CHAPTER 1

INTRODUCTION

1.1 ABOUT ABLOWAL SUBSTATION

It is situated in Sarabha Nagar 7.5 KM from Railway Station.Until 1978 it was transmitting

132KV energy and on 29 July 1982 it was upgraded to 220KV.It is divided into four parts.

1. 22KV switch yard

2. 220/66KV switch yard

3. 66/11KV switch yard

4. 11KV control room

RING TYPE system is used for the supply purpose which has helped to produce more

regular power supply with reduced power cut and faults can easily eliminated without

difficulty.

The 220 KV Ablowal grid has incoming supply of 220 KV from Gobindgarh and Fagun

Majra and it supplies the stepped down power of 66 KV to the areas of Rakhra, Pasiana,

Patiala, DCW, Shakti Vihar and Sirhind Road and the stepped down power of 11 KV to the

areas of Model Town, Jail Road, Dashmesh Nagar, Lung, Maltex(independent feeder),

Bakshiwala and Asa majra.

There are two 220/66 KV power transformers and two 66/11 KV transformers in the grid, all

protected by lightening arrestors and various other protection equipments. There are 2 bus

bars, one each for 66 KV output and 11 KV output.

The 220/66 KV transformers are from the companies of ABB and BHEL, both with the

capacities of 50-75-100 MVA. Both have a C.T. ratio of 300-150/0.577-1-1-1 A. The

transformer from BHEL was installed in 1982 and the one from ABB was installed in 2005.

There are 2 11 KV capacitor banks from the companies of MAHAN and BHEL, each with a

capacity of 2.722(=2 x 1.361) MVAR. Each capacitor has a rating of 137.234 pF. There are

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24 such capacitors in each unit, with 3 such units in each capacitor bank, i.e. a total of 72

capacitors in each capacitor bank

1.2 TRANSMISSION AND DISTRIBUTION

Electric power transmission is the process in the transfer of electrical power to consumers

and refers to the 'bulk' transfer of electrical power from one location to another. Transfer of

electrical power from Generating Stations to the industrial, commercial or residential

consumers is as important as power generation. Typically power transmission is between the

power plant and a substation in the vicinity of a populated area. To satisfy various

instantaneous demands from consumers requires an uninterrupted flow of electricity. In the

energy delivery industry, the transmission system functions in much the same way as the

interstate highway system, serving as its major transport arteries. A power transmission

system is sometimes referred to as a "grid", which is a fully connected network of

transmission lines. The Regional Power Grids are established for optimal utilization of the

power generated from the unevenly distributed power generating stations, by having intra-

regional and inter-regional power exchanges depending upon day-to-day power availability

and load conditions. The surplus power is transferred to the power deficit regions. Due to the

large amount of electric power involved, transmission normally takes place at high voltage

(110 kV or above). Electric power is usually sent over long distances through overhead

power transmission lines. Power is transmitted underground in densely populated areas, such

as large cities, but is typically avoided due to the high capacitive and resistive losses

incurred. Redundant paths and lines are provided so that power can be routed from any

power plant to any load center, through a variety of routes, based on the economics of the

transmission path and the cost of power.

The grid consists of two infrastructures: the high-voltage transmission systems, which carry

electricity from the power plants and transmit it hundreds of miles away, and the lower-

voltage distribution systems, which draw electricity from the transmission lines and distribute

it to individual customers. High voltage is used for transmission lines to minimize electrical

losses; however, high voltage is impractical for distribution lines. Electricity distribution is

the penultimate process in the delivery of electric power, i.e. the part between transmission

and user purchase from an electricity retailer. It is generally considered to include medium-

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voltage (less than 50kV) power lines, low-voltage electrical substations and pole-mounted

transformers, low-voltage (less than 1000V) distribution wiring and sometimes electricity

meters. This interface features transformers that "step down" the transmission voltages to

lower voltages for the distribution systems. Transformers located along the distribution lines

further step down the voltage for household use. Substations also include electrical

switchgear and circuit breakers to protect the transformers and the transmission system from

electrical failures on the distribution lines. Circuit breakers are also located along the

distribution lines to locally isolate electrical problems (such as short circuits caused by

downed power lines).

According to World Resources Institute (WRI), India’s electricity grid has the highest

transmission and distribution losses in the world – a whopping 27%. Numbers published by

various Indian government agencies put that number at 30%, 40% and greater than 40%.

This is attributed to technical losses (grid’s inefficiencies) and theft.

1.3 TRANSMISSION TOWER

The huge amount of power generated in a power station (hundreds of MW) is to be

transported over a long distance (hundreds of kilometers) to load centers to cater power to

consumers with the help of transmission line and transmission towers as shown.

Disc insulators.

R RTransmission line (bare conductor)

Y Y

B B

Transmission tower steel structure

GroundFIQURE 1.1 TRANSMISSION TOWER

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To give an idea, let us consider a generating station producing 120 MW power and we want

to transmit it over a large distance. Let the voltage generated (line to line) at the alternator be

10 kV. Then to transmit 120 MW of power at 10 kV, current in the transmission line can be

easily calculated by using formula

PI = 3 V cos θ where cos θ is the power factor

L

=120×106

3×10×103 ×0.8

∴ I = 8660 A

Instead of choosing 10 kV transmission voltage, if transmission voltage were chosen to be

400 kV, current value in the line would have been only 261.5 A. So sectional area of the

transmission line (copper conductor) will now be much smaller compared to 10 kV

transmission voltage. In other words the cost of conductor will be greatly reduced if power is

transmitted at higher and higher transmission voltage. The use of higher voltage (hence lower

current in the line) reduces voltage drop in the line resistance and reactance. Also

transmission losses is reduced. Standard transmission voltages used are 132 kV or 220 kV or

400 kV or 765 kV depending upon how long the transmission lines are.

Therefore, after the generator we must have a step up transformer to change the generated

voltage (say 10 kV) to desired transmission voltage (say 400 kV) before transmitting it over a

long distance with the help of transmission lines supported at regular intervals by

transmission towers. It should be noted that while magnitude of current decides the cost of

copper, level of power to be transfer.

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1.4 NEED OF SUBSTATION

Electricity is produced by generators at 11,000 volts or now a days it is 33,000 volts.

However this is not enough to send it long distances, so the electricity first passes through a

transformer at the power station, that boosts the voltage up to 220,000 or 400,000 volts or

now a days 800 kv DC. When electricity travels long distances it is better to do so at higher

voltages as the electricity is transferred more efficiently.

When the electricity leaves the transformer it goes into the grid. The grid is the network of

cables and wires which are spread across the country. This grid carries the electricity from

the generating stations to the towns and cities that will use it. The wires that carry the

electricity in the grid are called transmission lines, which are carried across the country by

pylons.

Electricity from the grid is much too powerful to use in our homes and businesses. Therefore

the high voltage transmission lines carry electricity long distances to a substation. The power

lines go into substations near businesses, factories and homes.

Here transformers reduce the very high voltage electricity to 132, 000 Volts before it enters

the distribution network, which is the low voltage network.

The regional distribution network carries electricity to substations, where the voltage is again

reduced to 11,000 volts. The 11,000 volts network supplies towns, industrial estates, and

villages, as well as some industrial customers who have large electricity requirements.

The voltage is once again reduced to 230 volts at local substations to deliver electricity to

most homes and businesses.

As we can see in the above figure voltage is supplied to the bulk industries is 11,000 or

33,000 V. Now what’s the reason behind that. Does the machinery of these industries work

on such high voltage?? No, actually reason of this is that their main target is to minimize the

tripping of the supply. Because in the Big Industries or in the Manfacturing Units even

tripping for a short while can cause loss up to crores of rupees.

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FIQURE NO 1.2 KEY DIAGRAM

1.5 SINGLE LINE DIAGRAM

Power systems are extremely complicated electrical networks that are geographically spread

over very large areas. For most part, they are also three phase networks – each power circuit

consists of three conductors and all devices such as generators, transformers, breakers,

disconnects etc. are installed in all three phases. In fact, the power systems are so complex

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that a complete conventional diagram showing all the connections is impractical. Yet, it is

desirable, that there is some concise way of communicating the basic arrangement of power

system components. This is done by using Single Line Diagrams (SLD). SLDs are also

called One Line DiagramsSingle Line Diagrams do not show the exact electrical connections

of the circuits. As the name suggests, SLDs use a single line to represent all three phases.

They show the relative electrical interconnections of generators, transformers, transmission

and distribution lines, loads, circuit breakers, etc., used in assembling the power system. The

amount of information included in an SLD depends on the purpose for which the diagram is

used. For example, if the SLD is used in initial stages of designing a substation, then all

major equipment will be included in the diagram – major equipment being transformers,

breakers, disconnects and buses. There is no need to include instrument transformers or

protection and metering devices. However, if the purpose is to design a protection scheme for

the equipment in the substation, then instrument transformers and relays are also

included.There is no universally accepted set of symbols used for single line diagrams.

1.6 CONCEPT OF BUSES

Concept of bus in single line diagrams is essentially the same as the concept of a node in an

electrical circuit. Just keep in mind that there is one bus for each phase. Buses are shown in

SLDs as short straight lines perpendicular to transmission lines and to lines connecting

equipment to the buses. In actual substations, the buses are made of aluminum or copper bars

or pipes and can be several meters long. The impedance of buses is very low, practically

zero, so electrically the whole bus is at the same potential. Of course, there is line voltage

between the buses of the individual phases.

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1.7 COMPONENTS OF SUBSTATION

1. Outdoor switch yard

(i) Incoming lines (i/c)

(ii) Outgoing lines (o/g)

(iii) Bus bars

(iv) Transformers(t/f s)

(v) Insulators

(vi) Sub-station equipments such as circuit breakers, insulators, earthing strips, lightening arrestors, CTs, PTs, isolators, clamps & connectors.

(vii) Overhead earth wire shielding against lightening strokes

(viii) Galvanized steel structures for towers, gantries, support

(ix) Power Line Carrier Communication (PLCC) equipments including wave trap, turning unit coupling capacitor etc.

(x) Control cables for metering protection & control

(xi) Road railways track

(xii) Capacitor bank

(xiii) Station lightening system

2. Battery room direct current( D.C.) distribution system

(i) D.C. dry cells batteries & charging equipments

(ii) D.C. distribution system or D.C. panel

(iii) D.C. dry cells batteries & charging equipments

(iv) D.C. distribution system or D.C. panel

3. Mechanical , electrical & other auxiliaries

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(v) Fire extinguishers

(vi) Lightening system

(vii) Oil purification system

(viii) Telephone system

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1.8 ELEMENTS OF THE SUBSTATION

Substations generally have switching, protection and control equipment, and transformers. In a

large substation, circuit breakers are used to interrupt any short circuits or overload currents that

may occur on the network. Smaller distribution stations may use closer circuit breakers or fuses

for protection of distribution circuits. Substations themselves do not usually have generators,

although a power plant may have a substation nearby. Other devices such as capacitors and

voltage regulators may also be located at a substation.

1.9 DESIGN OF THE SUBSTATION

The main issues facing a power engineer are reliability and cost. A good design attempts to strike

a balance between these two, to achieve sufficient reliability without excessive cost. The design

should also allow easy expansion of the station, if required.

Selection of the location of a substation must consider many factors. Sufficient land area is

required for installation of equipment with necessary clearances for electrical safety, and for

access to maintain large apparatus such as transformers. Where land is costly, such as in urban

areas, gas insulated switchgear may save money overall. The site must have room for expansion

due to load growth or planned transmission additions. Environmental effects of the substation

must be considered, such as drainage, noise and road traffic effects. Grounding (earthing) and

ground potential rise must be calculated to protect passers-by during a short-circuit in the

transmission system. Of course, the substation site must be reasonably central to the distribution

area to be served.

1.10 LAYOUT OF THE SUB STATION

The first step in planning a substation layout is the preparation of a one-line diagram which

shows in simplified form the switching and protection arrangement required, as well as the

incoming supply lines and outgoing feeders or transmission lines. It is a usual practice by many

electrical utilities to prepare one-line diagrams with principal elements (lines, switches, circuit

breakers and transformers) arranged on the page similarly to the way the apparatus would be laid

out in the actual station.

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In a common design, incoming lines have a disconnect switch and a circuit breaker. In some

cases, the lines will not have both, with either a switch or a circuit breaker being all that is

considered necessary. A disconnect switch is used to provide isolation, since it cannot interrupt

load current. A circuit breaker is used as a protection device to interrupt fault currents

automatically, and may be used to switch loads on and off, or to cut off a line when power is

flowing in the 'wrong' direction. When a large fault current flows through the circuit breaker, this

is detected through the use of current transformers. The magnitude of the current transformer

outputs may be used to trip the circuit breaker resulting in a disconnection of the load supplied

by the circuit break from the feeding point. This seeks to isolate the fault point from the rest of

the system, and allow the rest of the system to continue operating with minimal impact. Both

switches and circuit breakers may be operated locally (within the substation) or remotely from a

supervisory control center.

Once past the switching components, the lines of a given voltage connect to one or more buses.

These are sets of bus bars, usually in multiples of three, since three-phase electrical power

distribution is largely universal around the world.

The arrangement of switches, circuit breakers and buses used affects the cost and reliability of

the substation. For important substations a ring bus, double bus, or so-called "breaker and a half"

setup can be used, so that the failure of any one circuit breaker does not interrupt power to other

circuits, and so that parts of the substation may be de-energized for maintenance and repairs.

Substations feeding only a single industrial load may have minimal switching provisions,

especially for small installations.

Once having established buses for the various voltage levels, transformers may be connected

between the voltage levels. These will again have a circuit breaker, much like transmission lines,

in case a transformer has a fault (Commonly called a ‘short circuit).

Along with this, a substation always has control circuitry needed to command the various

breakers to open in case of the failure of some component.

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1.11 SWITCHING FUNCTION

An important function performed by a substation is switching, which is the connecting and

disconnecting of transmission lines or other components to and from the system. Switching

events may be "planned" or "unplanned".

A transmission line or other component may need to be de-energized for maintenance or for new

construction, for example, adding or removing a transmission line or a transformer.To maintain

reliability of supply, no company ever brings down its whole system for maintenance. All work

to be performed, from routine testing to adding entirely new substations, must be done while

keeping the whole system running.

Perhaps more important, a fault may develop in a transmission line or any other component.

