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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
1
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-
2
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
3
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.
4
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.
5
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
6
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.
7
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
8
(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.
10
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
16
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
17
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
18
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
19
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
20
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.
21
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.
22
(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.
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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.
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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.
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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.
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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
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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.
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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).
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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)
79
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.
84
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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