 𝑖𝑛𝑑𝑖𝑣𝑖𝑑𝑢𝑎𝑙 𝑚𝑎𝑥𝑖𝑚𝑢𝑚 𝑑𝑒𝑚𝑎𝑛𝑑

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐷𝑒𝑚𝑎𝑛𝑑 𝑜𝑓 𝑡𝑕𝑒 𝑝𝑜𝑤𝑒𝑟 𝑠𝑡𝑎𝑡𝑖𝑜𝑛

Average demand

The average of loads occurring on the power station in a given period (day or

month or year) is known as average demand.

Daily average demand =no of units generated per day

24 hours

Monthly average demand =no of units generated in month

no of hours in a month

Yearly average demand =no of units generated in a year

no of hours in a year

Plant use factor

It is the ratio of kWh generated to the product of plant capacity and the number of

hours for which the plant was in operation.

Plant use factor =Station output in kWh

Plant capacity x Hours of use

Maximum demand

It is the greatest demand of load on the power station during a given period.

Spinning Reserve

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Spinning reserve is that generating capacity which is connected to the bus and is

ready to take load

Hot Reserve

Hot reserve is that reserve generating capacity which is in operation bus is not in

service.

Cold Reserve

Cold reserve is that reserve generating capacity which is available for service but is

not in operation.

Economic Dispatch Control (EDC)

When the economical load distribution between a number of generator units

is considered, it is found that the optimum generating schedule is affected when an

incremental increased at one of the units replaces a compensating decrease at every other

unit, in term of some incremental cost. Optimum operation of generators at each

generating station at various station load levels is known as unit commitment.

1.2 OVERVIEW OF POWER SYSTEM CONTROL

Speed regulation of the governor

Controls the boiler pressure, temperature & flows

Speed regulation concerned with steam input to turbine

Load is inversely proportional to speed

Governor senses the speed & gives command signal

Steam input changed relative to the load requirement.

Governor Control

Governor is a device used to control the speed of a prime mover. A governor

protects the prime mover from over speed and keeps the prime mover speed at or

near the desired revolutions per minute.

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When a prime mover drives an alternator supplying electrical power at a given

frequency, a governor must be used to hold the prime mover at a speed that will

yield this frequency. An unloaded diesel engine will fly to pieces unless it is under

governor control.

Load frequency control

Sense the bus bar frequency & compare with the tie line power frequency

Difference fed to the integrator & to speed changer

Tie line frequency maintained constant

Economic dispatch control

When load distribution between a numbers of generator units considered optimum

schedule affected when increase at one replaces a decreases at other.

Optimum use of generators at each station at various loads is known as economic

dispatch control.

Automatic voltage regulator

Regulate generator voltage and output power

Terminal voltage & reactive power is also met

System voltage control

Static VAR compensator

Synchronous condenser

Tap changing transformer

Switches

Capacitor

Reactor

Security control

Monitoring & decision

Control

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Monitoring & decision

Condition of the system continuously observed in the control centers by relays.

If any continuous severe problem occurs system is in abnormal condition.

Control

Proper commands are generated for correcting the abnormality in protecting the

system.

If no abnormality is observed, then the normal operation proceeds for next

interval.

Central controls are used to monitor the interconnected areas

Inter connected areas can be tolerate larger load changes with smaller frequency

deviations

Central control centre monitors information about frequency, generating unit

outputs and tie line power flows to interconnected areas.

This information is used by automation load frequency control in order to maintain

area frequency at its scheduled value.

1.3 NEED FOR VOLTAGE REGULATION IN POWER SYSTEM

Knowledge of voltage regulation helps in maintaining the voltage at the load

terminals within prescribed limits under fluctuating load conditions, by employing

suitable voltage control equipment. The following points are to be considered.

The transmission lines and the distribution lines need voltage control at various

stages to maintain the voltage at the last consumer‘s premises within permissible

limits.

Variations in supply voltage are detrimental in various aspects.

Below normal voltage substantially reduces the light output from incandescent

lamps.

Above normal voltage reduces the life of the lamps.

Motors operated at below normal voltage draw abnormally high currents and may

overheat, even when carrying no more than the rated horse power load.

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If the voltage of the system deviates from the nominal value, the performance of

the devices suffers and its life expectancy drops.

The real line losses depend as much upon the reactive line as upon the real time

power flow. The reactive line flow depends upon line end voltages.

By adjusting the excitation of the generator at the sending end below a certain

limit may result in instability of the system and excitation above certain level will

result in overheating of the rotor.

Service voltages are usually specified by a nominal value and the voltage

maintained is ± 5 % of the nominal value.

1.4 NEED FOR FREQUENCY REGULATION IN POWER SYSTEM

Knowledge of frequency regulation helps in maintaining the system frequency that is

speed of the alternator within prescribed limits under fluctuating load conditions, by

using speed governor and integral controller. In a network, considerable drop in

frequency occurs due to high magnetizing currents in induction motors and transformers.

The following points to be considered.

In any power system if the frequency changes there won‘t be required receiving

end voltage. If we connected two systems in parallel, it will spoil the system.

The generator turbines, particularly steam driven ones are designed to operate at a

very precise speed.

Most of AC motors rub at speeds that are directly related to the frequency.

The overall operation of a power system can be much better controlled if the

frequency error is kept within strict limits.

A large number of electrically operated clocks are used. They are all driven be

synchronous motors and the accuracy of these clocks is a function not only of a

frequency error, but actually of the integral of this error.

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Constant turbine speed is an important requirement. The velocity of the expanding

steam is beyond our control and the turbine efficiency requires perfect speed

match.

Unusual deviations in the frequency can be detected earlier.

When two systems working at different frequencies are to be tied together to make

same frequency, frequency converting stations or links are required

1.5 LOAD FORECASTING

The load on their systems should be estimated in advance. This estimation in

advance is known as load forecasting. Load forecasting based on the previous experience

without any historical data.

1.5.1 Classification of load forecasting

Forecasting Lead Time Application

Very short time Few minutes to half an hour Real time control, real time

Security evaluation.

Short term Half an hour to a few hours

Allocation of spinning

reserve, unit commitment,

Maintenance scheduling.

Medium term Few days to a few weeks Planning or seasonal peak

winter, summer.

Long term Few months to a few years To plan the growth of the

generation capacity

1.6 BASIC P-F AND Q-V CONTROL LOOPS

Static changes in ∆Pi the real bus power affect the bus phase angle and not the bus

voltage magnitudes. This change affects the real line flows and not the reactive

line flows.

Static changes in ∆Qi in the reactive power affect the bus voltage magnitudes and

the phase angle. This change affects the reactive line flows and not the real line

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flows. A static change in the reactive bus power affects the bus voltage at the

particular bus and has little effect on the magnitude of voltage.

1.6.1 Q-V Control Loop

The automatic voltage regulator circuit or QV control loop as shown in figure.

This loop is used for voltage control. This bus bar voltage is stepped down using a

potential transformer to a small value of voltage.

This is sent to the rectifier circuit which converts the AC voltage into DC voltage

and a filter circuit used in this removes the harmonics. The voltage Vi, thus

rectified is compared with a reference voltage Vref in the comparator and a voltage

error signal is generated.