Some examples of this: a line is hit by lightning and develops an arc, or a tower is blown down

by high wind. The function of the substation is to isolate the faulted portion of the system in the

shortest possible time.There are two main reasons: a fault tends to cause equipment damage; and

it tends to destabilize the whole system. For example, a transmission line left in a faulted

condition will eventually burn down; similarly, a transformer left in a faulted condition will

eventually blow up.While these are happening, the power drain makes the system more unstable.

Disconnecting the faulted component, quickly, tends to minimize both of these problems.

1.12 AUTOMATION

Early electrical substations required manual switching or adjustment of equipment, and manual

collection of data for load, energy consumption, and abnormal events. As the complexity of

distribution networks grew, it became economically necessary to automate supervision and

control of substations from a centrally attended point, to allow overall coordination in case of

emergencies and to reduce operating costs. Early efforts to remote control substations used

dedicated communication wires, often run alongside power circuits. Power-line carrier,

microwave radio, fiber optic cables as well as dedicated wired remote control circuits have all

been applied to Supervisory Control and Data Acquisition (SCADA) for substations. The

development of the microprocessor made for an exponential increase in the number of points that

could be economically controlled and monitored. Distributed automatic control at substations is

one element of the so-called smart grid.

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CHAPTER 2

TYPES OF SUBSTATION

2.1 According to the service requirement:

Transformer substation

Power factor correction substation

Frequency change substation

Converting substation

Industrial substation

2.1.1 According to the constructional features:

Indoor substation

Outdoor substation

Underground substation

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Polemounted substation

2.1.2TRANSFORMER SUBSTATION

They are known as transformer substations as because transformer is the main component

employed to change the voltage level, depending upon the purposed served transformer

substations may be classified into:

(i) STEP UP SUBSTATION

The generation voltage is steeped up to high voltage to affect economy in transmission of electric

power. These are generally located in the power houses and are of outdoor type

(ii) PRIMARY GRID SUBSTATION

Here, electric power is received by primary substation which reduces the voltage level to 11KV

for secondary transmission. The primary grid substation is generally of outdoor type.

(iii) SECONDARY SUBSTATIONS

At a secondary substation, the voltage is further steeped down to 11KV. The 11KV lines runs

along the important road of the city. The secondary substations are also of outdoor type

(iv)DISTRIBUTION SUBSTATION

These substations are located near the consumer’s localities and step down to 400V, 3-phase, 4-

wire for supplying to the consumers. The voltage between any two phases is 400V & between

any phase and neutral

2.2 SUBSTATION DESIGN

Selection of site for construction of a Grid Sub Station is the first and importantactivity. This

needs meticulous planning, fore-sight, skilful observation and handling so that the selected site is

technically, environmentally, economically and socially optimal and is the best suited to the

requirements.

The main points to be considered in the selection of site for construction of a Grid substation are

as follows:-

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The site should be:

a) As near the load centre as possible.

b) As far as possible rectangular or square in shape for ease of proper orientation of bus– bars

and feeders.

c) Far away from obstructions, to permit easy and safe approach / termination of high

voltage overhead transmission lines.

d) Free from master plans / layouts or future development activities to have free line

corridors for the present and in future.

e) Easily accessible to the public road to facilitate transport of material.

f) As far as possible near a town and away from municipal dumping grounds, burial

grounds, tanneries and other obnoxious areas.

g) Preferably fairly leveled ground. This facilitates reduction in leveling expenditure.

h) Above highest flood level (HFL) so that there is no water logging.

i) Sufficiently away from areas where police and military rifle practices are held.

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CHAPTER 3

EQUIPMENTS USED IN SUBSTATION

3.1 TRANSFORMERS

Transformer is a static machine, which transforms the potential of alternating current at same

frequency. It means the transformer transforms the low voltage into high voltage & high voltage

to low voltage at same frequency. It works on the principle of static induction principle.When the

energy is transformed into a higher voltage, the transformer is called step up transformer but in

case of other is known as step down transformer.

3.1.1 WORKING PRINCIPLE

The working principle of transformer is very simple. It depends upon Faraday's laws of

Electromagnetic Induction. Actually mutual induction between two or more winding is

resposible for transformation action in an electrical transformer. Say you have one winding

which is supplied by an alternating

electrical source. The alternating current

through the winding produces a continually

changing flux or alternating flux sarrounds

the winding. If any other winding is brought

nearer to the previous one, obviously some

portion of this flux will link with the

second. As this flux is continually changing in

its amplitude and direction, there must be a

change in flux linkage in the second

winding or coil. According to Faraday's laws of Electromagnetic Induction, there must be an

EMF induced in the second. If the circuit of the latter winding is closed, there must be an electric

current flows through it. This is the simplest form of electrical power transformer and this is most

basic of working principle of transformer. The winding which takes electrical power from the

source, is generally known as Primary Winding of transformer. Here in our above example it is

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first winding.  The winding which gives the desired output voltage due to mutual induction in the

transformer, is commonly known as Secondary Winding of Transformer.

3.1.2 CONSTRUCTIONAL FEATURES

So three main parts of a transformer are,

1.Primary Winding of transformer - which produces magnetic flux when it is connected to

electrical

2. Magnetic Core of transformer - the magnetic flux produced by the primary winding, will

pass through this low reluctance path linked with secondary winding and creates a closed

magnetic circuit.

3. Secondary Winding of transformer - the flux, produced by primary winding, passes through

the core, will link with the secondary winding. This winding is also wound on the same core

and gives the desired output of the transformer.

3.1.3 LOSSES IN A TRANSFORMER

An ideal transformer would have no energy losses, and would be 100% efficient. In practical

transformers energy is dissipated in the windings, core, and surrounding structures. Larger

transformers are generally more efficient, and those rated for electricity distribution usually

perform better than 98%.

Experimental transformers using superconducting windings achieve efficiencies of 99.85%. The

increase in efficiency can save considerable energy, and hence money, in a large heavily-loaded

transformer; the trade-off is in the additional initial and running cost of the superconducting

design.

Losses in transformers (excluding associated circuitry) vary with load current, and may be

expressed as "no-load" or "full-load" loss. Winding resistance dominates load losses,

whereas hysteresis and eddy currents losses contribute to over 99% of the no-load loss. The no-

load loss can be significant, so that even an idle transformer constitutes a drain on the electrical

supply and a running cost; designing transformers for lower loss requires a larger core, good-

quality silicon steel or even amorphous steel for the core, and thicker wire, increasing initial cost,

so that there is a trade-off between initial cost and running cost

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3.2 TYPES OF TRANSFORMERS INSTALLED AT SUBSTATION

3.2.1CURRENT TRANSFORMER

FIG. NO 3.1- CURRENT TRANSFORMER

The instrument current transformer (CT) steps down the current of a circuit to a lower value and

is used in the same types of equipment as a potential transformer. This is done by constructing

the secondary coil consisting of many turns of wire, around the primary coil, which contains only

a few turns of wire. In this manner, measurements of high values of current can be obtained. A

current transformer should always be short-circuited when not connected to an external load.

Because the magnetic circuit of a current transformer is designed for low magnetizing current

when under load, this large increase in magnetizing current will build up a large flux in the

magnetic circuit and cause the transformer to act as a step-up transformer, inducing an

excessively high voltage in the secondary when under no load. These transformers are basically

used to get the incoming current on the incoming feeders. It steps down the incoming 800 amps

to 1 amps. Current transformers are used in electric metering for large load situations to reduce

the current level presented to the metering circuit in order to make it more manageable and safe.

A current transformer also isolates the measuring instruments from what may be very high

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voltage in the monitored circuit. Current transformers are commonly used in metering and

protective relays in the electrical power

industry. Care must be taken that the secondary of a current transformer is not

disconnected from its load while current is flowing in the primary, as the transformer

secondary will attempt to continue driving current across the effectively infinite impedance. This

will produce a high voltage across the open secondary (into the range of several kilovolts in

some cases), which may cause arcing. The high voltage produced will compromise operator and

equipment safety and permanently affect the Accuracy of the transformer

3.2.2 POTENTIAL TRANSFORMER/CAPACITANCE VOLTAGE TRANSFORMER

FIG. NO - 3.2 PT/CVT

Capacitor Voltage Transformer (CVT) is a transformer used in power systems to step-down

extra high voltage signals and provide low voltage signals either for measurement or to operate a

protective relay. In its most basic form the device consists of three parts: two capacitors across

which the voltage signal is split, an inductive element used to tune the device to the supply

frequency and a transformer used to isolate and further step-down the voltage for the

instrumentation or protective relay. The device has at least four terminals, a high-voltage

terminal for connection to the high voltage signal, a ground terminal and at least one set of

secondary terminals for connection to the instrumentation or protective relay. CVTs are typically

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single-phase devices used for measuring voltages in excess of one hundred kilovolts where the

use of voltage transformers would be uneconomical. It consists of a potential divider circuit

employing two capacitances (C1) and (C2). The voltage across

C2 is fed to an intermediate transformer which steps down the voltage to the order of 110V. In

practice the first capacitor, C1, is often replaced by a stack of capacitors connected in series. This

results in a large voltage drop across the stack of capacitors that replaced the first capacitor and a

comparatively small voltage drop across the second capacitor, C2, and hence the secondary

terminals. The indicating instruments, meters, relays are designed for voltages as obtainable from

secondary sides of the voltage transformers. The calibration of these instruments is however

according to primary voltages of voltage transformer. A voltage transformer is intended to

present a negligible load to the supply being measured. The low secondary voltage allows

protective relay equipment and measuring instruments to be operated at lower voltages.

3.2.3 POWER TRANSFORMER

Substation has the two 220/66 kv power transformers (100 MVA) installed made by BHEL and

ABB and two 66/11 kv power transformer (20 MVA) made by ECE and TA. The power

transformers are used to step down the220 KV incoming to 66 kv and further step down 11kv.

FIG.3.3 - A 66/11 KV POWER TRANSFORMER

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FIG.3.4- A 220/66 KV POWER TRANSFORMER

The power transformer serves as step down transformer. It consists of transformer tank in which

the windings are placed mounted on the core which is further attached to the sets of bushes.

There is a oil tank which is filled with transformer oil the tank serves for the cooling purpose.

The buchholz relay is provided for the protection. The oil-filled tank often has radiators through

which the oil circulates by natural convection; some large transformers employ forced circulation

of the oil by electric pumps, aided by external fans or water-cooled heat exchangers. Oil-filled

transformers undergo prolonged drying processes to ensure that the transformer is completely

free of water vapor before the cooling oil is introduced. This helps prevent electrical breakdown

under load. Oil-filled transformers may be equipped with Buchholz relays, which detect gas

evolved during internal arcing and rapidly de-energize the transformer to avert catastrophic

failure. Oil-filled transformers may fail, rupture, and burn, causing power outages and losses. An

installation of oil-filled transformers usually includes fire protection measures such as walls, oil

containment, and fire-suppression sprinkler systems.

3.2.3.1 Tap Changer

The voltage in a distribution line is not constant. It may be 1.05 p.u. at generator terminal and

0.95 at the load side. Depending on the place the transformer is used, we may need to adjust the

transformer ratio to get similar load voltage. That’s why we need tapings in a transformer.

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These taps are changed either manually or automatically. Also, there are two types of

transformers based on their tap changing conditions: On Load Tap Changer (OLTC) and Off

Circuit Tap Changer (OCTC)

3.2.3.2 Vector Group

In electrical engineering, a vector group is the International Electro-technical Commission (IEC)

method of categorizing the primary and secondary winding configurations of three-phase

transformers. It indicates the windings configurations and the difference in phase angle between

them. For example.star (H.V)-delta (L.V) 30 degree lead is denoted as Yd11.

The phase windings of a poly-phase transformer can be connected internally in different

configurations, depending on what characteristics are needed from the transformer. For example,

in a three-phase power system, it may be necessary to connect a three-wire system to a four-wire

system,or vice versa. Because of this, transformers are manufactured with a variety of winding

configurations to meet these requirements.. This limits the types of transformers that can be

connected between two systems, because mismatching phase angles can result in circulating

current and other system disturbances.

3.2.3.3 Symbol Designation

The vector group provides a simple way of indicating how the internal connections of a

particular transformer are arranged. In the system adopted by the IEC, the vector group is

indicated by a code consisting of two or three letters, followed by one or two digits. The letters

indicate the winding configuration as follows:

(i) D: Delta winding, also called a mesh winding. Each phase terminal connects to two windings,

so the windings form a triangular configuration with the terminals on the points of the triangle.

(ii) Y: Wye winding, also called a star winding. Each phase terminal connects to one end of a

winding, and the other end of each winding connects to the other two at a central point, so that

the configuration resembles a capital letter Y. The central point may be connected outside of the

transformer.

(iii) Z: Zigzag winding, or interconnected star winding. Basically similar to a star winding, but

the windings are arranged so that the three legs are "bent" when the phase diagram is drawn.

Zigzag wound transformers have special characteristics and are not commonly used where these

characteristics are not needed.

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(iv): Independent windings. The three windings are not interconnected inside the transformer at

all, and must be connected externally. In the IEC vector group code, each letter stands for one set

of windings. The HV winding is designated with a capital letter, followed by medium or low

voltage windings designated with a lowercase letter. The digits following the letter codes

indicate the difference in phase angle between the windings, with HV winding is taken as a

reference. The number is in units of 30 degrees. For example, a transformer with a vector group

of Dy1 has a delta-connected HV winding and a wye-connected LV winding. The

phase angle of the LV winding lags the HV by 30 degrees.

3.2.3.4 Phase displacement

Phase rotation is always anti-clockwise. (International adopted convention) Use the hour

indicator as the indicating phase displacement angle. Because there are 12 hours on a clock, and

a circle consists out of 360°, each hour represents 30°. Thus 1 = 30°, 2 = 60°, 3 = 90°, 6 = 180°

and 12 = 0° or3 60°.

The minute hand is set on 12 o'clock and replaces the line to neutral voltage (sometimes

imaginary) of the HV winding. This position is always the reference point. Because rotation is

anti-clockwise, 1 =30° lagging (LV lags HV with 30°)and 11 = 330° lagging or 30° leading (LV

leads HV with 30°) The point of confusion is in how to use this notation in a step-up transformer.

As the IEC60076-1 standard has stated, the notation is HV-LV in sequence. For example, a step-

up transformer with a delta-connected primary, and star-connected secondary, is not written as

'dY11', but 'Yd11'. The 11 indicates the LV winding leads the HV by 30 degrees. Transformers

built to ANSI standards usually do not have the vector group shown on their nameplate and

instead a vector diagram is given to show the relationship between the primary and other

windings.

3.2.3.5 Dehydration of Transformer Oil

Dehydration is the process of removing water content from transformer oil by circulating it

through large machine where it is heated for a large amount of time and the water is removed

23

FIG.3.4. DEHYDRATION TANK

.

When starting the dehydration, oil is drawn from the bottom of transformer into the filtration

plant and let into transformer again at the top for removing any settled moisture / impurities. The

readings of IR values shall not be taken during this process since these will be misleading due to

erroneous indication of winding temperature. After about 8 – 12 hours of circulation in this

manner, the cycle is reversed, i.e., oil is drawn from the top and fed at the bottom.

During dehydration, measure insulation resistance values of the transformer every 2 hours. The

test voltage of 5 kV is applied for one minute. The winding temperature is assumed to be the

same as top oil temperature under steady state conditions.

In the beginning, the IR values drop down as the temperature increases. If there is moisture in the

windings, then, the IR values at constant temperature will drop down as the moisture is removed

from the insulation and gets dissolved in the oil. The moisture in the oil is continuously removed

by the filtration plant. After the moisture has been removed from the winding, the IR values will

start rising as the dissolved moisture in the oil is removed. These reach a constant value after the

drying out is complete. The dehydration process is thereafter continued for a minimum of another

24 hours. If there is no moisture in the windings, then the IR values at constant temperature will

remain the same. In such a case, the dehydration is stopped after the time prescribed by the

manufacturer. If no such time is prescribed, then the dehydration at constant temperature is

carried out for a minimum of 72 hours

24

FIG 3.5 TEMP. V/S TIME GRAPH

3. 2.3.6 Transformer Cooling System

The main source of heat generation in transformer is its copper loss or I2R loss. Although there

are other factors contribute heat in transformer such as hysteresis & eddy current losses but

contribution of I2R loss dominate them. If this heat is not dissipated properly, the temperature of

the transformer will rise continually which may cause damages in paper insulation and liquid

insulation medium of transformer. So it is essential to control the temperature within permissible

limit to ensure the long life of transformer by reducing thermal degradation of its insulation

system. In Electrical Power transformer we use external transformer cooling system to

accelerate the dissipation rate of heat of transformer.

25

There are different transformer cooling methods available for transformer :

ONAN Cooling of Transformer

ONAF Cooling of Transformer

OFAF Cooling of Transformer

OFWF Cooling of Transformer

ODAF Cooling of Transformer

ODWF Cooling of Transformer

Mostly we use ONAN &ONAF Cooling of Transformer

ONAN Cooling of Transformer

FIG 3.6 ONAN Cooling of Transformer

This is the simplest transformer cooling system. The full form of ONAN is "Oil Natural Air

Natural". Here natural convectional flow of hot oil is utilized for cooling. In convectional

circulation of oil, the hot oil flows to the upper portion of the transformer tank and the vacant

26

place is occupied by cold oil. This hot oil which comes to upper side, will dissipate heat in the

atmosphere by natural conduction, convection & radiation in air and will become cold. In this

way the oil in the transformer tank continually circulate when the transformer put into load. As

the rate of dissipation of heat in air depends upon dissipating surface of the oil tank, it is essential

to increase the effective surface area of the tank. So additional dissipating surface in the form of

tubes or radiators connected to the transformer tank. This is known as radiator of transformer or

radiator bank of transformer.

ONAF Cooling of Transformer

FIG 3.7 ONAF Cooling of Transformer

Heat dissipation can obviously be increased, if dissipating surface is increased but it can be make

further faster by applying forced air flow on that dissipating surface. Fans blowing air on cooling

surface is employed. Forced air takes away the heat from the surface of radiator and provides

better cooling than natural air. The full form of ONAF is "Oil Natural Air Forced". As the heat

dissipation rate is faster and more in ONAF transformer cooling method than ONAN cooling

system, electricalpower transformer can be put into more load without crossing the permissible

temperature limits.

27

3.3 BREAKDOWN VOLTAGE TEST OF OIL

To determine the insulating property of the dielectric oil, an oil sample is taken from the device

under test.

FIG 3.8 Breakdown Voltage Test of Oil

Its breakdown voltage is measured on-site according the following test sequence:

In the vessel, two standard-compliant test electrodes with a typical clearance of 2.5 mm

are surrounded by the insulating oil.

During the test, a test voltage is applied to the electrodes. The test voltage is continuously

increased up to the breakdown voltage with a constant slew rate of e.g. 2 kV/s.

Breakdown occurs in an electric arc, leading to a collapse of the test voltage.

Immediately after ignition of the arc, the test voltage is switched off automatically.

Ultra fast switch off is crucial, as the energy that is brought into the oil and is burning it

during the breakdown, must be limited to keep the additional pollution by carbonisation as

low as possible.

The root mean square value of the test voltage is measured at the very instant of the

28

breakdown and is reported as the breakdown voltage.

After the test is completed, the insulating oil is stirred automatically and the test sequence

is performed repeatedly.

The resulting breakdown voltage is calculated as mean value of the individual

measurements.

This test is continuously conducted at the time of dehydration of oil and the measured values

are continuously compared with the desired value

3.4 CIRCUIT BREAKER

FIG 3.10 Circuit Breaker

The modern power system deals with huge power network and huge numbers of associated

electrical equipment. During short circuit fault or any other types of electrical fault these

equipment as well as the power network suffer a high stress of fault current in them which may

damage the equipment and networks permanently. For saving these equipments and the power

networks the fault current should be cleared from the system as quickly as possible. Again after

the fault is cleared, the system must come to its normal working condition as soon as possible for

29

supplying reliable quality power to the receiving ends. In addition to that for proper controlling

of power system, different switching operations are required to be performed. So for timely

disconnecting and reconnecting different parts of power system network for protection and

control, there must be some special type of switching devices which can be operated safely under

huge current carrying condition. During interruption of huge current, there would be large arcing

in between switching contacts, so care should be taken to quench these arcs in safe manner.

The circuit breaker is the special device which does all the required switching operations during

current carrying condition.

3.4.1 WORKING PRINCIPLE OF CIRCUIT BREAKER

The circuit breaker mainly consists of fixed contacts and moving contacts. In normal "on"

condition of circuit breaker, these two contacts are physically connected to each other due to

applied mechanical pressure on the moving contacts. There is an arrangement stored potential

energy in the operating mechanism of circuit breaker which is realized if switching signal

given to the breaker. The potential energy can be stored in the circuit breaker by different

ways like by deforming metal spring, by compressed air, or by hydrolic pressure. But

whatever the source of potential energy, it must be released during operation. Relaese of

potential energy makes sliding of the moving contact at extremely fast manner. All circuit

breaker have operating coils (tripping coils and close coil), whenever these coils are energized

by switching pulse, the plunger inside them displaced. This operating coil plunger is typically

attached to the operating mechanism of circuit breaker, as a result the mechanically stored

potential energy in the breaker mechanism is released in forms of kinetic energy, which makes

the moving contact to move as these moving contacts mechanically attached through a gear

lever arrangement with the operating mechanism. After a cycle of operation of circuit

breaker the total stored energy is released and hence the potential energy again stored in the

operating mechanism of circuit breaker by means of spring charging motor or air compressor

or by any other means. Till now we have discussed about mechanical working principle of

circuit breaker. But there are electrical characteristics of a circuit breaker which also should

be consider in this discussion of operation of circuit breaker.

30

The circuit breaker has to carry large rated or fault power. Due to this large power there is

always dangerously high arcing between moving contacts and fixed contact during

operation of circuit breaker. Again as we discussed earlier the arc in circuit breaker can be

quenching safely if the dielectric strength between the current carrying contacts of circuit

breaker increases rapidly during every current zero crossing of the alternating current. The

dielectric strength of the media in between contacts can be increased in numbers of ways,

like by compressing the ionized arcing media since compressing accelerates the

deionization process of the media, by cooling the arcing media since cooling increase the

resistance of arcing path or by replacing the ionized arcing media by fresh gasses. Hence a

numbers of arc quenching processes should be involved in operation of circuit breaker.

Depending upon the medium used for quenching the arc there are several types of circuit

breaker.

Types of Circuit Breaker:

1. BULK OIL CIRCIUT BREAKER

2. MINIMUM OIL CIRCUIT BREAKER

3. AIR BLAST CIRCUIT BREAKER

4. VACCUM CIRCUIT BREAKER

5. SF-6 CIRCUIT BREAKER

3.4.2 SF-6 CIRCUIT BREAKER

A circuit breaker in which the current carrying contacts operate in Sulphur Hexafluoride or SF6

gas is known as an SF6 Circuit Breaker.

Now a days SF-6 circuit breaker replacing ABCB & MOCB due to the following properties:

1. Excellent insulating, arc extinguishing, physical and chemical properties of SF6 gas is

greater advantage of SF6 circuit breakers

2. The gas is non-inflammable and chemically stable. The decomposition products are non-

explosive i.e, rhere is no risk of fire or explosion

3. Electrical clearances are very much reduced because of high dielectric strength of SF6

31

4. Its performance is not affected due to variation in atmospheric conditions

5. It gives noiseless operation it does not make sound like air-blast circuit breaker during

operation

6. No frequent contact replacement-arcing time is small owing to outstanding arc quenching

properties of SF6 and therefore contact erosion is less. Hence contacts do not suffer

oxidation

7. Therefore is no reduction in dielectric strength of SF6 since no carbon particle is formed

during the arcing

8. Minimum maintenance. The breaker may require maintenance once in four to ten year

9. Same gas is re-circulated into the circuit thereby reducing the requirement of SF6 gas.

3.4.2.1 OPERATION OF SF6 C.B

The working of SF6 CB of first generation was quite simple it is some extent similar to air blast

circuit breaker. Here SF6 gas was compressed and stored in a high pressure reservoir.

During operation of SF6 circuit breaker this highly compressed gas is released through the arc

and collected to relatively low pressure reservoir and then it pumped back to the high pressure

reservoir for reutilize.

The working of SF6 circuit breaker is little bit different in modern time. Innovation of puffer

type design makes operation of SF6 CB much easier. In buffer type design, the arc energy is

utilized to develop pressure in the arcing chamber for arc quenching.

Here the breaker is filled with SF6 gas at rated pressure. There are two fixed contact fitted with a

specific contact gap. A sliding cylinder bridges these to fixed contacts. The cylinder can axially

slide upward and downward along the contacts. There is one stationary piston inside the cylinder

which is fixed with other stationary parts of the SF6 circuit breaker, in such a way that it can not

change its position during the movement of the cylinder. As the piston is fixed and cylinder is

movable or sliding, the internal volume of the cylinder changes when the cylinder slides.

During opening of the breaker the cylinder moves downwards against position of the fixed piston

hence the volume inside the cylinder is reduced which produces compressed SF6 gas inside the

32

cylinder. The cylinder has numbers of side vents which were blocked by upper fixed contact

body during closed position. As the cylinder move further downwards, these vent openings cross

the upper fixed contact, and become unblocked and then compressed SF6 gas inside the cylinder

will come out through this vents in high speed towards the arc and passes through the axial hole

of the both fixed contacts. The arc is quenched during this flow of SF6 gas.

During closing of the SF6 circuit breaker, the sliding cylinder moves upwards and as the position

of piston remains at fixed height, the volume of the cylinder increases which introduces low

pressure inside the cylinder compared to the surrounding. Due to this pressure difference SF6 gas

from surrounding will try to enter in the cylinder. The higher pressure gas will come through the

axial hole of both fixed contact and enters into cylinder via vent and during this flow; the gas

will quench the arc.

3.5 ISOLATOR

An isolator is a non load-breaking switch, and it provides a visible means of isolating a

component, such as a circuit breaker, transformer, etc., from the high-voltage lines, whenever it

is necessary to perform maintenance of that component. An isolator does not have any specified

current breaking capacity or current making capacity. Opening and closing of a current carrying

circuit is performed by a circuit-breaker. Normally, isolators come in pairs, with one on each side

of the component to be isolated. Isolators are only opened after the load current has been broken

using a circuit breaker, and must be closed before the circuit breaker is reclosed. In some designs

the isolator switch has the additional ability to earth the isolated circuit thereby providing an

additional safety. Such an arrangement would apply to circuits which inter-connect power

distribution systems where both end of the circuit need to be isolated. Isolator switches have

provisions for a padlock so that inadvertent operation is not possible. Isolators are mechanically

interlocked with the earth switch and electrically interlocked with the circuit breaker to ensure

proper sequence of operation.

33

FIG 3.11 Isolator

Types of Isolators are:

1. Central rotating, horizontal swing

2. Centre-Break

3. Vertical swing

4. Pantograph type

3.5.1 Isolator with earth switch

Isolators are used for breaking charging current of transmission lines. The main purpose of an

earth switch is to discharge the charging current present on the tip of the contact so as to make it

safe for the personnel rectifying the fault. Earth switch usually comprises of a vertical break

switch arm with the contact at the extreme end and engages with fixed contact fixed on the post

insulator on the line side. They have separate operating box and operating system. Mechanical

interlock is provided between main and earth switches so that earth switch can be operated only

when main isolator is off and vice-versa. These isolators are operated from local as well from

remote ends (i.e. panels). The control wiring is to be connected accordingly between panels and

the operating mechanisms of isolators. Flexible copper wires are being used for the movement of

the earth switch rod.

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3.5.2 Difference between an Isolator and a Circuit Breaker

The major difference between an isolator and a circuit breaker is that an isolator is an off-load

device intended to be opened only after current has been interrupted by some other control

device. Also, an isolator is a manually operated device whereas a circuit breaker is an automatic

one receiving signals from the relays operating in the circuit.Safety regulations of the utility must

prevent any attempt to open the disconnector while it supplies acircuit. Isolators are installed on

both sides of a bus for the safety and reliability of the substation.

3.6 LIGHTNING ARRESTOR

FIG 3.12 LIGHTING ARRESTER

A lightning arrester is a device used to protect the insulation and conductors of the system from

the damaging effects of lightning. It is a device designed to protect electrical equipments from

high voltage surges and to limit the duration and amplitude of the follow current. The typical

35

lightning arrester has a high-voltage terminal and a ground terminal. When a lightning surge (or

switching surge, which is very similar) travels along the power line to the arrester, the current

from the surge is diverted through the arrestor, in most cases to earth. Generally arresters are

connected in parallel with the equipment to be protected, typically between phase and earth for

three phase installations. These are connected directly to line or bus connected to transformer.