The amplified form of this voltage gives a condition for the exciter to increase the

field current based on its polarity. The output of the generator is stepped up using

a transformer and fed to the n-bus bar. Thus the voltage is regulated and controlled

in this control circuit.

1.6.2 PF Control Loop

Primary ALFC

The circuit primarily controls the steam valve leading to the turbine. A speed

sensor senses the speed of the turbine.

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This is compared with a reference speed, governor whose main activity is to

control the speed of the steam by closing and opening of the control valve.

That is, if the differential speed is low, then the control valve is opened to let out

the steam at high speed thereby increasing turbine‘s speed and vice versa. The

control of speed in turn controls the frequency

Secondary ALFC

This circuit involves a frequency sensor that senses the frequency of the bus bar

and compares it with Tie line power frequencies in the signal mixer.

The output of this is an Area Control Error (ACE) which is sent to the speed

changer through integrator.

The speed changer gives the reference speed to the governor. Integral controller is

used to reduce the steady state frequency change to zero.

After this part of the circuit, is the introduction of the Primary ALFC loop whose

function has already been described. Thus, the two loops together help in

controlling the speed which in turn controls the Frequency since N α f.

Using the relation, Speed N =120 f/P

where, f is frequency in Hz and P is number of poles.

1.7 SYSTEM VOLTAGE CONTROL

This involves the process of controlling the system voltage within tolerable limits.

This includes the devices such as static VAR compensators, synchronous

condenser, tap changing transformer, switches, capacitor and reactor.

The controls described above contribute to the satisfactory operation of the power

system by maintaining system voltages, frequency and other system variables

within their acceptable limits.

They also have a profound effect on the dynamic performance of power system

and on its ability to cope with disturbances.

Security control

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The main objective of real time power system operation requires a process guided by

control and decisions based on constant monitoring of the system condition. The power

system operation is split into two levels.

Level 1: Monitoring and Decision

The condition of the system is continuously observed by the control centres by

protective relays for faults or contingencies caused by equipment trouble and

failure.

If any of these monitoring devices identifies a sufficiently severe problem at the

sample time, then the system is in an abnormal condition. If no such abnormality

is observed, then the system is in a normal condition.

Level 2: Control

At each sample, the proper commands are generated for correcting the abnormality

on protecting the system from its consequences. If on abnormality is observed,

then the normal operation proceeds for the next sample interval.

Central controls also play an important role in modern power systems. Today

systems are composed of interconnected areas, where each area has its own

control centre. There are power to handle anticipated load peaks and unanticipated

generator outages. Interconnected areas can also tolerated large load changes with

smaller frequency deviations at spinning reserve and standby provides a reserve

margin.

The central control centre information including area frequency, generating unit

outputs and tie line power floes to interconnected areas. This information is used

by automatic load frequency control in order to maintain area frequency at its

scheduled values.

1.8 PLANT LEVEL CONTROL

(i) Governor control or Prime mover control

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Governor control or Prime mover controls are concerned with speed regulation of

the governor and the control of energy supply system variables such as boiler pressure,

temperature and flows. Speed regulation is concerned with steam input to turbine. With

variation in load, speed of governor varies as the load is inversely proportional to speed.

The speed of the generator varies and the governor senses the speed and gives a

command signal, so that, the steam input of the turbine is changed relative to the load

requirement.

(ii) Automatic Voltage Regulator (AVR) or Excitation control

The function of Automatic Voltage Regulator (AVR) or Excitation control is to

regulate generator voltage and relative power output. As the terminal voltage varies the

excitation control, it maintains the terminal voltage to the required standard and the

demand of the reactive power is also met by the excitation control unit.

System level control

(i) Load Frequency Control (LFC)

This involves the sensing of the bus bar frequency and compares with the tie line

power frequency. The difference of the signal is fed to the integrator and it is given to

speed changer which generates the reference speed for the governor. Thus, the frequency

of the tie line is maintained as constant.

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(ii) Economic Dispatch Control (EDC)

When the economical load distribution between a number of generator units is

considered, it is found that the optimum generating schedule is affected when an

incremental increased at one of the units replaces a compensating decrease at every other

unit, in term of some incremental cost. Optimum operation of generators at each

generating station at various station load levels is known as unit commitment.

(iii) System Voltage Control.

This involves the process of controlling the system voltage within tolerable limits.

This includes the devices such as static VAR compensators, synchronous condenser, tap

changing transformer, switches, capacitor and reactor. The controls described above

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contribute to the satisfactory operation of the power system by maintaining system

voltages, frequency and other system variables within their acceptable limits. They also

have a profound effect on the dynamic performance of power system and on its ability to

cope with disturbances.

(iv) Security control

The main objective of real time power system operation requires a process guided

by control and decisions based on constant monitoring of the system condition. The

power system operation is split into two levels.

UNIT 3 – REACTIVE POWER VOLTAGE CONTROL

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3.1 GENERATION AND ABSORPTION OF REACTIVE POWER.

Synchronous Generators

Synchronous machines can be made to generate or absorb reactive power

depending upon the excitation (a form of generator control) applied. The ability to supply

reactive power is determined by the short circuit ratio.

𝑆𝐶𝑅 =1

𝑋𝑆

Where XS = Synchronous reactance

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An over excited synchronous machine operating on no load generates reactive

power. Under excited synchronous machine absorbs reactive power.

Synchronous Compensators

Certain smaller generators, once run up to speed and synchronized to the system,

can be declutched from their turbine and provide reactive power without producing real

power.

Capacitive and Inductive Compensators (Series capacitors and shunt reactors)

These are devices that can be connected to the system to adjust voltage levels .A

capacitive compensator produces an electric field thereby generating reactive power and

an inductive compensator produces a magnetic field to absorb reactive power.

Compensation devices are available as either capacitive or inductive alone or as a hybrid

to provide both generation and absorption of reactive power.

Over head lines

Overhead lines and underground cables, when operating at the normal system voltage,

both produce strong electric fields and so generate reactive power. When current flows

through a line or cable it produces a magnetic field which absorbs reactive power. A

lightly loaded overhead line is a net generator of reactive power while a heavily loaded

line is a net absorber of reactive power.

Cables

In the case of cables designed for use at 275 or 400kV the reactive power generated by

the electric field is always greater than the reactive power absorbed by the magnetic field

and so cables are always net generators of reactive power.

Transformers

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Transformers always absorb reactive power regardless of their loading. At no load shunt

magnetizing effect is predominant and at full load series leakage inductance effect is

predominant. The reactive power absorbed by transformer is given by

𝑄𝑇 = 3|𝐼|2𝑋 𝑉𝐴𝑅 𝑜𝑟 3𝐾𝑉𝐴 . 𝑋𝑇 𝐾𝑉𝐴𝑅

where

I = Current in Amps flowing through transformer

X = Transformer reactance per phase

3.2 ROLE OF TAP CHANGING TRANSFORMER IN VOLTAGE

CONTROL

All power transformers on transmission lines are provided with taps for control

of secondary voltage. The tap changing transformers do not control voltage by regulating

the flow of reactive VARs but by changing transformation ratio. There are two types of

tap changing transformers

Off-load tap changing transformers.

On-load (under load) tap changing transformers.

Off -load Tap Changing Transformer:

The off-load tap changing transformer which requires the disconnection of the

transformer when the tap setting is to be changed. Off- load tap changers are used when it

is to be operated in frequently due to growth or some seasonal change.