These are placed on the entry of the incoming line to the substation so that any lightning surge

travelling on the incoming line is bypassed to the earth thro’ Lightning Arrester. It is also placed

just before the primary side of the transformer for its safety. The main element of a surge arrester

is the ‘Non-Linear Resistor’, the part of the arrester which offers a low resistance to the flow of

discharge current thus limiting the voltage across the arrester terminals and high resistance to

power frequency voltage, thus limiting the magnitude of follow current.

3.6.1 Types of Lightning Arrester:

There are 2 types of designs available for EHV Surge-Arrester. These are Conventional gapped

Surge-

1. Arrester (Value Type)

2. Metal Oxide Surge-Arrester.

3.6.1.1 Conventional Gapped Lightning Arrester (Valve Type Arrester)

In a substation the Surge Arrester is connected between line and earth. It is the first apparatus as

seen from the overhead transmission line entering in the switchyard. It consists of resistor

elements in series with gap elements offer non-linear resistance such that for normal frequency

power system voltages the resistance is high however, for discharge currents the resistance is

low. The gap units consist of air gaps of appropriate length. During normal voltages the lightning

arrester does not conduct. When a surge-wave travelling along the overhead line comes to the

arrester, the gap breaks down. The resistance offered being low the surge is diverted to the earth.

After a few micro seconds the surge vanishes and normal power frequency voltage is set up

across the arrester. The resistance offered by resistors to this voltage is very high. Therefore, are

current reduces and voltage across the gap is no more sufficient to maintain the arc. Therefore,

the current flowing to the earth is automatically interrupted and normal condition is restored. The

36

high voltage surge is discharged to earth. Hence the insulation of equipment connected to the line

is protected.

3.6.1.2 Metal Oxide Lightning Arresters

The metal oxide arresters without spark gaps consist of an active part which is a highly non

linear ceramic resistor made of essentially Zinc Oxide. Fine Zinc Oxide crystals are surrounded

by other metal oxides (additives). Such microstructures render extreme non-linear characteristics

to these ceramic resistors. In the operating characteristic of Surge Arrester the current axis is in

logarithmic scale. The current increases by 107 orders of magnitude when the voltage across

element doubles. This special characteristic is the heart of protection technology in this type of

Surge Arrester. The lower linear part ‘A’ is temperature dependant and exhibits a negative

temperature coefficient. The arrester is designed in such a way that the applied operating voltage

gets located around point ‘O’. This results in a continuous resistive current of few micro amps

flowing through the resistor elements. Under over voltage condition, the voltage increases and

shifts operating point momentarily for overvoltage duration to point near ‘B’. This results in a

resistive current of few milli-amperes flowing through the resistor elements. As soon as the

overvoltage disappears the operating point shifts back to ‘O’. In the event of transient switching

or lightning over-voltages, the operating point will shift to portion ‘C’. For the transient of a few

micro seconds it will draw current in the range of 5/10 k Amps. In the event of very high

lightning current of the order of 40 to 100 k Amps peak, the operating point will shift to portion

’D’. However, on expiry of transient of few milli seconds the operating point will come back to

point ‘O’. Thus the operating point of these arresters is normally located at point ‘O’ called

Maximum Continuous Operating Voltage (MCOV) and the point ‘B’ of the Fig. (5) indicates

approximately the rated voltage of arrester. The arrester can stay at point ‘O’ i.e., MCOV, all

long its life but can stay at point ‘B’ (fault condition), i.e. Rated Voltage, for only 10 seconds (it

is presumed that system breakers will operate to isolate the fault within 2 seconds). The energy

that gets dissipated,I.e. (I2R) during continuous or overvoltage condition decides the size (dia) of

ZnO resistor element. These are classified as different classes depending upon the energy

handling capabilities. Higher class corresponds to higher energy capability.

37

3.7 INSULATOR

Electrical Insulator must be used in electrical system to prevent unwanted flow of electric

current to the earth from its supporting points. The insulator plays a vital role in electrical

system. Electrical Insulators a very high resistive path through which practically no current can

flow. In transmission and distribution system, the overhead conductors are generally supported

by supporting towers or poles. The towers and poles both are properly grounded. So there must

be insulator between tower or pole body and current carrying conductors to prevent the flow of

current from conductor to earth through the grounded supporting towers or poles.

Types of Insulator:

Pin Insulator

Suspension Insulator

 Strain Insulator

Post Insulator

Shackle Insulator

In 66 KV sub-station mostly we use suspension & strain insulator.

3.7.1 Suspension Insulator

In higher voltage, beyond 33KV, it becomes uneconomical to use pin insulator because size,

weight of the insulator become more. Handling and replacing bigger size single unit insulator

are quite difficult task. For overcoming these difficulties, suspension insulator was

developed. In suspension insulator numbers of insulators are connected in series to form a

string and the line conductor is carried by the bottom most insulator. Each insulator of a

suspension string is called disc insulator because of their disc like shape.

38

FIG 3.13 Suspension Insulator

3.7.2 Strain insulator

FIG 3.14 Suspension Insulator

When suspension string is used to sustain extraordinary tensile load of conductor it is referred

as string insulator. When there is a dead end or there is a sharp corner in transmission line,

the line has to sustain a great tensile load of conductor strain. A strain insulator must have

considerable mechanical strength as well as the necessary electrical insulating properties.

39

TABLE NO -1

3.8 CAPACITOR BANK

40

Rated System

Voltage

No. Of disc insulator used in

strain type tension insulator

string

No. Of disc insulator used in

suspension type tension

insulator string

33 KV 3 3

66 KV 5 4

132 KV 9 8

220 Kv 15 14

A capacitor bank is used in the outgoing bus so that it can maintain the voltage level same in the

outgoing feeder. Capacitor Control is usually done to achieve as many as possible of the

following goals:

Reduce losses due to reactive load current, reduce kVA demand, decrease customer energy

consumption, improve voltage profile, and increase revenue. Indirectly capacitor control also

results in longer equipment lifetimes because of reduced equipment stresses. Experience shows

that switched feeder capacitors produce some of the fastest returns on equipment investment.

3.8.1 Sources of Energy Loss

Energy losses in transmission lines and transformers are of two kinds: resistive and reactive. The

former are caused by resistive component of the load and cannot be avoided. The latter, coming

fromreactive component of the load, can be avoided (Fig. 1). Reactive losses come from circuit

capacitance (negative), and circuit inductance (positive). When a heavy inductive load is

connected to the power grid, a large positive reactive power component is added, thereby

increasing observed power load (Fig.1). This increases losses due to reactive load current,

increases kVA demand, increases customer energy consumption, usually degrades voltage

profiles, and reduces revenue.

FIG 3.15 POWER TRIAANGLE

3.8.2 Reactive Compensation

When capacitors of appropriate size are added to the grid at appropriate locations, the above

41

mentioned losses can be minimized by reducing the reactive power component in Fig. 1, thereby

reducing the observed power demand. There are many aspects to this compensation and its

effects, depending on where capacitors get to be located, their sizes, and details of the

distribution circuit.

Some are discussed below:

3.8.3 Energy Loss Reduction

More than one half of system energy loss is caused by the resistance of the feeders. To minimize

energy losses it is, therefore, important to locate feeder capacitors as close to the loads as

possible. Substation capacitors cannot do the job - the reactive load current has already heated

feeder conductors downstream from the substation. Reducing reactive current at the substation

can’t recover energy losses in the feeders. Another way to minimize energy losses is to use

capacitor banks that are not too large. This makes it possible to put the banks on-line early in the

load cycle. Since energy saved is the product of power reduction and the time the banks are

online, the overall energy reduction is usually greater than when using large banks which are

turned on for shorter amounts of time

FIG 3.16 GRAPH OF CURRENTS VS TIME

42

3.8.4 Demand Reduction

When capacitors are on-line reactive current and, therefore, total line current is reduced. During

heavy load periods this has several advantages: The peak load is increased when it is most

needed (essentially releasing demand), the effective line current capacity is increased, and the

operating line and transformer temperatures are reduced – prolonging equipment lifetimes. The

latter makes it possible to upgrade lines and transformers less frequently. All of these contribute

to reduced costs and higher revenues.

3.8.5 Voltage Profile

Distribution feeder demand capacity is usually limited by voltage drop along the line. The

customer service entrance voltage must be stable, usually ±5% to ±10%. The feeder voltage

profile can be‘flattened’ by connecting large capacity banks to the grid. Several benefits

become available: The kVA demand can be increased to arrive at the original voltage drop

(this is equivalent to releasing feeder demand), the substation voltage can be lowered to

reduce peak demand and save energy, or the service entrance voltage can be allowed to

increase thereby increasing revenue (at the expense of less than optimum kVA demand.

43

3.9 WAVE TRAP

.

FIG 3.17 SLD OF WAVE TRAP

Reliable & fast communication is necessary for safe efficient &economical power

supply. To reduce the power failure in extent & time, to maintain the interconnected

grid system in optimum working condition; to coordinate the operation of various

generating unit communication network is indispensable for state electricity board.

In state electricity boards, the generating & distribution stations are generally located

at a far distance from cities. Where P & T communication provided through long

overhead lines in neither reliable nor quick.

As we have available very reliable physical paths viz. the power lines, which

interconnected, hence power line carrier communication is found to be most

economical and reliable for electricity boards.

3.9.1 APPLICATIONS

The PLCC can be used for the following facilities:

1. Telephony

2. Teleprotection

3. Remote control or indication

4. Telemetry

5. Teleprinting

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3.9.2 PRINCIPLE OF PLCC

The principle of PLCC is the simple one:

All type of information is modulated on carried wave at frequency 50Hz to 500 KHz.

The modulated HF carrier fed into the power line conductor at the sending end and

filtered out again at the respective stations. Long earlier system double side band

amplitude modulation was more common but the present amplitude modulated

system.

Since high voltage power lines are designed to carry large quantities of energy on the

high voltage and the communication system at low voltage, they cannot be directly

connected to high voltage lines. Suitably designed coupling equipments have therefore

to be employed which will permit the injection of high frequency carrier signal

without undue loss and with absolute protection of communication equipments or

operating personal from high voltage hazard.

Therefore, the coupling equipment essentially comprises the following:

Wave trap or line trap

Wave trap is connected in series with power line between the point of connection of

coupling capacitor and S/S. Wave trap offers negligible impedance to HF carrier.

Wave trap stands electromechanically and thermally for short circuit current in the

event of fault on the line.

Coupling capacitor

The modulated carrier is let into power line through coupling capacitor specially

designed to with stand line voltage under all weather condition. The upper end of the

coupling capacitor is connected directly to the line and the lower end is connected to

the ground through a carrier frequency chock coil or drain coil. Thus coupling

capacitor forms the link between the PLCC equipment and power line. The coupling

capacitor used in UPSEB is 2200pf capacitance.The coupling capacitor are designed

for outdoor use and hence to withstand normal atmospheric phenomenon such as

temperature & humidity changes, rain, snow, anticipated wind load, nominal wire

tension etc. at full rated voltage. In some case capacitive voltage transformers (CVT)

45

used as a source of line voltage for metering and protection as also used coupling

capacitor .

CHAPTER 4

PROTECTION SYSTEM IN SUB-STATION

.4.1 Objective of power system protection

The objective of power system protection is to isolate a faulty section

of electrical power system from rest of the live system so that the rest portion can

function satisfactorily without any severer damage due to fault current.

Actually circuit breaker isolates the faulty system from rest of the healthy system

and this circuit breakers automatically open during fault condition due to its trip

signal comes from protection relay. The main philosophy about protection is that

no protection of power system can prevent the flow of fault current through the

system, it only can prevent the continuation of flowing of fault current by quickly

disconnect the short circuit path from the system.

4,2 Protection system in power system

Let’s have a discussion on basic concept of Protection system in power

system and coordination of protection relays.

FIG 4.1 CONNECTIONS OF RELAYS

46

In the picture the basic connection of protection relay has been shown. It is quite

simple. The secondary of current transformer is connected to the current coil of

relay. And secondary of voltage transformer is connected to the voltage coil of the

relay. Whenever any fault occurs in the feeder circuit, proportionate secondary

current of the CT will flow through the current coil of the relay due to which mmf

of that coil is increased. This increased mmf is sufficient to mechanically close the

normally open contact of the relay. This relay contact actually closes and

completes the DC trip coil circuit and hence the trip coil is energized. The mmf of

the trip coil initiates the mechanical movement of the tripping mechanism of the

circuit breaker and ultimately the circuit breaker is tripped to isolate the fault.

Some Relays used in Sub-Station

1. Over Current Relay

2. Over Voltage Relay

3. Differential Relay

4. Restricted Earth Fault Relay

5. Buchholz Relay

47

4.3 OVER CURRENT AND EARTH FAULT PROTECTION OF TRANSFORMER

Backup protection of electrical transformer is simple Over Current and Earth

Fault protection applied against external short circuit and excessive over loads.

These over current and earth Fault relays may be of Inverse Definite Minimum

FIG 4.2 O/C AND E/F SCHEME

Time (IDMT) or Definite Time type relays. Generally IDMT relays are

connected to the in-feed side of the transformer. The over current relays can

not distinguish between external short circuit, over load and internal faults of

the transformer. For any of the above fault, backup protection i.e. over current

and earth fault protection connected to in-feed side of the transformer will

operate. Backup protection is although generally installed at in feed side of the

transformer, but it should trip both the primary and secondary circuit breakers

of thtransformer

Over Current and Earth Fault protection relays may be also provided in load

side of the transformer too, but it should not inter trip the primary side Circuit

Breaker like the case of backup protection at in-feed side. The operation is

governed primarily by current and time settings and the characteristic curve of

the relay. To permit use of over load capacity of the transformer and co-

48

ordination with other similar relays at about 125 to 150% offull load current of

the transformer but below the minimum short circuit current.

Backup protection of transformer has four elements, three over current relays

connected each in each phase and one earth fault relay connected to the common

point of three over current relays as shown in the figure. The normal range of

current settings available on IDMT over current relays is 50% to 200% and on

earth fault relay 20 to 80%.

Another range of setting on earth fault relay is also available and may be

selected where the earth fault current is restricted due to insertion of impedance in

the neutral grounding. In the case of transformer winding with neutral earthed,

unrestricted earth fault protection is obtained by connecting an ordinary earth fault

relay across a neutral current transformer.

The unrestricted over current and earth fault relays should have proper time lag

to co - ordinate with the protective relays of other circuit to avoid

indiscriminate tripping

4.4 .DIFFERENTIAL PROTECTION OF TRANSFORMER

Generally Differential protection is provided in the electrical power

transformer rated more than 5MVA. The Differential Protection of

Transformer has many advantages over other schemes of protection. 1) The

faults occur in the transformer inside the insulating oil can be detected by

Buchholz relay. But if any fault occurs in the transformer but not in oil then it

can not be detected by Buchholz relay. Any flash over at the bushings are not

adequately covered by Buchholz relay.Differential relays can detect such type

of faults. Moreover Buchholz relay is provided in transformer for detecting any

internal fault in the transformer but Differential Protection scheme detects the

same in more faster way.

2) The differential relays normally response to those faults which occur in

side the differential protection zone of transformer.

49

4.4.1 PRINCIPLE OF OPERATION

Principle of Differential Protection scheme is one simple conceptual

technique. The differential relay actually compares between primary current

and secondary current of power transformer, if any unbalance found in

between primary and secondary currents the relay will actuate and inter trip

both the primary and secondary circuit breaker of the transformer.

4.5 .BUCHHOLZ RELAY

Construction of Buchholz Relay

Buchholz Relay in transformer is an oil container housed the connecting pipe

from main tank to conservator tank. It has mainly two elements. The upper

element consists of a float. The float is attached to a hinge in such a way that it

can move up and down depending upon the oil level in the Buchholz

RelayContainer. One mercury switch is fixed on the float. The alignment of

mercury switch hence depends upon the position of the float.

The lower element consists of a baffle plate and mercury switch. This plate is

fitted on a hinge just in front of the inlet (main tank side ) of Buchholz Relay

in transformer in such a way that when oil enters in the relay from that inlet

in high pressure the alignment of the baffle plate along with the mercury

switch attached to it, will change. In addition to these main elements

aBuchholz Relay has gas release pockets on top. The electrical leads from

both mercury switches are taken out through a molded terminal block.

4.5.1 Buchholz Relay principle

The Buchholz Relay working principle of is very simple. Buchholz Relay

function is based on very simple mechanical phenomenon. It is mechanically

actuated. Whenever there will be a minor internal fault in the transformer such

as an insulation faults between turns, break down of core of transformer, core

heating, the transformer insulating oil will be decomposed in different

50

hydrocarbon gases, CO2 and CO. The gases produced due to decomposition

of transformer insulating oil will accumulate in the upper part the Buchholz

Container which causes fall of oil level in it. Fall of oil level means lowering

the position of float and thereby tilting the mercury switch. The contacts of this

mercury switch are closed and an alarm circuit energized. Sometime due to oil

leakage on the main tank air bubbles may be accumulated in the upper part the

Buchholz Container which may also cause fall of oil level in it and alarm

circuit will be energized. By collecting the accumulated gases from the gas

release pockets on the top of the relay and by analyzing them one can predict

the type of fault in the transformer.

More severe types of faults, such as short circuit between phases or to earth

and faults in the tap changing equipment, are accompanied by a surge of oil

which strikes the baffle plate and causes the mercury switch of the lower

element to close. This switch energized the trip circuit of the Circuit Breakers

associated with the transformer and immediately isolate the faulty transformer

from the rest of the electrical power system by inter tripping the Circuit

Breakers associated with both LV and HV sides of the transformer. This is

how Buchholz Relay functions.

4.5.2 Buchholz Relay Operation – Certain Precaution

The Buchholz Relay operation may be actuated without any fault in the

transformer. For instance, when oil is added to a transformer, air may get in

together with oil, accumulated under the relay cover and thus cause a

false Buchholz Relay operation. That is why mechanical lock is provided in

that relay so that one can lock the movement of mercury switches when oil is

topping up in the transformer. This mechanical locking also helps to prevent

unnecessary movement of breakable glass bulb of mercury switches during

transportation of the Buchholz Relays.

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FIG 4.3 BUCHHOLZ RELAY

The lower float may also falsely operate if the oil velocity in the connection

pipe through, not due to internal fault, is sufficient to trip over the float. This

can occurs in the event of external short circuit when over currents flowing

through the winding cause overheated the copper and the oil and cause the oil

to expand.

52

4.6 LIGHTING ARRESTER

FIG 4.4 LIGHTING ARRESTER

A Lightning Arrester ( surge arrester) is a device used on electrical power systems

and telecommunications systems to protect the insulation and conductors of the

system from the damaging effects of lightning. The typical lightning arrester has

a high-voltage terminal and a ground terminal. When a lightning surge (or switching

surge, which is very similar) travels along the power line to the arrester, the current

from the surge is diverted through the arrestor, in most cases to earth.

In switchyard, a lightning arrestor is placed where wires enter a structure, preventing

damage to instruments within and ensuring the safety of individuals near them.

Smaller versions of lightning arresters, also called surge protectors, are devices that

are connected between each electrical conductor in power and communications

systems and the Earth. These prevent the flow of the normal power or signal currents

to ground, but provide a path over which high-voltage lightning current flows,

bypassing the connected equipment. Their purpose is to limit the rise in voltage when

a communications or power line is struck by lightning or is near to a lightning strike.

53

If protection fails or is absent, lightning that strikes the electrical system introduces

thousands of kilovolts that may damage the transmission lines, and can also cause

severe damage to transformers and other electrical or electronic devices. Lightning-

produced extreme voltage spikes in incoming power lines can damage electrical home

appliances

Surge Counter: Surge counter along with leakage current indicator. This device is

connected in series with the surge arrester by means of suitable cable at earth side.

The counter counts the number of surges passing through the surge arrester while the

leakage current indicator continuously indicates the leakage current through active

elements as well as over the surface of the surge arrester.

4.7 EARTHING

Earthing is foremost important for the safety of human beings, Animals, Consumer

Property and utilities equipment. In this article, the importance of Earthing

requirement of good Earthing, the factors which influence the property of the

diverting medium earth, condition monitoring of earth and method to improve the

earth conditions are discussed in depth. The sole purpose of substation

grounding/earthing is to protect the equipment from surges and

Lightning strikes and to protect the operating persons in the substation. The substation

earthing system is necessary for connecting neutral points of transformers and

generators to ground and also for connecting the non current carrying metal parts such

as structures, overhead shielding wires, tanks, frames, etc to earth. The function of

substation earthing system is to provide a grounding mat below the earth surface in

and around the substation which will have uniformly zero potential with respect to

ground and lower earth resistance to ensure that

. To provide discharge path for lightning over voltages coming via rod-gaps, surge

arresters, and Shielding wires etc.

. To ensure safety of the operating staff by limiting voltage gradient at ground level

in theSubstation

54

. To provide low resistance path to the earthing switch earthed terminals, so as to

discharge the trapped charge (Due to charging currents even the line is dead still

charge remains which causes dangerous shocks) to earth prior to maintenance and

repair

4.7.1 OBJECTIVE OF EARTHING

Prime Objective of Earthing is to provide a Zero potential surface in and around and

under the area where the electrical equipment is installed or erected.

To achieve this objective the non-current carrying parts of the electrical equipment is

connected to the general mass of the earth which prevents the appearance of

dangerous voltage on the enclosures and helps to provide safety to working staff and

public.

4.7.2 REQUIREMENT OF GOOD EARTHING

a) Good earth should have low resistance

b) It should stabilize circuit potential with respect to ground and limit overall potential

rise.

c) It should protect men material from injury or damage due to over voltage.

d) It should provide low impedance path to fault currents to ensure prompt and

consistent operation of protective relays, Surge arrester etc.,

e) It should keep maximum potential gradient along the surface of the sub-station

within safe limits during ground fault.

4.7.3. FACTORS THAT INFLUENCE THE CONDITION OF EARTH

The following factors in the earth should be maintained within the limit irrespective of

seasons so that the earth should fulfil the above requirements.

a) Kind of Soil – Soil resistivity

b) Moisture Content

c) Salt Content

d) Condition of Electrode

e) Temperature Co-efficient

55

CHAPTER 5

INDOOR EQUIPMENTS

5.1 CONTROL BATTERIES

There are 110 batteries of 2v each are connected in series. They provide the 220v DC to the control panels.

FIG NO 5.1 CONTROL BATTERY

sitive of the second battery. Run your negative wire off of the open connector from

the firstWhen connecting your batteries in Series you are doubling the voltage while

maintaining the same capacity rating (amp hours).

All the circuit breakers of electrical power system are DC (Direct Current) operated.

Because DC power can be stored in battery and if situation comes when total failure

of incoming power occurs, still the circuit breakers can be operated for restoring the

situation by the power of storage battery. Hence the battery is another essential item of

the power system. Some time it is referred as the heart of the electrical substation. A

Substation battery or simply a Station battery containing a number of cells accumulate

energy during the period of availability of A.C supply and discharge at the time when

relays operate so that relevant circuit breaker is trip

56

5.2 D.C PANEL

The DC supply is required in the substation for signaling remote position control,

remote indications and similar purposes. The AC supply is not always reliable hence

in no case of absence of AC supply the important purpose of control of CB in event of

fault of substations, on EHV lines should be affected. Therefore, all the relays,

tripping alarms, etc. are designed to work on DC. The panel consists of various

displays and indicators to show the supply status to different equipments. Normally,

they are available in the ratings of 110V dc and 220V dc

5.3 CONTROL AND RELAY PANEL

FIG NO 5.2 CONTROL AND RELAY PANEL

57

The Control and Relay Panels are mounted in the control room. Its main functions are:

1. To control the operations of breakers under normal and abnormal conditions of

system.

2. To provide indications of status of various equipments in the switchyard.

3. To indicate the current in the system, bus voltage, line voltage, temperature of

transformer Windings, oil, etc.

4. Measurement of energy through energy meter

The C& R Panels are mounted on the floor in the control room near cable trenches so

that cables can be taken in conveniently. The panels are arranged in rows in the

sequence according to that in switchyard. Earthing is provided for each C & R Panel.

Various relays are provided on these panels for protection of equipments like

transformers and lines etc. The relays are tested with testing kits and once the testing

is complete the settings are set on the relays according to proper protection

coordination in the system as per requirement.

5.4 INCOMING BREAKERS

FIG 5.3 INCOMING BREAKER

A breaker is sed to break the circuit in case of any faults or for maintenance purposes.

Incoming breaker is one which is given before the transformer side and the outgoing.

58

There are four sets of incoming breaker s are installed at the substation. They receive

the output of the power transformers. One of the basic functions of switchgear is

protection, which is interruption of short-circuit and overload fault currents while

maintaining service to unaffected circuits. Switchgear also provides isolation of

circuits from power supplies. Switchgear is also used to enhance system availability

by allowing more than one source to feed a load.

59

CHAPTER 6INTRODUCTION TO A.B.T

6.1 WHAT IS AVAILABILITY BASE TARIFF

The term Availability Tariff, particularly in the Indian context, stands for a rational

tariff structure for power supply from generating stations, on a contracted basis. The

power plants have fixed and variable costs. The fixed cost elements are interest on

loan, return on equity, depreciation, O&M expenses, insurance, taxes and interest on

working capital. The variable cost comprises of the fuel cost, i.e., coal and oil in case

of thermal plants and nuclear fuel in case of nuclear plants. In the Availability Tariff

mechanism, the fixed and variable cost components are treated separately. The

payment of fixed cost to the generating company is linked to availability of the plant,

that is, its capability to deliver MWs on a day-by-day basis. The total amount payable

to the generating company over a year towards the fixed cost depends on the average

availability (MW delivering capability) of the plant over the year. In case the average

actually achieved over the year is higher than the specified norm for plant availability,

the generating company gets a higher payment. In case the average availability

achieved is lower, the payment is also lower. Hence the name ‘Availability Tariff’.

This is the first component of Availability Tariff, and is termed ‘capacity charge’.

The second component of Availability Tariff is the ‘energy charge’, which comprises

of the variable cost (i.e., fuel cost) of the power plant for generating energy as per the

given schedule for the day. It may specifically be noted that energy charge (at the

specified plant-specific rate) is not based on actual generation and plant output, but on

scheduled generation. In case there are deviations from the schedule (e.g., if a power

plant delivers 600 MW while it was scheduled to supply only 500 MW), the energy

charge payment would still be for the scheduled generation (500 MW), and the excess

generation (100 MW) would get paid for at a rate dependent on the system conditions

prevailing at the time. If the grid has surplus power at the time and frequency is above

50.0 cycles, the rate would be lower. If the excess generation takes place at that time

of generation shortage in the system (in which condition the frequency would be

below 50.0 cycles), the payment for extra generation would be at a higher rate.

60

To recapitulate, the Indian version of Availability Tariff comprises of three

components: (a) capacity charge, towards reimbursement of the fixed cost of the

plant, linked to the plant's declared capacity to supply MWs, (b) energy charge,

to reimburse the fuel cost for scheduled generation, and (c) a payment for

deviations from schedule, at a rate dependent on system conditions. The last

component would be negative (indicating a payment by the generator for the

deviation) in case the power plant is delivering less power than schedule.

6.2 HOW DO BENEFICIARIES SHARES THE PAYMENT

The Central generating stations in different regions of the country have various States

of the Region as their specified beneficiaries or bulk consumers. The latter have

shares in these plants calculated according to Gadgil formula, and duly notified by the

Ministry of Power. The beneficiaries have to pay the capacity charge for these plants

in proportion to their share in the respective plants. This payment is dependent on the

declared output capability of the plant for the day and the beneficiary's percentage

share in that plant, and not on power / energy intended to be drawn or actually drawn

by the beneficiary from the Central station.

The energy charge to be paid by a beneficiary to a Central station for a particular day

would be the fuel cost for the energy scheduled to be supplied from the power plant to

the beneficiary during the day. In addition, if a beneficiary draws more power from

the regional grid than what is totally scheduled to be supplied to him from the various

Central generating stations at a particular time, he has to pay for the excess drawal at

a rate dependent on the system conditions, the rate being lower if the frequency is

high, and being higher if the frequency is low.