On-load tap changing transformer:

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On –load tap changing transformer is used when changes in transformer ratio to

be needed frequently, & no need to switch off the transformer to change the tap of

transformer. it is used on power transformers, auto transformers & bulk distribution

transformer & at other points of load service.

The modern practice is to use on-load tap changing transformer. In the position shown

the voltage is maximum and since the currents divide equally & flow in opposition

through the coil b/w Q1& Q2 the resultant flux is zero & hence minimum impedance.

To reduce the voltage the following operations are required in sequence:

i. Open Q1.

ii. Move selector switch S1 to the next contact.

iii. Close Q1.

iv. Open Q2.

v. Move selector switch S2 to the next contact.

vi. Close Q2.

Thus six operations are required for one change in tap position. The voltage change b/w

taps is often 1.25 percent of the nominal voltage.

Applications:

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Autotransformers used to change from one subsystem to another are often

furnished with under load or on load tap changing facilities (ULTC). They may be

controlled either automatically or manually. These are usually present throughout

the network interconnecting transmission of system different levels.

The taps on this transformer provide a convenient means of controlling reactive

power flow b/w subsystems. This in turn can be used to control line voltage

profiles & reactive power losses.

The control of single transformer will cause changes in voltages at its terminals. In

addition, it influences the reactive power flow through the transformer.

During high system load conditions, the network voltages are kept at the highest

practical level to maximize reactive power requirements & increase the

effectiveness of shunt capacitors & line charging.

3.3 STATIC VAR COMPENSATOR

The term static var compensator is applied to a number of static var compensation

devices for use in shunt reactive control.

These devices consist of shunt connected, static reactive element (linear or non

linear reactors and capacitors) configured into a var compensating system.

Static var compensators (SVCs) constitute a mature technology that is finding

widespread usage in modern power systems for load compensation as well as

transmission-line applications.

Static var compensators (SVCs) are used primarily in power systems for voltage

control as either an end in itself or a means of achieving other objectives, such as

system stabilization SVCs are used because SVC at suitable points of a

transmission system can maintain specific voltage profile and can limit the voltage

and frequency deviations under disturbances

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Static VAR compensators are located in receiving substations and distribution

systems for smooth and steeples variation of compensation of reactive power

injected into line by shunt capacitors and shunt reactors.

Further the transient stability can be improved and the system transmission

capacity can be increased both under operating and fault conditions.

The performance of SVC voltage control is critically dependent on several factors,

including the influence of network resonances, transformer saturation,

geomagnetic effects, and voltage distortion.

When SVCs are applied in series-compensated networks, a different kind of

resonance between series capacitors and shunt inductors becomes decisive in the

selection of control parameters and filters used in measurement circuits.

Let QC be the reactive power charging by capacitor

Let QL be the reactive power absorbed by inductor

Net reactive power injected to the bus Q = QC – QL

For light load condition QL > QC

For heavy load condition QL< QC

3.3.1 V-I Characteristics of the SVC

The steady-state and dynamic characteristics of SVCs describe the variation of

SVC bus voltage with SVC current or reactive power.

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Two alternative representations of these characteristics such as

Part (a) illustrates the terminal voltage–SVC current characteristic and

Part (b) depicts the terminal voltage– SVC reactive-power relationship.

3.3.2 Advantages/ Merits of SVC

Bus voltage can be controlled

Improves system stability, voltage stability

Reduces power oscillations

Minimize transmission losses

Increase in steady-state power-transfer capacity

Enhancement of transient stability

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3.3.3 Types of SVC

Variable impedance type

Current source type

Voltage source type

The followings are the basic types of reactive power control elements which makes all or

parts of SVC

Saturated reactor

Thyristor controlled Reactor

Thyristor switched capacitor

Thyristor Switched Reactor

Thyristor controlled Transformer

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3.4 WAYS OF IMPROVING VOLTAGE STABILITY AND REAL

POWER LOSS MINIMIZATION

Reactive power compensation is often most effective way to improve both power

transfer capability and voltage stability.

The control of voltage levels is accomplished by controlling the production,

absorption and flow of reactive power.

To control voltage throughout the system we have to use addition devices to

compensate reactive power.

Reactive compensation can be divided into series and shunt compensation. It can

be also divided into active and passive compensation.

But mostly consideration will be focused on shunt capacitor banks; the leading

current drawn by the shunt capacitors compensates the lagging current drawn by

the load.

The selection of shunt capacitors depends on many factors, the most important of

which is the amount of lagging reactive power taken by the load.

Variable VAR compensation is achieved using switched capacitors. Depending on

the total VAR requirement, capacitor banks are switched into or switched out of

the system.

The smoothness of control is solely dependent on the number of capacitors

switching units used. The switching is usually accomplished using relays and

circuit breakers.

Series Switched capacitors are connected in series with the line to control power

flow and minimizing transmission losses.

Shunt Switched capacitors are connected in parallel with the load bus to ground to

enhance the voltage stability.

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3.5 THE THYRISTOR-SWITCHED CAPACITOR (TSC)

The circuit shown in Fig. 1 consists of a capacitor in series with a bidirectional

thyristor switch.

It is supplied from an ideal ac voltage source with neither resistance nor reactance

present in the circuit. The analysis of the current transients after closing the switch

brings forth two cases:

Fig. 1 . Switching of a capacitor at a voltage source: (a) a circuit diagram and (b) the current and

voltage

Case 1: The capacitor voltage is not equal to the supply voltage when the thyristors are

fired. Immediately after closing the switch, a current of infinite magnitude flows and

charges the capacitor to the supply voltage in an infinitely short time. The switch realized

by thyristors cannot withstand this stress and would fail.

Case 2: The capacitor voltage is equal to the supply voltage when the thyristors are fired,

as illustrated in Fig. The analysis shows that the current will jump immediately to the

value of the steady-state current. The steady state condition is reached in an infinitely

short time.

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To overcome the problems discussed above, a small damping reactor is added in

series with the capacitor, as depicted in Fig. 2.

A basic single-phase TSC consists of an anti-parallel–connected thyristor-valve

pair that acts as a bidirectional switch in series with a capacitor and a current

limiting small reactor, as shown in Fig.

Figure 2. Voltages after turn-off to the TSC: (a) a circuit diagram and (b) the voltage–

current waveforms.

The thyristor switch allows the conduction for integral number of half-cycles. The

capacitor is not phase controlled, as is a TCR.

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The thyristor valves are turned on at an instant when minimum voltage is sensed

across the valves to minimize the switching transients.

Barring these initial transients, the TSC current is sinusoidal and free from

harmonics, thus obviating the need for any filters.

The small-series inductor is installed to limit current transients during overvoltage

conditions and planned switching operations, as well as when switching at

incorrect instants or at the inappropriate voltage polarity.

The inductor magnitude is chosen to give a natural resonant frequency of four to

five times the system nominal frequency, which ensures that the inductance

neither creates a harmonic-resonant circuit with the network nor hampers the TSC

control system.

Another function of this series inductor is to act in combination with the capacitor

as a filter for harmonics generated by the associated TCR. In some cases,

discharge circuits are provided with the capacitors to rapidly dissipate the remnant

charge on the capacitor after a switch-off.