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6.3 HOW DOES MECHANISM WORK

The process starts with the Central generating stations in the region declaring their

expected output capability for the next day to the Regional Load

Dispatch Centre (RLDC). The RLDC breaks up and tabulates these output capability

declarations as per the beneficiaries' plant-wise shares and conveys their entitlements

to State Load Dispatch Centres (SLDCs). The latter then carry out an exercise to see

how best they can meet the load of their consumers over the day, from their own

generating stations, along with their entitlement in the Central stations. They also take

into account the irrigation release requirements and load curtailment etc. that they

propose in their respective areas. The SLDCs then convey to the RLDC their schedule

of power drawal from the Central stations (limited to their entitlement for the day).

The RLDC aggregates these requisitions and determines the dispatch schedules for

the Central generating stations and the drawal schedules for the beneficiaries duly

incorporating any bilateral agreements and adjusting for transmission losses. These

schedules are then issued by the RLDC to all concerned and become the operational

as well as commercial datum.

However, in case of contingencies, Central stations can prospectively revise the output

capability declaration, beneficiaries can prospectively revise requisitions, and the

schedules are correspondingly revised by RLDC.

While the schedules so finalized become the operational datum, and the regional

constituents are expected to regulate their generation and consumer load in a way that

the actual generation and drawls generally follow these schedules, deviations are

allowed as long as they do not endanger the system security. The schedules are also

used for determination of the amounts payable as energy charges, as described earlier.

Deviations from schedules are determined in 15-minute time blocks through special

metering, and these deviations are priced depending on frequency. As long as the

actual generation/drawal is equal to the given schedule, payment on account of the

third component of Availability Tariff is zero. In case of under-drawal, a beneficiary

is paid back to that extent according to the frequency dependent rate specified for

deviations from schedule.

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6.3 NECESSITY OF A.B.T

Prior to the introduction of Availability Tariff, the regional grids had been operating

in a very undisciplined and haphazard manner. There were large deviations in

frequency from the rated frequency of 50.0 cycles per second (Hz). Low frequency

situations result when the total generation available in the grid is less than the total

consumer load. These can be curtailed by enhancing generation and/or curtailing

consumer load. High frequency is a result of insufficient backing down of generation

when the total consumer load has fallen during off-peak hours. The earlier tariff

mechanisms did not provide any incentive for either backing down generation during

off-peak hours or for reducing consumer load / enhancing generation during peak-

load hours. In fact, it was profitable to go on generating at a high level even when the

consumer demand had come down. In other words, the earlier tariff mechanisms

encouraged grid indiscipline.

The Availability Tariff directly addresses these issues. Firstly, by giving incentives for

enhancing output capability of power plants, it enables more consumer load to be met

during peak load hours. Secondly, backing down during off-peak hours no longer

results in financial loss to generating stations, and the earlier incentive for not backing

down is neutralized. Thirdly, the shares of beneficiaries in the Central generating

stations acquire a meaning, which was previously missing. The beneficiaries now

have well-defined entitlements, and are able to draw power up to the specified limits

at normal rates of the respective power plants. In case of over-drawal, they have to

pay at a higher rate during peak load hours, which discourages them from over-

drawing further. This payment then goes to beneficiaries who received less energy

than was scheduled, and acts as an incentive/compensation for them.

6.5 ADVANTAGES OF A.B.T

The mechanism has dramatically streamlined the operation of regional grids in India.

Firstly, through the system and procedure in place, constituents’ schedules get

determined as per their shares in Central stations, and they

63

clearly know the implications of deviating from these schedules. Any constituent

which helps others by under-drawal from the regional grid in a deficit situation, gets

compensated at a good price for the quantum of energy under-drawn. Secondly, the

grid parameters, i.e., frequency and voltage, have improved, and equipment damage

correspondingly reduced. During peak load hours, the frequency can be improved

only by reducing drawls, and necessary incentives are provided in the mechanism for

the same. High frequency situation on the other hand, is being checked by

encouraging reduction in generation during off-peak hours. Thirdly, because of clear

separation between fixed and variable charges, generation according to merit-order is

encouraged and pithead stations do not have to back down normally. The overall

generation cost accordingly comes down. Fourthly, a mechanism is established for

harnessing captive and co-generation and for bilateral trading between the

constituents. Lastly, Availability Tariff, by rewarding plant availability, enables more

consumer load to be catered at any point of time.

64

CHAPTER 7 THE DAILY SCHEDULING PROCESS

7.1 BASIC PROCESS

Suppose a 1000 MW Central coal-fired power station has three beneficiaries

(States – A, B and C) with allocated shares of 30, 30 and 40% respectively.

Suppose the station foresees a capability to deliver 900 MW (ex-bus) on the next day,

and advises the same to the RLDC by 9 AM. The RLDC would break it up, and advise

the three SLDCs by 10 AM that their entitlements in the Central station are 270, 270

and 360 MW respectively, for the next day. Entitlements in the other Central stations

would also be advised by RLDC to the SLDCs similarly.

Simultaneously, the SLDCs would receive availability status from their intra -

State stations as well. They would then carry out a detailed exercise as to how best to

meet the expected consumer demand in their respective States over the 24 hours. For

this, they would compare the variable costs of various intra - State power stations

inter-se, and with energy charge rates of the Central stations, and also consider the

irrigation release requirements vs. energy availability of the hydro-electric stations.

After this exercise, the SLDCs will issue the dispatch schedules for the intra - State

stations, and their requisition from the Central stations (restricted to the States’

respective entitlements). Suppose States – A and B fully requisition their shares from

the Central station under consideration (270 MW each, throughout the 24-hour

period), while State – C requisitions 360 MW during the day time, but only 200

MW during the night hours.

Summation of the three requisitions would thus produce, for the Central generating

station, the total dispatch schedule of 900 MW during the day time and 740 MW

during the night hours, as illustrated in figure 7.1. This would be issued by the RLDC

by 5 PM, and would be effective from the following midnight (unless modified in the

intervening hours). States – A, B and C shall pay capacity charge for the whole day

corresponding to plant availability of 270, 270 and 360 MW, and the generating

65

station would get capacity charge corresponding to 900 MW. Energy charge

payments by the three States would be for 270 x 24 MWh, 270 x 24 MWh, and (200

x 24 + 160 x 16) MWh of energy respectively, at the specified energy charge rate of

the generating stations

Fig.7.1 An Example of Daily Schedule Process

66

CHAPTER 8

DEVIATIONS FROM SCHEDULE

As mentioned earlier, the energy charge, at the specified energy charge rate of a

generating station, is payable for the scheduled energy quantum. The energy actually

supplied by the generating station may differ from what was scheduled. If actual

energy supplied were higher than scheduled, the generating station would be entitled

to receive a payment for the excess energy (the deviation from schedule, technically

termed as Unscheduled

Interchange (UI) in Availability Tariff terminology) at a rate dependent on frequency

at that time. If the energy actually supplied is less than what is scheduled, the

generating station shall have to pay back for the energy shortfall, at the same

frequency - linked rate.

The relationship between the above UI rate and grid frequency, for the inter-State

system, is specified by CERC. The present relationship, applicable from1.10.2004, is

shown in figure 8.1.. When the frequency is 50.5 Hz or higher, the UI rate is zero,

which means that the generating station would not get any payment for the extra

energy supplied. It would burn fuel for producing this extra energy, but would not get

reimbursed for it at all. Conversely, if the actual energy supplied were less than

scheduled energy, the generating station would still be paid for the scheduled energy

(at its energy charge rate) without having to pay back anything for the energy

shortfall. It would thus be able to save on fuel cost (for the energy not generated) and

retain the energy charge as net saving. There is thus a strong commercial incentive to

back down generation during high frequency situations, and help in containing the

frequency rise.

67

Fig.8.1 Variation of UI rate with frequency

On the other hand, when frequency goes down, the UI rate (for both over-supply and

under-supply) ramps up, reaching a ceiling level of Rs. 5.70 per kWh at a frequency

of 49.0 Hz. At a frequency of 49.5 Hz, the UI rate is Rs. 3.45 per kWh presently.

Under this condition, any extra energy sent into the grid would get the generating

station a UI payment at the rate of Rs. 3.45 per kWh. For any shortfall, the generating

station shall have to pay back at the same rate. It would thus have a strong commercial

incentive to maximize its generation during periods of such low frequency.

A similar scheme operates for the States (beneficiaries) as well. Any State drawing

power in excess of its schedule has to pay for the excess energy at the same

frequency - dependant rate. The high UI rate during low-frequency conditions would

induce all States to reduce their drawal from the grid, by maximizing their own

generation and/or by curtailing their consumer load. If a State draws less power than

scheduled, it pays for scheduled energy quantum at the normal rate and gets paid

back for energy not draw at a much higher UI rate. On the other hand, during high-

frequency conditions, a State can draw extra power at a low rate, and is thus

encouraged to back down its own costlier generating stations. An under-drawal

during high-frequency conditions means that the State pays for the scheduled power

quantum unnecessarily. It should either reduce its schedule, or increase its drawal.

68

For the above purpose, the energy is metered in 15-minute time blocks, since

frequency keeps changing (and the UI rate with it). The metered energy is then

compared with the scheduled energy for that 15-minute time block, and the

difference (+ or -) becomes the UI energy. The corresponding UI rate is determined

by taking the average frequency for the same 15-minute time block into account.

Fig.8.2 An illustration of UI rate

Also, for each Central generating station and State, the actual energy has to be

metered on a net basis, i.e., algebraic sum of energy metered on all its peripheral

interconnection points, for every 15-minute time block. All UI payments are made

into and from a regional UI pool account, operated by the concerned RLDC.

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CHAPTER 9A SIMPLE TRADING OPPORTUNITY

Let us now return to figure 6.1. The two areas marked ‘X’ represent the off-peak hour

capability of the Central generating station, which State - C has not requisitioned,

although within its entitlement. This capability (160 MW) is now available with the

Central station, and it has three options before it, as follows:

i) Back down the station during off-peak hours, i.e., generate power only

according to the schedule given by RLDC by aggregating the requisition of the

three States. In this case, the station gets capacity charge for the day

corresponding to its availability declaration (900

MW), and energy charge to fully recover its fuel cost for generating the

scheduled quantum of energy during the day.

ii) Find a buyer (other than State - C) for the above off-peak surplus, and

generate power adding the MW agreed to be taken by this buyer, to the

aggregate schedule for States - A, B and C. As the station is already being paid

capacity charge for 900 MW, it may not be too particular about further fixed

cost recovery. As long as the energy sale rate agreed upon is higher than the

fuel cost per kWh of the station, it would be financially beneficial for the

station to enter into such a deal. It would also reduce the technical problems

associated with backing down of the station and improve the station’s

efficiency. If time permits, the Central generating station may look around to

find the party, which would pay the highest rate, and maximize its profit.

(There is a mistaken belief that the generating station has to share the accruing

profit with State - C. There is no such stipulation by CERC. The station is free

to retain the whole profit accruing on this account).

70

Instead of selling the off-peak surplus power through a bilateral agreement as

described above, the station may accept the schedule given by the RLDC, but

generate power to its full capability of 900 MW even during off-peak hours. The

result would be an over-supply of 160 MW (as a deviation from schedule), for which

the station would get paid from the regional UI pool account at the prevailing UI rate.

In effect, it would be a sale to the regional pool, and would make financial sense as

long as the prevailing UI rate is higher than the fuel cost per kWh of the station.

There is no restriction of any kind in this respect, and the Central generating stations

are free to exercise any of these options from time to time, or even a combination. The

only precaution the station needs to take, in the second option, is to ensure that its

agreement with the off-peak surplus buyer has a provision for termination / reduction

of supply at a very short notice. This may be required in case State - C, on the day of

operation, suddenly reverts and asks for scheduling of its full entitlement, and the

surplus capacity available with the Central station for such sale is no longer available.

In other words, the agreement has to be non-firm or interruptible. Consequently, the

price of this supply would be much lower than that for power supplied on a firm basis.

However, the above options for the generating station arise only in case a State has

not requisitioned its full entitlement in the first place. In fact, the same three options

are available to State - C, before they get passed on to the Central station, and are as

follows:

Requisition full entitlement of 360 MW from the Central station for the entire

24 - hour period, find a buyer for the off-peak surplus, and schedule a

bilateral sale. This would make sense as long as the sale rate per kWh is more

than the energy charge rate of the Central station.

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Requisition the full entitlement for the entire 24 - hour period, but draw power

only according to its actual requirement. In effect, this would be a pre-planned

deviation from schedule for which State - C would get UI payment. All that

State -C has to watch for and be vigilant about is that the UI rate during the

off-peak hours remains above the energy charge rate of the Central station. In

case the frequency rises and UI rate falls below the energy charge rate of the

concerned Central station, State - C should reduce its requisition and thereby

stop under-drawing

.

Availability of various and similar options, both for the beneficiaries and for the

generating companies, means that the mechanism is sound and equitable.

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CHAPTER 10U.I. RATE vs. SYSTEM MARGINAL COST

UI rate is tightly linked to grid frequency. As the frequency is same all over an A.C.

system, and can be readily seen through a simple frequency meter, it is easily possible

to know the prevailing UI rate anywhere in the system, without the help of any

communication system. With this on-line knowledge of the current UI rate, a State

would know what it would have to pay for an extra MW that it may draw from the

regional grid. It can readily compare this with the fuel cost it would save if generation

were reduced by one MW at its own station, having the highest variable cost. If the UI

rate is lower than the latter, it would be beneficial for the State to reduce its own

generation and draw the replacement energy from the regional grid, till it has backed

down all generation having a variable cost higher than the current UI rate. In the

process, the State’s marginal generation cost would move down, towards the

prevailing UI rate.

Meanwhile, other States too would take a similar action in the same time frame, and

total generation in the system would come down, resulting in a downward movement

of frequency, and an upward movement of UI rate, till the attainment of a state of

equilibrium wherein the marginal generation cost of every State would equal the UI

rate.

On the other hand, if a State finds the UI rate to be higher than the variable cost of any

of its partly loaded generating units at any time, it would be financially beneficial for

the State to maximize the output of all such generating units and thereby reduce its

drawal from the regional grid. The State would have an under-drawal, for which it

would get paid a UI rate higher than its marginal generation cost.

With similar action being taken by other States as well, the frequency would tend to

rise, and UI rate would decline correspondingly, till equilibrium is reached wherein

the marginal generation cost of every State would equal the UI rate. In other words,

there would be perpetual movement of UI rate and the system marginal cost towards

each other, leading to ultimate optimization in generation, on a region - wide basis.

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There would be another fallout of the above. Depending on its variable cost, each

generating unit would have a threshold frequency, i.e., the frequency at which the UI

rate equals the variable cost of the generating unit. The output of the generating unit

should be maximized as long as the grid frequency is below the threshold frequency,

irrespective of the schedule given out by the RLDC / SLDC for the unit. And the unit

should be backed down when grid frequency climbs up and exceeds the above

threshold frequency. For a pit-head generating station having an ex - power plant

variable cost of 90 paise/kWh, the threshold frequency, with the present UI rate –

frequency relationship, shall be 50.2 Hz. For a load-centre thermal plant with a

variable cost (ex - power plant) of 180 paise/kWh, the threshold frequency would be

49.9 Hz, as illustrated, and so on.

FIG 10.1 U.I RATES VS FREQ.As a consequence of this, the grid frequency would modulate over the 24-hour period.

It would be 50.0 Hz when the system load can be met by the available generating

units having a variable cost of up to 150 paise/kWh

(generally the case in late night hours). It would be only 49.5 Hz when all generating

units of variable cost up to about 350 paise/kWh have to be harnessed for meeting the

system demand (during peak-load hours). In due course, a frequency pattern would

emerge depending on the daily profile of total system load, and the generation mix.

The corresponding UI rate profile shall reflect the daily pattern of system marginal

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cost. Typical patterns that may emerge (after effective implementation of free -

governor mode of operation)

FIG 10.2 EFFECT OF FREQ. ON U,I RATES AND MARGINAL LOAD

As far as the hydro-electric units are concerned, their actual variable cost is zero, but

their generation may be restricted depending on availability of water.

As such, each hydro station would have an energy value in terms of the cost of energy

(from other sources) it can replace. Hydro stations with a storage capacity should be

run only during the peak-load hours, when their output can replace or supplement the

costlier energy. Again, depending on the frequency pattern and availability of water,

each hydro station can be assigned a threshold frequency. While the depleted hydro

plants may have a threshold frequency in 49.0 – 49.2 Hz range, the over-flowing

hydro stations may be assigned a threshold frequency of 50.5 Hz.

This would lead to a frequency - based dispatch of generating stations which

can be given out by the SLDCs as the dispatch guideline or instructions for their

generating stations. The underlying approach is that the frequency would be allowed

to float, and there would be no attempt to operate the grid at a frequency very close to

50.0 Hz. Also, while the schedules would serve as the commercial datum, the entities

would be free to deviate from the schedules, to achieve real region - wide merit -

order in generation, in an autonomous, decentralized and very cost - effective manner,

without depending on any communication and EMS / SCADA system

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CHAPTER 11

TRADING OF STATES’ SURPLUS GENERATION

A simple trading opportunity has been described in chapter - D, for the purpose of

explaining the working of the available mechanism. A surplus availability of Central

station entitlement for State - C has been assumed therein. Most of the large Central

stations are, however, pit-head or nuclear plants, with comparatively low variable

costs / energy charge rates. The instances of such low variable cost power being

determined as surplus would occur only when the off-peak hour consumer demand in

the State can be and is met from other sources having a comparable or still lower

variable cost. State - C would generally have its own load-centre plants, with a

variable cost higher than that of the Central station under consideration. These load-

centre plants would naturally be scheduled to back down during off-peak hours,

before the possibility or requirement of backing down the Central station arises.

In other words, the more common situation would be that the States’ own generating

stations are backed down during off-peak hours. It would therefore be the energy from

off-peak surplus of such stations that would be more commonly available daily for

being offered to another State, either for catering to consumer demand which the latter

cannot meet on its own, or to replace costlier energy. The State - C (which has such

off-peak surplus) should first try to find out if there are any buyers available for its

own surplus generation. Obviously, such buyers would have to pay a price higher than

the variable cost of load-centre stations concerned. If nobody is ready to pay such a

price for this off-peak energy, the concerned load-centre stations will have to be

backed down. If State - C has a surplus even after the permissible backing down /

shutting down of all such stations, the circumstances described in chapter - D would

arise, and options as explained therein shall have to be exercised.

The price at which State - C considers selling its own surplus generation would have

no relationship with the rate(s) at which State - C gets its entitlement from Central

generating stations. Instead, it will have to be higher than the variable cost of State -

C’s own stations, which would have to be backed down if this power is not purchased

by another State. The price that the latter may agree to pay shall however depend on

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(i) the price at which off-peak power may be available to the needy State on

comparable terms from some other source, (ii) the likely UI rate during those hours,

and (iii) the criticality of the need for additional power, and (iv) the price the needy

State is ready to pay. Obviously, these aspects cannot be covered in a formula, and the

price will have to be negotiated between State - C and the purchaser(s).

Now, suppose a situation arises wherein State - C does not require energy from a

certain station of its own, having a variable cost of say 200 paise/kWh, during certain

off-peak hours, and no other State is willing to enter into a bilateral contract for taking

this energy on a scheduled (committed) basis at 200 paise plus. In such a situation, the

State load dispatch centre (SLDC) shall have to schedule this station to back down

during such off-peak hours. However, if the actual frequency during those hours on a

particular day is below 49.8 Hz, this station should not back down. The resulting

surplus energy should go into the regional grid as State’s UI. The State would get paid

for it at the prevailing UI rate, and the amount should be suitably passed on to the

concerned generating station. This would happen automatically when Availability

Tariff is implemented for the intra - State stations as well.

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CHAPTER 12

EXPECTATIONS FROM CENTRAL STATIONS

In the day-to-day operation under Availability Tariff framework, a Central generating

station has to declare by 9 AM every morning its foreseen MW output capability for

the next day. This must be done judiciously and faithfully.

Unless it is planned to bring in or take out a generating unit or a major plant auxiliary,

a thermal station should have only one figure of MW availability for the whole of the

next day, i.e., for 24 hours midnight to midnight.

The above availability forecast should be the best assessment by the plant operators of

the average MW output capability. Based on the operational feedback during the day,

the availability forecast can be trimmed by 10 PM. No margins / cushions need be

kept. As long as the actual average availability during a day is close to the declared

availability for that day, there would be no commercial implications. In case the

foreseen plant availability changes due to a unit / equipment outage during the day,

the same should also be advised by the Central generating station to the RLDC, latest

by 10 PM.

In case a unit or auxiliary is required to be taken out of service during the next day, it

would be expected that it is planned to be done after the morning / evening peak.

Similarly, if a unit or auxiliary is to be brought back in operation, it should be so

planned that plant availability increases before the onset of morning / evening peak. It

is expected that these plant availability changes are declared faithfully, and plant

operation is attempted accordingly. There could however be problems during a unit

restart, resulting in deviations from schedule. As long as these are not deliberate, such

deviations should only be accounted as UI, and should not be viewed as “gaming”.

By 5 PM of the scheduling day, the dispatch schedule for Central stations (for the

next day) would be available from the concerned RLDC. Normally, all beneficiaries

would requisition their respective entitlements fully for all 24hours, and the Central

stations (other than liquid fired) would not have any residual capability available for

trading. However, in case a beneficiary requisitions less than its full entitlement, the

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Central station may at its sole option, trade the resulting residual capacity, as

described in chapter - D. If it is done on a bilateral basis (as per second alternative), it

has to be included in the final schedule for the next day, for which the RLDC has to

be advised by the Central station by 10 PM.

During the day of operation, the Central generating station would be expected to

operate in a safe and efficient manner, keeping in view its dispatch schedule and grid

conditions. As long as the grid frequency is below a generating unit’s threshold

frequency (described in chapter - E and illustrated in figure - 4), the unit should

deliver its full continuous output capability. When the grid frequency rises above the

unit’s threshold frequency and is likely to remain high, the unit should be backed

down in a graded manner, irrespective of its dispatch schedule.

. All generating units have to be on free - governor mode of operation (FGMO), and

have to participate in primary frequency control. For example, if frequency rises by

0.1 Hz, the unit load should automatically and immediately come down by 4 - 5%.

Over the next 4 -5 minutes, the unit load should gradually be brought back to the

previous level by supplementary control, as long as grid frequency remains below the

unit’s threshold frequency. When grid frequency goes above the threshold frequency,

the unit load should be reduced to the level as plotted in figure - 4. The desired

FGMO and supplementary control is discussed.

12.1 Frequency Control by FGMO

Frequency control requires provision of primary regulation and supplementary

regulation as basic requirement. Primary regulation is provided through speed

governors which respond to frequency changes by varying turbine outputs. Keeping

governors free to operate in the entire frequency range enables smooth control of

frequency fluctuations as well as security against grid disturbances. In India, due to

wide range of frequency fluctuations, speed governors were prevented from

responding by the utilities with dead band configuring from47.5 Hz to 51.50 Hz with

emergency unloading available only when frequency goes above 51.50 Hz. Efforts

have been made to enable speed governors responding in the entire frequency range

which has come to be known as free governor mode of operation (FGMO)

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The introduction of Availability Based Tariff (ABT) though stabilized frequency in a

narrower band, the rapid fluctuations continued to occur with frequency excursions of

0.5 Hz over a period of 10 minutes and frequency shooting up to 51 Hz and above

when sudden bulk load shedding or maximization of generation takes place before

evening peak hours. Dipping of frequency takes place during onset of peak loads or

unit tripping. Such frequency fluctuations during normal operation in the grid leads to

complex counter actions by the control center operators at regional and state level.

Further, the fluctuating frequency even in an interval of 15 minutes does not give out

clear signals to operators to plan generation changes, load shedding or to draw/inject

Unscheduled Interchange (UI) power responding to signals generated by the

commercial mechanism (ABT). Under ABT mechanism, frequency is allowed to float

between 49 Hz and 50.5 Hz and drawing / injection of UI power is permitted in this

frequency range. However, fluctuating frequency masks the frequency based ABT

signals.

In most of the grid disturbances over the last few years, Southern regional grid used to

split into four parts in the post fault scenario due to tripping of various lines in the

South-West-East-North regional corridor due to power swings. The Eastern part used

to have surplus of generation over load resulting in frequency shooting up to 52 Hz

and above leading to tripping of several generating units on high frequency. Another

pattern observed was isolation of Tamilnadu grid from the Southern part followed by

severe frequency decay and under frequency load shedding through df/dt relays which

brings up frequency above 52 Hz once again leading to tripping of some generators on

high frequency. After inter-connecting with WR and ER grids also, similar pattern

continued in the post fault scenario with tripping of generating units on high

frequency With implementation of free governor mode of operation on generating

units, tripping on high frequency could be avoided during grid disturbances as load

generation balance can be attained at a faster rate. Even during normal operation,

tripping of a 500 MW unit leads to frequency drop of around one hertz due to low

system stiffness as the frequency has to be controlled only by load damping effect in

the first 20-seconds after the tripping. FGMO would increase system stiffness

significantly and avoid large frequency dips in the event of unit tripping

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For example, 10000MW generation on FGMO with 5% droop in Central grid

would increase system stiffness by 2000 MW per hertz. Consider a system of 10000

MW at 50 Hz. Assume a droop of 5% for the entire grid system.

Case-1

If due to some reasons, a generator of 200 MW trips and no unit is under FGMO,

the dip in frequency will be 50 X 200/10000 = 1 Hz.

Case-2

If FGMO is available only for 5000 MW due to disabling of the governing action

in other sets, then the frequency drop will be

50 X (200/5000) X 5/100 = 0.1 Hz.

Case-3

If FGMO is available for all the 10000 MW, the dip

in frequency will be

50 X (200/10000) X 5/100 = 0.05 Hz only.

12.2 EVENT OF CONTENGENCY

In the event of unforeseen tripping of a generating unit or of a major auxiliary

(forced outage), which brings down the availability of the station suddenly, the

operator should quickly assess the possibility of bringing back the unit / auxiliary

and resuming generation as per the given schedule. In case this is possible within an

hour or two, the operator should inform the RLDC that the station’s availability

declaration (for commercial purpose) and schedule should not be revised.

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On the other hand, in case the station availability is foreseen to remain curtailed for a

longer duration, the RLDC should be formally informed about the change in station

availability, along with the curtailment duration, to the extent determined.

The RLDC would give effect to the availability change, and corresponding revision

of schedules, after one hour. During the intervening period, the deviation from

schedule would be recorded as UI, and the station would have to pay back for the

shortfall at the prevailing UI rate, while getting paid the capacity charge and energy

charge respectively as per pre-revised availability declaration and dispatch schedule.

This is illustrated in figure . The plant operator should therefore not delay his

availability change advice to RLDC.

It would be noted from the foregoing that the Central generating stations, at their

discretion, can deviate from the schedule given out by RLDC, and take advantage of

the UI mechanism. The schedule too is based on availability declaration by the

station. The stations thus have the desired autonomy. The only mandatory

requirement is that of operating within the overall framework of Availability Tariff

and Indian Electricity Grid Code (IEGC). FGMO is mandatory for all generating units

connected to grid. Another requirement under IEGC is that reactive power (MVAR)

generation at the Central stations shall be as per instructions of the concerned RLDC,

but within the generating units’ reactive capability.

On a long-term basis, the Central generating companies are expected to operate and

maintain their stations diligently, and ensure high plant availability in a sustained

manner. They should also coordinate sincerely with the concerned Regional Power

Committee (RPC) and RLDC in respect of scheduling of planned unit outages.

One of the primary objectives of Availability Tariff is to encourage maximisation of

generation, particularly during periods of power shortage. It is evident that the

country would continue to suffer from daily peak-hour shortage for many years to

come. No body need grudge the Central generating companies earning extra money

through achievement of a plant availability level higher than the norms; it only

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enables more consumer demand to be met, and load-shedding to be correspondingly

reduced. The only thing to be guarded against is that the plant availability is not

deliberately under-declared, with the objective of earning high amounts as UI.

Once the plant availability, i.e. the MW output capability, has been declared

judiciously and faithfully, the generating station should be freely allowed to deviate

from the given schedule without any restrictions, as long as there is no transmission

constraint. Any deviation which gives extra income to a generating station through the

UI mechanism also ensures extra power for consumers and/or enhanced optimisation /

conservation of resources, and is therefore acceptable.

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CHAPTER 13

GUIDANCE FOR STATE LOAD DISPATCH CENTRES(SLDCs)

The SLDCs shall have to carry out their functions in compliance with provisions in

the respective State Electricity Grid Code. This chapter is intended only for general

guidance of SLDCs from the perspective of Availability Tariff for Central stations

and Indian Electricity Grid Code (IEGC).