A 3-phase TSC unit comprises three single-phase TSCs connected in a delta,

which are usually supplied by the delta secondary winding of a step-down

transformer

A practical TSC compensator involves n 3-phase TSC banks of equal rating

connected in shunt.

The overall TSC susceptance at any given instant is the sum of conducting TSC.

In some cases, the ratings of different constituent TSC steps may be chosen based

on a binary system.

In this scheme, n −1 capacitors are rated for susceptance B and one capacitor is

rated for susceptance B2. Thus the total numbers of possible TSC steps get

extended to 2n. An example of such a TSC is shown in Fig. 3

The TSC provides a fast response—typically between one-half to one cycle.

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However, this response time may be extended because of any delays in the

measurement and control systems.

Operating Characteristics

The TSC has a discrete voltage–current operating characteristic as shown in Fig. 4

The shape of this characteristic is a function of the number of TSC units, their individual

ratings, and a hysteresis voltage DV, which is built in to avoid undesirable frequent

switching of capacitors.

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3.6 VOLTAGE CONTROL IN A TRANSMISSION SYSTEM BY

BOOSTER TRANSFORMER

The booster transformer performs the function of boosting the voltage. It can be

installed at a substation or at any intermediate point of line.

In the circuit shown in figure P and Q are the two relays. The secondary of the

booster transformer is connected in series with the line whose voltage is to be

controlled and the primary of the booster transformer is supplied from a regulating

transfoemer with on load tap changer gear.

The booster can be brought in to the circuit by the closure of relay Q and the

opening of the relay P, and vice versa as shown in figure.

The secondary of the booster transformer injects a voltage in phase with the line

voltages.

Advantages

It can be installed at any intermediate point in the system

Rating of booster transformer is about 10% of that of the main transformer

(product of current and injected voltage)

Disadvantages

When used in conjunction with main transformer

More expensive than a transformer with on load tap changings

Less efficient due to losses in booster

Requires more space

30

3.7 REACTIVE POWER REQUIREMENT FOR CONTROL OF

VOLTAGE IN LONG RADIAL LINES

Long radial lines - The efficacy factor

Long radial transmission lines present a problem of unequal voltage along the

length. Once energized shunt capacitance of the line becomes a source of reactive

power (var).

Under low load conditions the var generation exceeds the var consumption.

Without compensation, under light load conditions the endpoint voltage may

exceed the upper permissible voltage limit.

Under heavy load conditions the voltage may dip below the lower permissible

limit. The voltage profile of the line becomes flat at surge impedance load (SIL).

In practice, on account of the transient stability considerations the permissible

loading of long lines are kept below surge impedance load & therefore problem is

to restrict overvoltage along the length of the line. This is solved by connection of

shunt reactors.

Controlled shunt compensation of long lines improve the voltage profile. It also

enhances the power transfer capability of a long line by giving voltage support.

31

Fig.1 Voltage profiles of an uncompensated line

Shunt Compensation

Figure 2 shows the principles and theoretical effects of shunt reactive power

compensation in a basic ac system, which comprises a source V1, a power line and

a typical inductive load.

Figure 2(a) shows the system without compensation, and its associated phasor

diagram. In the phasor diagram, the phase angle of the current has been related to

the load side, which means that the active current IP is in phase with the load

voltage V2. Since the load is assumed inductive, it requires reactive power for

proper operation and hence, the source must supply it, increasing the current from

the generator and through power lines.

If reactive power is supplied near the load, the line current can be reduced or

minimized, reducing power losses and improving voltage regulation at the load

terminals. This can be done in three ways: a) with a capacitor, b) with a voltage

source, or c) with a current source.

In Fig. 2(b), a current source device is being used to compensate the reactive

component of the load current (IQ). As a result, the system voltage regulation is

32

improved and the reactive current component from the source is reduced or almost

eliminated.

If the load needs leading compensation, then an inductor would be required. Also

a current source or a voltage source can be used for inductive shunt compensation.

The main advantages of using voltage or current source VAR generators (instead

of inductors or capacitors) is that the reactive power generated is independent of

the voltage at the point of connection.

Fig. 2: Principles of shunt compensation in a radial ac system.

a) Without reactive compensation.

b) Shunt compensation with a current source.

33

Series Compensation

VAR compensation can also be of the series type. Typical series compensation

systems use capacitors to decrease the equivalent reactance of a power line at rated

frequency

Fig. 3: Principles of series compensation.

a) The same system of fig. 2(a) without compensation.

b) Series compensation with a voltage source.

The connection of a series capacitor generates reactive power that, in a self-

regulated manner, balances a fraction of the line's transfer reactance. The result is

improved functionality of the power transmission system through:

i. increased angular stability of the power corridor,

ii. improved voltage stability of the corridor,

iii. Optimized power sharing between parallel circuits.

34

Like shunt compensation, series compensation may also be implemented with

current or voltage source power system of figure 3(a), also with the reference

angle in V2, and Fig. 2(b) the results obtained with the series compensation

through a voltage source, which has been adjusted again to have unity power

factor operation at V2.

However, the compensation strategy is different when compared with shunt

compensation.

In this case, voltage VCOMP has been added between the line and the load to change

the angle of V2 which is now the voltage at the load side.

With the appropriate magnitude adjustment of VCOMP, unity power factor can

again be reached at V2. As can be seen from the phasor diagram of Fig. 3(b),

VCOMP generates a voltage with opposite direction to the voltage drop in the line

inductance because it lags the current IP.

Series Capacitor are installed in series with a transmission line as shown in Fig.3,

which means that all the equipment must be installed on a platform that is fully

insulated for the system voltage (both the terminals are at the line voltage). On this

platform, the main capacitor is located together with overvoltage protection

circuits. The overvoltage protection

3.8 METHODS OF VOLTAGE CONTROL

The following are the methods of voltage control

By excitation control

By static shunt capacitors

By static series capacitors

By static shunt reactors

By synchronous condensers

The remaining methods of voltage control are

Tap changing transformer

35

Booster transformer

Regulating transformer

Static var compensators

3.8.1 by excitation control

Excitation system, where the exciting current is fed from a controlled rectifier that

gets its power either directly from the generator terminals or from the power

plant‘s auxiliary power system, normally containing batteries.

The terminal voltage of the alternator is sampled, rectified and compared with a

reference voltage; the difference is amplified and fed back to the exciter field

winding to change the excitation current.

In the static excitation system, the generator field is fed from a thyristor network

shown in Fig. It is just sufficient to adjust the thyristor firing angle to vary the

excitation level.

A major advantage of such a system is that, when required the field voltage can be

varied through a full range of positive to negative values very rapidly with the

ultimate benefit of generator Voltage regulation during transient disturbances.

36

3.8.2 by Static Shunt Capacitors

Capacitors produce var and may be connected in series or shunt in the system.

Series capacitors compensate the line reactance in long overhead lines and thus

improve the stability limit.

However, they give rise to additional problems like high voltage transients, sub

synchronous resonance, etc. Shunt capacitors are used for reactive compensation.

Simplicity and low cost are the chief considerations for using shunt capacitor.

Further, for expanding systems additions can be made.

3.8.3 by static Series capacitors

Schematic diagram of a series capacitor installation

37

It is connected in series to compensate the inductive reactance of line. It reduces

the transfer reactance between the buses to which line is connected.

It increases maximum power that can be transmitted and reduces reactive power

loss. The reactive power produced by the series capacitor increases with increase

in power transfer. Series capacitor is self regulating in this regard.

Under fault conditions, the voltage across the capacitor rises and unlike a shunt

capacitor experiences many times its rated voltage due to fault currents.

A zinc oxide varistor in parallel with the capacitor may be adequate to limit this

voltage. For locations with high fault currents a parallel fast acting triggered gap is

introduced which operates for more severs faults.

When the spark gap trigger it is followed by closure of the bypass breaker. The

drainage reactor limits the frequency and magnitude of the current through the

capacitor when the gap sparks.

Advantages

To improve voltage regulation of distribution & industrial feeders.

To reduce light flicker problems.

To improve system stability

Applications

Voltage rise due to reactive current.

By passing the capacitor during faults & reinsertion after fault clearing.

3.8.4 by static Shunt Reactors

The shunt reactor is used to reduce or limit voltage rise due to open circuit or light

load.

Shunt reactor absorbs reactive power are usually used for EHV lines longer than &

when the far end line is opened , the receiving current flowing through the large

source inductive reactance will cause a rise in voltage at the receiving end of the

line.

38

Ferranti effect will cause a further rise in receiving end voltage during heavy loads

some of the reactors may have to be disconnected.

Advantages

Shunt reactors of sufficient size is permanently connected to the line to limit

fundamental frequency temporary over voltages.

To limit switching transients.

To maintain normal voltage under light load conditions.

39

During heavy load conditions, some of the reactors are disconnected by using

switching reactors & circuit breakers.

3.8.5 by Synchronous Condenser

Synchronous condenser is a synchronous machine running without a prime mover

or a mechanical load. By controlling the field excitation, it can be made generate

or absorb reactive power.

It can automatically adjust reactive power output to maintain constant terminal

voltage by using voltage regulator.

The advantage of using synchronous condenser is its flexibility for use in all load

conditions because it supplies VARs when over excited during peak load

conditions and it consumes VARs when under excited during load conditions.

The smooth variation of reactance VARs is possible as compared to step variation

in static capacitors.

Synchronous condensers can be over loaded for short duration; where as static

capacitors cannot withstand mechanical over loads. Synchronous condensers are

otherwise called active compensators.

40

Synchronous condensers connected in parallel are used to provide constant voltage

at that particular point. The synchronous compensator is connected to the tertiary

winding of the main transformer for voltage and reactive power control at both

transmission and sub transmission levels.

Advantages

Reactive power production is not affected by system voltage.

Flexibility of operation at all load conditions.

Smooth variation of reactive VARs as compared to step-by-step variation in

static capacitors.

It is used in HVDC converter stations.

Disadvantages

Installation cost is high.

It can fall out of step which may result in a large sudden change in voltage.

The machine adds to the short circuit capacity of the system during fault

condition.

Synchronous compensators cannot be designed to work at more than about

20kv.

41

UNIT 4 – COMMITMENT AND ECONOMIC LOAD DISPATCH

-----------------------------------------------------------------------------------------------------------------

4.1 UNIT COMMITMENT PROBLEM

4.1.1 UC Statement:

To select the generating units that will supply the forecasted (estimated load in

advance) load of the system over a required period of time at minimum cost as well as

provide a specified margin of the operating reserve, known as spinning reserve. This

procedure is known as Unit Commitment.

4.1.2 Constraints in unit commitment

1. Spinning reserve.

2. Thermal constraints.

Minimum uptime.

Minimum down time.

Crew Constraints.

3. Other constraints.

Hydro constraints.

Must run constraints.

Fuel constraints.

Spinning Reserve

Spinning reserve is total amount of generation available from all units

synchronized on the system minus the present load and losses being supplied.

Spinning reserve = Total amount of generation - [present load + losses]

Spinning reserve must be established, so that the loss of one or more units does not cause

drop in system frequency (i.e., If one unit is lost, the spinning reserve unit has to make p

42

for the loss in a specified time period. Spinning reserve is the reserve generating capacity

running at zero load or no load.

Thermal constraints

A thermal unit can withstand only gradual temperature changes and is required to

take some hours to bring the unit on-line. For thermal plants, one hour is the smallest

time period that should be considered for unit commitment solutions as the start-up and

shut-down time for many units is of this order. The thermal unit constraints are minimum

up time, minimum down time and crew constraints.

Minimum up time

Once the unit is running, it should not be turned off immediately.

Minimum down time

Once the unit is decommited, there is a minimum time before it can be recommitted.

Crew constraints

If a plant consists of two or more units, they cannot both be turned on at the same time.

Since there are not enough crew members to attend both units while starting up.

Other Constraints

Hydro-constraints

Unit commitment problem involves only thermal units. In Hydro-thermal

scheduling allocate maximum hydro units during rainy seasons and to allocate thermal

units during remaining periods. We are not considering hydro units for unit commitment

because start-up and shunt down time, operating costs are negligible. So we couldn‘t get

the optimal solution.

Must Run Constraints

Some units like nuclear units are given a must run status during certain times of the year

to maintain the voltage in the transmission system.

43

Fuel constraints

If thermal and hydro sources are available, a combined operation is economic and

advantageous. A system in which some units have limited fuel, or else have constraints

that require them to burn a specified amount of fuel in a given time, presents a most

challenging unit commitment problem.

4.2 UNIT COMMITMENT PROBLEM USING PRIORITY LIST

METHOD

Priority List Method (using Full Load Average Production Cost FLAPC)

Priority list method is the simplest unit commitment solution method which

consists of creating a priority list of units.

The priority list can be obtained by noting the full-load average production cost of

each unit.

Full load average production cost = {Net heat rate at full load} × Fuel cost

𝑭𝑳𝑨𝑷𝑪 =𝑪𝒊(𝑷𝑮𝒊)

𝑷𝑮𝒊

=𝑲𝒊 × 𝑯𝒊(𝑷𝑮𝒊)

𝑷𝑮𝒊

Assumptions:

No load costs are zero.

Unit input-output characteristics are linear between zero output and full load.

Start-up costs are fixed amount.

Ignore minimum up time and minimum down time.

Steps to be followed or Method of solving:

Determine the full load average production cost for each unit.

FLAPC = 𝐊×𝐇𝐢(𝐏𝐆𝐢)

𝑷𝑮𝒊

Form priority order based on average production cost,(Ascending Order)

Commit number of units corresponding to the priority order.

Calculate PG1, PG2…PGN from economic dispatch problem for the feasible

combinations only.

44

Assume load is dropping or decreasing determines whether dropping the next unit

will supply generation and spinning reserve.

If not, continue as it is.

If yes, go to next step.

Determine the number of hours H, before the unit will be needed again.

Check H< Minimum shut down time.

o If yes, go to last step.

o If not, go to next step.

Calculate two costs

Sum of hourly production costs for the next H hours with the unit up.

Recalculate the same for the unit down + start up cost for either cooling or

banking. If the second case is less expensive, the unit should be on.

Repeat this procedure until the priority list.

Merits:

No need to go for ‗N‘ combinations.

Take only one constraint.

Ignore the minimum up time and minimum down time.

Complication reduced.

Demerits:

Start up cost are fixed amount.