The daily scheduling process for Central stations has been described in chapter - B.

How the States can take advantage of the commercial mechanism now available, to

trade surplus generation in off-peak hours is described in chapters - D and F. These

mainly deal with actions on the previous day, up to issuance of final schedules by

RLDC. As a general rule, the SLDCs should requisition their entire entitlement in the

available Central generating station capacity (other than liquid fired) for the whole

day, unless their consumer load profile and intra-State generation mix is such that the

total State load during certain hours of the day is expected to be less than the

Central entitlement plus intra-State generation of a variable cost lower than the

highest energy charge rate of Central generation. In such a case, the requisition from

Central stations having high energy charge rates could be suitably curtailed during

the concerned hours, provided the frequency is expected to rise during those hours to

a level that causes the UI rate to fall below the energy charge rate of the concerned

station. In case frequency is not expected to rise to such a level during those hours,

Central station requisition should not be curtailed, and the surplus should be traded

bilaterally or as UI.

On the day of operation, the SLDCs have to primarily monitor the intra-State system.

They have to keep a general watch on the actual net drawal of the State from the

regional grid vis-à-vis the State’s net drawal schedule, but it is not necessary to

endeavor to equalize the two. In fact, in the system in place, it is beneficial as well as

desirable to deviate from the net drawal schedule depending on the circumstances.

For example, an overdrawal may result from increase in consumer load or reduction

of intra - State generation. If there is no transmission constraint and grid frequency is

good, it causes no problem for the larger grid, and the extra energy comes to the State

at a low UI rate.

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There can be no objection to extra consumer demand being met through such over-

drawal. There can also be no objection to the over-drawn energy replacing the intra

- State generation of a higher variable cost. The SLDC should in fact try to increase

its overdrawal further, as long as frequency is good, by (i) reducing own generation

which has a variable cost higher than prevailing UI rate, and (ii) restoring consumer

load that had been shed.

Even if a State overdraws in a low-frequency situation, it would mean meeting

consumer demand which would not have been met otherwise, and is beneficial from

this angle. However, it has following adverse implications:

i) The regional grid may be endangered if frequency falls below 49.0 Hz, or if

some transmission element gets excessively overloaded. RLDC may then ask

the SLDC to curtail its overdrawal, and SLDC must take necessary action

immediately.

ii) Another State (which is under-drawing) may be perceived to be getting

deprived of its rightful share. However, this would be the case only if that

State has resorted to load shedding, AND frequency is below 49.0 Hz. If a

State carries out load shedding and thereby causes inconvenience to its

consumers while frequency is above 49.0 Hz, it would be doing so either

because of a misconception or for commercial reasons, i.e., to get UI payment,

and therefore would not have a valid ground for feeling aggrieved.

iii) The over-drawing State shall have to pay UI charges at a high rate. The SLDC

would have to be sure that it is in the State’s overall interest.

The SLDC should therefore take the following corrective action in the event of

overdrawal during low frequency situation:

i) Increase Central station requisition to full entitlement (in case not fully

requisitioned earlier).

ii) Maximize generation at intra - State stations having variable costs lower than

prevailing UI rate. (This can be in the form of standing instructions, i.e.,

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frequency - linked dispatch guidelines).

iii) Harness captive and co-generation, to the extent available at a price lower than

the prevailing UI rate.

iv) Explore the possibility of purchasing power through a bilateral agreement.

v) Curtail consumer load.

A situation of under-drawal can arise in case consumer load in the State comes down

in an unpredictable manner. If this happens at a time of general shortage in the

regional grid (wherein frequency would be low), the under-drawal is beneficial for all,

and SLDC should let it continue. For enhanced optimization, the SLDC may even

resort to:

i) maximizing generation at all intra-State stations whose variable cost is below

the prevailing UI rate.

ii) increasing Central station requisition to full entitlement (in case not fully

requisitioned earlier).

iii) harnessing captive and co-generation, to the extent available at a price lower

than the prevailing UI rate.

iv) curtailing consumer load, by shedding low - priority consumers

(provided UI earning for the utility justifies such load shedding). This is

totally optional, and helps the regional grid.

86

Overall interest of consumers in the State is however to be safeguarded by the concerned State

Electricity Regulatory Commission (by specifying limits for such load shedding).

In case under-drawal takes place when grid frequency is good, the SLDC should take

action to reduce the under-drawal, through one or more of the following measures:

i) Restore consumer load which may have been shed.

ii) Back down intra-State generation having variable costs higher than prevailing

iii) UI rate, preferably through standing frequency - linked dispatch guidelines.

iv) Reduce drawal schedules for Central generating stations whose energy charge rate is

higher than the prevailing UI rate, and/or arrange a bilateral sale.

It would be seen from the above that the action to be taken by the SLDC depends on the grid

frequency, rather than on whether the State is in under-drawal or over-drawal mode. The need

for action on the above lines would generally arise when there is a change in system status, e.g.,

tripping of an intra-State generating unit, a load crash within the State, or a frequency change

due to load-generation imbalance elsewhere. Hence, the SLDC operators need to be perpetually

vigilant to promptly initiate the desired action, for grid security as well as commercial

optimization.

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CHAPTER 14

OPTIMUM UTILIZATION OF INTRA-STATE RESOURCES

Although Availability Tariff has so far been implemented only for Central generating stations,

and is perceived to be operating at regional (inter-State) level, it has an immediate, though

indirect, impact on intra-State operation, as explained below. In the mechanism now in place,

each State has a specified allocation in the identified Central stations, in terms of a percentage

share in the generating capacity. This determines the MW entitlement of each State day-by-day,

depending on ex-power plant capability declared for the day by the respective generating stations

on the previous day, as described in chapter - B. Since the above entitlement can meet only a part

(around 30%) of the total consumer demand in a State, it is necessary for each State to optimally

deploy the other (intra-State) resources, particularly because the total demand far exceeds the

total power availability presently.

In an interconnected power system, the net drawal of a State is always equal to the total

consumer load within the State minus the total of intra-State generation. In case the actual net

drawal exceeds the net drawal schedule (based on State’s entitlement in Central stations and its

requisition), the State has to pay UI charges. This liability can be reduced by restricting the

overdrawal, particularly when frequency is below normal. This in turn requires (if load shedding

has to be restricted) maximization of output from all intra-State stations, which means that there

is a pressure on each State as well for perpetually enhancing the availability of all intra-State

stations. It is another matter that in the absence of Availability Tariff for intra-State stations,

these stations have no direct incentive acting on them for maximizing their availability.

On the other hand, during off-peak hours, when total consumer load can be met from only a part

of the generating capacity available, the stations of higher variable cost should be backed down.

The intra-State stations are mostly located at load-centres and have a higher variable cost as

compared to Central stations, which are mostly pit-head. In the earlier regime (pre-ABT), in case

an SEB reduced its drawal from Central stations, its payment liability came down at the

composite rate (fixed + variable cost) of those stations. The

SEBs, therefore, made an uneven comparison: variable cost of their own stations versus

88

composite cost of Central stations, and did not back down their own stations if former was

lower, even if it was higher than the variable cost of Central stations. In effect, the merit order

was being distorted and generation was not being optimized. The position has now radically

changed. The SEBs compare only the variable costs, and ask intra-State stations to back down

during off-peak hours. These stations, however, are reluctant to back down (due to continuation

of single-part tariff for them, which discourages such backing down) and SLDCs face problems.

The remedy lies in implementation of Availability Tariff for all intra-State stations as well, and

only then would the States be able to achieve maximum optimization in their own operation.

Further, extension of the UI mechanism to the intra-State stations would get them to respond to

grid conditions on their own in the most desirable way. The States would be directly benefiting:

higher power availability during peak-load hours, reduced load shedding, and a possibility of

earning UI.

All hydro-electric stations, to the extent possible with storage / pondage volume available,

should be scheduled to generate during hours of peak system demand and to shut off / back

down during off-peak hours. During actual operation, they should back down any time the grid

frequency tends to rise and remain above a threshold even if it means deviating from the

schedule advised by SLDC. Similarly, when frequency tends to be below the threshold, the

generation should be increased (even if not scheduled during those hours of the day). Further,

bringing in of hydro generation should be held up/deferred if frequency is rising, and backing

down should be held up deferred if frequency is falling.

Pumped-storage plants should be operated with grid frequency as the primary signal. They

should be pumping during those hours of the day when frequency is at the highest level, even if

it causes the State to over-draw from the regional grid. They should be generating as per

capability during the hours when the frequency is at the lowest level. Such optimal operation,

however, requires the grid frequency to have a daily pattern, which should emerge when a

majority of the generating units are brought on effective free governor mode of operation.

The demand - supply gap in the country can be bridged substantially by harnessing the existing

captive and co-generation into the grid. This can be done fairly quickly by stipulating that any

89

injection from such plants into the grid (to the extent not covered under a contract with the SEB /

local utility) would be paid for as per the frequency-linked UI rate. The logic for this is simple:

such injection, with other things within the State remaining unchanged, would either reduce the

State’s over-drawal from the regional grid or increase its under-drawal, MW for MW. For each

unit injected by captive/co-generation, the State would financially gain with respect to regional

grid at the prevailing UI rate. This can be passed on to the supplier of that energy.

UI is a very versatile mechanism. It can even be applied for non-conventional generation (solar,

bio-mass, wind, mini-hydel) to gainfully harness the capacity, which may not come into the grid

otherwise.

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CHAPTER 15

“OPEN ACCESS”, “WHEELING” AND “ENERGY BANKING”

Availability Tariff is primarily meant for long-term supply from generating stations on a

contractual basis and is not directly applicable for transactions under “open access” and

“wheeling” provisions in the Electricity Act, 2003.

However, its third component (UI) has a great relevance. “Open access” and

“wheeling” generally involve two parties, one supplying a certain quantum of power to the other

through the regional / State grid. Any such transaction involves a number of parties, and disputes

could arise in scheduling, energy accounting and commercial settlement, unless an appropriate

framework is in place.

Suppose party - A has contracted to supply 10 MW round the clock to party - B (in the same

State) at a certain price (which need not be disclosed to others), through the State grid. Suppose

the transmission loss apportioned to this transaction has been determined as 0.5 MW. Party - B

would then be entitled to receive 9.5 MW, provided party - A is actually injecting 10.0 MW into

the State grid at its end. In actual operation, both injection by A and drawal by B may fluctuate

over the day and the differential may vary from 0.5 MW. Who would pick up the commercial

liability arising on account of these deviations? Since A and B are physically apart and

operationally independent, a pragmatic solution for commercial treatment in such a case would

be to meter the actual injection of A and actual drawal of B in 15-minute time blocks, and

separately compute their deviations from their respective schedules (10.0 MW / 2.5 MWh for A

and 9.5 MW / 2.375 MWh for B). The frequency-dependent UI rate can then be applied for the

deviations, A getting paid from (paying into) the State UI pool account for over (under) -

injection, and B getting paid from (paying into) the State UI pool account for under (over) -

drawal. The above would supplement the contractual payment by party - B to party - A for 10.0

MW of power supply, and applicable wheeling charges to the State grid owner, to complete the

settlement. Installation of this mechanism is absolutely a must for dispute - free and judicious

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operationalisation of “open access” and “wheeling” provisions. Besides, UI has another applica

application.

It would have been realized from chapter - D that UI provides an alternative to bilateral trading

of power. An entity with a surplus can sell it either by entering into a contract with another

entity, or can supply (sell) it to the pool (the regional grid) as UI. Similarly, an entity with a

deficit, or an entity wishing to replace its own costly generation with cheaper energy, can buy its

requirement either by entering into a contract with another entity, or simply draw (buy) it from

the pool (the regional grid) as UI.

A contracted sale or purchase necessarily involves (i) identifying a counterpart, (ii) agreeing on

power quantum, duration, price and other terms & conditions, (iii) ascertaining the adequacy of

transmission system, (iv) payment of applicable transmission / wheeling charges and absorption

of wheeling losses, (v) day-ahead scheduling through SLDC / RLDC concerned, (vii) payment

security for transaction, etc. An agreement also means a commitment by both the parties, to sell /

buy as per agreed terms. In case the seller fails to schedule the supply of the agreed quantum of

power (due to a short-fall in its own power availability, etc), or the buyer fails to schedule the

drawal of the agreed quantum of power (due to fall in its requirement, etc), it would mean a

contractual default. The agreement between the two parties must specify how such defaults are

to be handled. Another issue would be as to how a party (in case it is a regulated utility) selected

its counterpart and agreed on the price, and whether these have been done judiciously. Required

checks and balances may even delay the finalization of agreement, and trading opportunities

may be missed.

All of the above-listed complications get avoided if one goes through the UI route, but it has the

following implications: (i) there is no certainty about price (ii) RLDC/SLDC may ask the

supply/drawal to be curtailed in case of a transmission constraint. The major advantage,

however, is the flexibility: there is no commitment about the quantum. Also, no question can be

raised on the price from audit angle, since it is the prevailing pool price or system marginal cost.

The point being made here is that UI route provides an alternative to “open access” and

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‘wheeling”, and can be taken when one prefers flexibility over certainty. Even the “energy

banking” arrangements hitherto operated can all be beneficially replaced by the UI mechanism.

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CONCLUSION

Training at 220 kv Ablowal was a great learning experience both technically and personally.

Power sector is the backbone of every nation. Moreover, India being a developing nation relies

heavily on its Power Sector, be it Generation, Transmission or Distribution for its economic

development and during this training period I learned a lot about Power Sector. At Ablowal even

the trainees were treated more or less like regular employees, this helped me develop a

professional attitude. Interaction with clients for every project helped in improvement of my

communication skills. My analytical skills are also enhanced. After this internship I feel fully

prepared to enter into the corporate world.

I think that my training was successful and 220 kv substation at Ablowal is an excellent training

centre for inquisitive emerging electrical engineers to learn about the high voltage electricity

transmission and distribution with the the functioning of all other protective devices.

training session we came to know about the fundamentals of power system which may be quite

useful in future

I also learn about AVAILABILITY TARIFF for disciplined and accurate operation of power

system.The unique feature of this tariff, to tackle the peculiar problems of grid operation in india,

is the frequency linked pricing of the Unschedule Interchange.

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REFERNCES

Google.com

Wikipedia

Power system engg. ( Nagtath and Kothari)

electrical-engineering-portal.com

engineersgarage

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