No load cost is not considered

4.3 UNIT COMMITMENT PROBLEM USING FORWARD DYNAMIC

PROGRAMMING METHOD

Algorithm to run forward in time from the initial hour to the final hour.

Forward Dynamic programming is suitable if the start-up cost of a unit is a

function of the time it has been off-line (i.e., fixed amount).

Previous history of the unit can be computed at each stage.

Initial conditions are easily specified.

45

Algorithm

For a Load cycle, at each load level, the algorithm is to run units or both units

with a certain load sharing. Determine the most economical cost curve of a single

equivalent unit. Then add the third unit and repeat the steps. The process is repeated until

all the units are added.

46

Determine the possible number of combinations and determine the economic

dispatch and total cost.

Compute the minimum cost in hour K with combination I is

Fcost(K,I) = min(L) { Pcost(K,I) + Scost(K-1,L;k,I) + Fcost(K-1,L)}

Where,Fcost(K,I) = Least total cost to arrive at state (K,I)

Pcost(K,I) = Production cost for state (K,I)

Scost(K-1,L;k,I) = Transition cost from state (K-1,L) to state (K,I)

State (K,I) = Ith

combination in hour K

L = ―N‖ feasible states in interval K-1.

Let X be the number of states to search each period.

Let N be the number of strategies or paths, to save at each step.

With a priority list ordering, reducing the number N by discharging the highest cost

schedules at each time interval and saving only the lowest N paths. The flow chart for

dynamic method is as shown Figure.

47

UNIT 5 – COMPUTER CONTROL OF POWER SYSTEMS

-----------------------------------------------------------------------------------------------------------------

5.1 STATE TRANSITION DIAGRAM OF A POWER SYSTEM

A power system may be operated in a several different states. These are classified into

five operating states. They are

1. Normal state (Secure state)

2. Alert state

3. Emergency state

4. Extremis state

5. Restorative state

The five operating states and their transitions are shown in fig.

Normal state

A system is said to be normal state if both load and operating constraints are

satisfied. It is one in which the total demand on the system is met by satisfying all the

operating constraints (i.e., equality (E) and inequality (I) constraints).

Secure state

48

The normal of the system is said to be secure state if all postulated contingency

states are found to be normal. A normal state of the system is said to be insecure if one or

more of the postulated contingency state consists of the constraint limits violated. In this

state, frequency and the bus voltage magnitude are within the normal operating range.

Current flows on all transition lines are within the given ratings. Transformers and

generators are operated within their ratings and there is no load shedding anywhere in the

system. Reserve margin is sufficiently high to make the system well secure.

Alert state

A normal state of the system is said to be in alert state if one or more of the

postulated contingency states, consists of the constraint limits violated. When the system

security level falls below a certain level or the probability of disturbance increases, the

system may be in alert state. All equalities (E) and inequalities (I) are satisfied, but on the

event of a disturbance occurs, the system will push into emergency state. To bring back

the system to secure state, preventive control action is carried out.

Emergency state

The system is said to be in emergency state if one or more operating constraints

are violated, but the load constraint is satisfied. In this state, the equality constraints are

unchanged. The system will return to the normal (secure) or alert state by means of

corrective actions, i.e., disconnection of faulted section or load shedding. The generator

still traces the load and the system is still synchronized. But one or several components

are overloaded. As the components eventually fail, the system will start disintegrate.

Extremis state

When the system is in emergency state, if no proper corrective action is taken in

time, then it goes to either serious emergency state or extremis state. In this, neither the

load nor the operating constraint is satisfied; this results in islanding. Also the generating

units are strained beyond their capacity. Emergency control action is done to bring back

the system state in to emergency state or normal state.

49

Restorative state

From this state, the system may be brought back either to alert state or secure

state. The latter is a slow process. Hence, in certain cases, first the system is brought back

to alert state and then to the secure state. This is done using restorative control action.

Control Strategies

Characterization of the system conditions into time states as described above

provides a framework in which control strategies can be developed and operator

actions identified to deal effectively with each state.

For a system that has been disturbed ant that has entered a degraded operating

state, power system control assists the operator in returning the system to a normal

state.

If the disturbance is small, power system controls by themselves may be able to

achieve this task. However, if the disturbance is large it is possible that operator

actions such as generation rescheduling or element switching may be required for

a return to the normal state.

50

To achieve high power system security, the control room should have data

collection system and computerized power system analysis program software,

called Energy Management Systems (EMS).

An EMS generally has a centralized digital computer system connected to Remote

Terminal Units (RTUs) via communication channels. The control room operator

may take various actions to maintain adequate power system security.

The philosophy that has evolved to cope with the diverse requirements of a system

control comprises a hierarchical structure as shown in fig. In this structure, there

are controllers operating directly on individual system such as excitation systems,

prime movers, boilers, transformers tap changers and DC converters.

There is usually some form of overall plant controller are in turn supervised by

system controllers at the operating centres.

The system controller actions are coordinated by poor-level master controllers.

The overall control system is thus highly distributed relies on many different types

of telemetry and control signals.

Supervisory Control and Data Acquisition (SCADA) systems provide information

to indicate the system status. State estimation programs filter the mentioned data

and provide an accurate picture of the system‘s condition.

The human operator is an important link at various levels in this control hierarchy

and at key locations on the system.

The primary function of the operator is top monitor system performance and

manages resources so as to ensure economic operation while maintaining the

required quality and reliability of power supply.

During system emergencies, the operator plays a key role by coordinating related

information from diverse sources and developing corrective strategies to restore

the system to a more secure state of operation.

Action by operator Variables to be adjusted

51

5.2 SCADA SYSTEM

It consists of a master station and RTUs linked by communication channel. The

hardware components can be classified into:

1. Process computer and associated hardware at the Energy Control Centre.

2. RTUs and the associated hardware at the remote stations.

3. Communication equipment that the links the RTUs and process computers at

the master station.

5.2.1 System Hardware Configuration

The supervisory control and the data acquisition system allow a few operators to

monitor the generation and HV transmission system. Consistent with principles of

high reliability and fail safe failures, electric utilities have almost universally

applied a redundant set of dual digital computers for the function of remote date

acquisition control, energy management and system security.

Both computers have their own core memory and drive an extensive number of

input-output devices such as printers, teletypes, and magnetic tape drive, disks.

Usually one computer, the on-line units, is monitoring and controlling the power

Unit commitment

Economic dispatch

Generator bus voltage

Network configuration

Load scheduling

On-load tap changing transformer

Phase shifting transformer

Tie-line system interchange

Generation on/ off status

Generation MW output schedule

Unit exciter setting

Substation CB open / close

Distribution feeder CB

Tap position

Tap position

Interchange schedule

52

system. The backup computer may be executing off-line batch programs such as

load forecasting or hydro-thermal allocation.

The on-line computer periodically updates a disk memory shared between the two

computers. Upon a fail over or switch-in status command, the stored information

of the common disk is inserted in the memory of the on-line computer.

The information used by the on-line computer has a maximum age of update

cycle. All of the peripheral equipment is interfaced with the computer through

input-output microprocessors that have been programmed to communicate, as well

as preprocess the analog information, check for limits, convert to another system

of units and so on.

The microprocessors can transfer data in and out of computer memory without

interrupting the central processing unit. As a result of these precautions, for all

critical hardware functions, there is often a guaranteed 99.8% or more availability.

53

Software also allows for multilevel hardware failures and initialization of

application programs, if failures occur. Critical operation and functions are

maintained during either preventive or corrective maintenance.

Besides hardware, new digital code to control the system may be compiled and

tested in the backup computer, then switched to on-line status. The digital

computers are usually employed in a fixed cycle operating mode, with priority

interrupts wherein computer periodically performs a list of operations. The most

critical functions have the fastest scan cycle. Typically, the following categories

are scanned every 2 seconds.

All status points such as switchgear position, substation loads and voltages,

transformer tap positions and capacitor banks.

Tie-line flow and interchanges schedules.

Generator loads, voltage, operating limits and boiler capacity.

Telemetry verification to detect failures and error in the remote bilateral

communication links between the digital computer and remote equipment.

The turbine-generators are often commanded to new power levels every 4 seconds,

sharing the load adjustment based on each unit‘s response capability in MW/min.

The absolute power output of each unit‘s response capability is typically adjusted

every 5 min by the computer executing an economic dispatch program to

determine the base power settings.

5.2.2 Types of SCADA System and Area of Applications

Type 1: Small distribution system (substation control center), small hydro

stations, HVDC links.

Type 2: Medium size power system (plant control centre) and power station HVDC

Links distribution systems.

54

Type 3: Regional control centre, distribution system in large urban area several

hydro power stations with cascade control.

Type 4: National & Regional control centers distributed systems in large urban

area and several hydro power station with cascade control.

Master Station

Master unit is provided with a digital computer with associated interfacing devices

and hardware to receive information from RTU (Remote Terminal Unit), process data

and display salient information to operator as shown. The hardware at the master station

includes the following:

1. Process computer.

2. CRT display.

3. Printer.

4. Data Logger.

5. Computer graphics.

6. Control console.

7. Keyboard.

8. Alarm panel

55

9. Instrument panel.

10. Modem.

11. Multiplexer.

Remote Terminal Units

The RTUs are installed at selected power stations and substations. The hardware

components of RTU may include the following:

1. Transducers.

2. A/D and D/A converter.

3. Serial interface.

4. Modems.

5. Multiplexers.

6. Front end computer.

7. Control relays.

The analog quantities like voltage, MW, MVAR and frequency measured at

stations are converted into DC voltage or current signals, through transducers and

fed to the A/D convert the analog signals into digital from suitable for

transmission.

The digital signal is fed to the end computer and modems through the serial

interface MODEM sends the information to the control the stations equipments

56

through the control relays. In addition to measure quantities, status of various

devices is informed to master station.

The master station scans the RTU sequentially and gathers information on the

system operating condition i.e., voltage, current, line flows, generation, output,

etc., as well as equipment status. Computer, using real time data can check

operating limits of various quantities and gives an alarm to operator if loading or

any other abnormal condition is detected.

The system real time information is presented to operator through CRT (Cathode

Ray Tube), Computer graphics terminals, alarm printer, etc.

5.2.3 Functions of SCADA

The supervisory control and data acquisition system allow a few operators to monitors

the generator. The following are the following of SCADA.

1. Data Acquisition: It provides telemeter measurements and status information to

operators.

2. Information display (limit violations unplanned events).

3. Supervisory control (CBs (Circuit Breakers): On/Off ; Generator : stop/start,

raise/lower command)

(a) Electrical breaker control

(b) Voltage regulators

(c) Tap changer control

(d) Capacitor control

(e) Loss reduction

(f) Miscellaneous device control

(g) Load management

(h) Fault isolation

(i) Service restoration

57

4. Information storage and results display (Reports such as energy accounting,

reserve calculation, interchanged evaluation.)

5. Sequence of events acquisition.

6. Remote terminal unit processing

7. General maintenance.

8. Runtime status verification.

9. Economic modeling

10. Remote start / stop.

11. Load matching based on economics.

12. Load shedding: Provides both automatic and operator-initiated tripping of load

in response to system emergencies.

5.3 NEED OF COMPUTER CONTROL OF POWER SYSTEM

Computer Configuration Trend

The computer system used at power system has been undergoing continuous

development over the years. Formerly, all the functions such as data acquisition,

logging display, and control and performance calculations were performer by

computer processing unit (CPU).

In such system failure of any of the elegant leads to the total system breakdown.

Thus, the need for a dual computer configuration arose which is quite costly.

The further advancement in communication technology and powerful

microprocessors has resulted in the cheap and reliable microprocessor based

Distributed Processing System (DPS).

It is based on the principle of LAN. Today, in all process industries including

power plant, this system is employed for data acquisition and control.

DPS consists of a number of microprocessors connected through data highway,

which is passive in nature. Each processor is assigned a specific task

58

independently. So, the failure of one of the processors does not disturb the

function of the other processors.

Functions and Facilities

The function of the data acquisition and control system is to provide the operator

with current plant information through graphic displays, group displays, alarms

annunciations and so on, for the safe operation of plant.

The DPS further provides detailed historical information for diagnostic / review

purposes in case of outage and plant performance.

The data acquisition and control system performs the following general functions.

Data acquisition and validation

Real time variable computations

Alarm monitoring and display.

Performance and deviation calculation.

Trends, events, reports and logs.

Sequential control

Modulating control

5.4 MAJOR FUNCTIONS OF ENERGY CONTROL CENTRE

When the power system increases in size-the number of substations, transformers,

switchgear and so on-their operation and interaction become more complex. So it

becomes essential to monitor this information simultaneously for the total system

which is called as energy control centre.

A fundamental design feature of energy centre is that, it increases system

reliability and economic feasibility. In other words, Energy Management (EM) is

performed at control centre called system control centre.

Fig. shows the schematic diagram showing the information flow between various

functions to be performed in an operations control centre computer system. The

system gets information about the power system from remote terminal units

59

(RTU) that encode measurement transducer outputs and operand/closed status

information into digital signals that are transmitted to the operations centre over

communication circuits.

The control centre can transmit control information such as raise/lower commands

to the speed changer and in turn to the generators and open/close commands to

circuit breakers (CBs). The information coming into the control centre is breaker

/switch status indications and analog measurements.

The analog measurements of generator outputs must be used directly by the

Automatic Generation Control (AGC) program, whereas, all other data will be

processed by the state estimator before being used by the other programs. Real

time operations are in two aspects.

60

(a) Three level control

1. Turbine-governor to adjust generation to balance changing load-instantaneous

control.

2. ACG (called Load Frequency Control (LFC)) maintains frequency and net

power interchange –action repeated at 2-6 sec. interval.

3. Economic Dispatch Control (EDC) distributes the load among the units such

that fuel cost is minimum-executed at 5-10 minutes intervals.

(b) Primary voltage control

1. Excitation controls regulate generator bus voltage.

2. Transmission voltage control device includes SVC (Static VAR Controllers),

shunt capacitors, transformer taps, etc.

5.4.1 Energy control Centre Functions

The practice of all communication links between equipment and the control

centre could be interrupted and still, electric service is being maintained.

The generating in the system remains synchronized to the transmission

network and maintains its existing power output level even without signals

received from control centre.

Monitoring

An energy control centre fulfills the function of coordinating their response

of the system elements in both normal operation and emergency conditions.

The burden of repetitious control in normal situations is delegated to the

digital computer and selective monitoring is performed by human

operators.

The digital computer is used to process the incoming stream of data to

detect abnormalities and the human operator via lights, buzzers and CRT

presentations. Many lower level or less serious cases of exceeding normal

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limits are routinely handled by digital computer. A more serious

abnormality detected by the digital computer may cause suspension of

normal control functions

In emergencies such as loss of a major generator or excess power demands

by a neighboring utility on the tie lines, many alarms could be detected and

the system could enter an emergency state.

Data Acquisition and Control

Data acquisition provides operators and computer control systems with

status and measurement information needed to supervise overall operations.

Security control analyses the consequences of faults to establish operating

conditions.

A SCADA system consists of a master station and remote terminal unit

(RTU). Master station communicates information to the RTU for observing

and controlling plants.

RTUs are installed at generating station or transmission substation or

distribution substation. RTUs transmitting status of the device and

measurements to master station and receive control commands from the

master station.

In a computer aided data acquisition scheme, the steady state reading can be

acquired simultaneously from various instrument locations and can be

saved for future analysis.

The transient may result in the form of voltage or current fluctuations. In a

real power system, the transient may result in the failure of components and

it is sometimes difficult to trace the origin of disturbance. Using a Data

Acquisition system, the transients can be reduced and analyzed.

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5.5 ENERGY MANAGEMENT SYSTEM AND ITS FUNCTIONS

Energy management is the process of monitoring, coordinating and

controlling the generation, transmission and distribution of electrical energy.

It is performed at centres called system control centres by a computer

system called Energy Management System (EMS), which forms the front

end of EMS. The EMS communicates with generating, transmission and

distribution systems through SCADA systems.

Automatic generation control and economic dispatch minimize the

production cost and transmission cost. Commit the number of units to be

operated to minimize the cost and schedule hydro-thermal plants properly

have come under energy management.

Energy management system consists of energy management, AGC security

control, SCADA, load management, as shown in fig.

Functions of energy management systems

1. System load forecasting –Hourly energy, 1 to 7 days.

2. Unit commitment -1 to 7 days.

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3. Fuel scheduling to plants.

4. Hydro-thermal scheduling-up to 7days.

5. MW interchanges evaluation-with neighboring system.

6. Transmission loss minimization.

7. Security constrained dispatch.

8. Maintenance scheduling.

9. Production cost calculation.

5.6 SECURITY MONITORING USING STATE ESTIMATION

State Estimation

Introduction

State estimation plays an important role in monitoring and control of modern

power system. State estimation is the process of assigning a value to an unknown system

state variable based on measurements from that system according to some criteria i.e.,

minimizing the sum of the squares of the differences between the estimated and true

values of a function.

Aim of state estimation

To obtain the best possible values i.e., ―best estimate‖ of the bus voltage

magnitudes and angles by processing the available network data. The complex bus

voltage (V<δ) serve as the state variables of the power system. State estimation is the

process to clean up the erroneous data.

Need of state estimation

To ―smooth out‖ small random errors in meter readings, detect and identify gross

measurement errors and ―fill in‖ meter readings that have failed due to communication

failures.

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Security monitoring

Effective operation of power system required that critical quantity be measured

and the values of measurements be transmitted to a central location. Such systems

of measurements and data transmission are called telemetry systems.

Telemetered data and information regarding breaker position received from the

system are processed first by the estimator.

The output of the state estimator is then fed into the security analyzer. Other

information like contingencies to be evaluated and associated constraints is also

fed into the security analyzer.

The security analyzer evaluates the impact of the above contingencies with the

help of fast load flow techniques. Thus, the real-time data are processed in the

control centres and are scanned by the security analyzer to ascertain whether the

operating condition is secured.

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The security monitoring functions are given below:

Function Function performed

Data acquisition

To process message from RTUs.

To check analog measurements against limits.

To check status values against normal value.

To send alarm conditions to alarm processor.

Alarm processor To send alarm messages.

To transmit messages according to priority.

Status processor To determine status of each substation for proper

connection

Reserve monitor To check generator MW output on all units against unit

limit.

State estimator

To determine system state variables.

To detect the presence of bad measured values.

To identify the location of bad measurements.

To initialize the network model for other programs.\

State estimator receives information from SCADA system and the network

topology and stores the status of the system (V and δ) in a central location called

database.

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Power system application like power flow, optimal power flow, contingency

analysis and short circuit analysis are executed using the state of the system were

computed by state estimation

5.7 VARIOUS CONTROLS FOR SECURE OPERATION.

System Security for secure operation

System security involves practices designed to keep the system operating when

components fail. Systems security can be broken down into three major functions that are

carried out in an energy control centre:

System monitoring

Contingency analysis

Security-constrained optimal power flow

System monitoring

It provides the operators of the power system with pertinent up to data information

on the conditions of the power system. Effective operation of the system is required that

critical quantities are measured and the values of measurements are transmitted to a

central location. Such system of measurements and data transmission called telemetry

systems, have evolved to schemes that can monitor voltages, currents, power flows and

status of circuit breakers and switches in every substation in a power system transmission

network.

Contingency analysis

The results of this type of analysis allow system to be operated defensively. Many

of the problems that occur on a power system can cause serious trouble which is often the

case with cascading failures. In this analysis, certain programs are used that model

possible system and are used to study outage events and alarm the operators about any

potential overloads or out-of-time voltages.

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Security-constrained optimal power flow

In this function, a contingency analysis is combined with an optimal power flow

which seeks to make changes to the optimal dispatch of generation, as well as other

adjustments, so that when a security analysis is run, no contingencies result in violations.

Other control for secure operation

State estimator:

To determine the best estimate of the state of the system using real time status and

measurements.

Power flow:

To calculate V, δ, power flows for the steady state condition.

Contingency analysis:

To determine the events which are harmful to the system by determining the states.

Optimal power flow:

Optimize a specified objective function by using controller action.

Security enhancement:

To alleviate an existing overload in the system by using corrective control actions.

Preventive action:

Before the occurrence of contingency event, preventive action has to be taken.

Bus load forecasting:

Forecast the load using real time measurements.

Transmission loss factors:

Calculate the impact of the transmission losses using incremental transmission loss (ITL).

Short circuit analysis:

Determine the fault current for different types of faults.

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Factors affecting power system security

As a consequence of many widespread black-outs in interconnected power

systems, the priorities for operation of the modern power systems have evolved to the

following:

Operate the system in such a way that power is delivered reliably.

Within the constraints placed on the system operation by reliability

considerations, the system will be operated most economically.

Characteristics of the physical system (generation, transmission and

distribution systems and protection systems).

Any piece of equipment in the system can fail either due to internal causes or due to

external causes such as lightning stroke, object hitting transmission towers, or human

errors in setting relays. Thus, most power systems are designed to have sufficient

redundancy to withstand all major failure events.

Business structures of owning and operating entities.

The regulatory frame work.

Method of enhancing security

Impractical to achieve complete immunity to black-out.

Need to strike a balance between economy and security.

Good design and operating practices could significantly minimize the

occurrence and impact of widespread outages.

Reliability criteria.

Online security assessment.

Robust stability controls.

Real-time system monitoring and control.

Coordinated emergency controls.

Wide spread use of distributed generation.