study of substation

PROJECT REPORT

ON

STUDY OF SUB-STATION


BACHELOR OF TECHNOLOGY

IN

ELECTRICAL & ELECTRONICS ENGINEERING



BY
B.UDAY KIRAN
(07821A0210)



Under the Esteemed Guidance of

Mr. M. Srinivas
A.D.E



MAHESHWARA ENGINEERING COLLEGE
(Affiliated to J.N.T.University, Hyderabad)
Patancheru, Hyderabad
2010









A Project report


On


STUDY OF SUB-STATION
220 K.V















ABSTRACT

STUDY OF SUB-STATION

The electrical energy usage is day by day increasing. The present day electrical power system is a.c that is electrical energy is generated, transmitted and distributed in the form of alternating current.

The electrical power is produced at the power stations which are located at favorable places generally quite away from the consumers. It is delivered to the consumers to a large network of transmission and distribution.

The assembly of apparatus used to change some characteristics (e.g. voltage a.c to d.c, frequency, p.f etc) of electric supply is called a sub-station. Substation is important part of power system. The continuity of supply depends to a considerable extent upon the successful operation of sub-stations. It is, therefore, essential to exercise utmost care while designing and building a sub-station.

To analyze the working of sub-station we have to know the working of each and every component used in a sub station. By studying each and every component which is installed in sub station we can easily analyze the working of a sub-station.

The major component of a sub-station is transformer. It is used for two functions, those are
a) Voltage step-up and
b) Voltage step-down

Need of step–up of voltage is because, the transmission losses (I²R losses) are depends on current ‘I’ flowing through transmission lines, we know that transformer is a device at constant power we can increase or decrease the voltage (while voltage increases current automatically decreases) by step-upping the voltage we can reduce the transmission losses, as well as for Domestical purpose we need low voltages for that step-down is necessary thing.











CONTENTS



• Introduction to Sub-Station, Malyalapally
• Circuit symbols
• Single Line diagram
• Switch yard components

* BUS BARS
* CIRCUIT BREAKERS
* ISOLATORS
* LIGHTNING ARRESTERS
* CURRENT TRANSFORMERS
* CAPACITOR VOLTAGE TRANSFORMERS
* WAVE TRAP
• Components Ratings
• Maintenance schedule














INTRODUCTION






















SUB-STATION

Electric power substation
An assembly of equipment in an electric power system through which electrical energy is passed for transmission, distribution, interconnection, transformation, conversion, or switching.
Specifically, substations are used for some or all of the following purposes: connection of generators, transmission or distribution lines, and loads to each other; transformation of power from one voltage level to another; interconnection of alternate sources of power; switching for alternate connections and isolation of failed or overloaded lines and equipment; controlling system voltage and power flow; reactive power compensation; suppression of over voltage; and detection of faults, monitoring, recording of information, power measurements, and remote communications. Minor distribution or transmission equipment installation is not referred to as a substation.
Substations are referred to by the main duty they perform. Broadly speaking, they are classified as: transmission substations, which are associated with high voltage levels; and distribution substations, associated with low voltage levels. See Electric distribution systems
Substations are also referred to in a variety of other ways:
1. Transformer substations are substations whose equipment includes transformers.
2. Switching substations are substations whose equipment is mainly for various connections and interconnections, and does not include transformers.
3. Customer substations are usually distribution substations on the premises of a larger customer, such as a shopping center, large office or commercial building, or industrial plant.
4. Converter stations are complex substations required for high-voltage direct-current (HVDC) transmission or interconnection of two ac systems which, for a variety of reasons, cannot be connected by an ac connection. The main function of converter stations is the conversion of power from ac to dc and vice versa. The main equipment includes converter valves usually located inside a large hall, transformers, filters, reactors, and capacitors.
5. Most substations are installed as air-insulated substations, implying that the bus-bars and equipment terminations are generally open to the air, and utilize insulation properties of ambient air for insulation to ground. Modern substations in urban areas are esthetically designed with low profiles and often within walls, or even indoors.
6. Metal-clad substations are also air-insulated, but for low voltage levels; they are housed in metal cabinets and may be indoors or outdoors.
7. Acquiring a substation site in an urban area is very difficult because land is either unavailable or very expensive. Therefore, there has been a trend toward increasing use of gas-insulated substations, which occupy only 5–20% of the space occupied by the air-insulated substations. In gas-insulated substations, all live equipment and bus-bars are housed in grounded metal enclosures, which are sealed and filled with sulfur hexafluoride (SF6) gas, which has excellent insulation properties.
8. For emergency replacement or maintenance of substation transformers, mobile substations are used by some utilities.
An appropriate switching arrangement for “connections” of generators, transformers, lines, and other major equipment is basic to any substation design. There are seven switching arrangements commonly used: single bus; double bus, single breaker; double bus, double breaker; main and transfer bus; ring bus; breaker-and-a-half; and breaker-and-a-third. Each breaker is usually accompanied by two disconnect switches, one on each side, for maintenance purposes. Selecting the switching arrangement involves considerations of cost, reliability, maintenance, and flexibility for expansion.
A substation includes a variety of equipment. The principal items are transformers, circuit breakers, disconnect switches, bus-bars, shunt reactors, shunt capacitors, current and potential transformers, and control and protection equipment. Like Circuit breaker, Electric protective devices, Electric switch, Relay, Transformer
Good substation grounding is very important for effective relaying and insulation of equipment; but the safety of the personnel is the governing criterion in the design of substation grounding. It usually consists of a bare wire grid, laid in the ground; all equipment grounding points, tanks, support structures, fences, shielding wires and poles, and so forth, are securely connected to it. The grounding resistance is reduced enough that a fault from high voltage to ground does not create such high potential gradients on the ground, and from the structures to ground, to present a safety hazard. Good overhead shielding is also essential for outdoor substations, so as to virtually eliminate the possibility of lightning directly striking the equipment. Shielding is provided by overhead ground wires stretched across the substation or tall grounded poles.
















There are of totally 3-feeders are coming from N.T.P.C power plant to this sub-station to get distributed to different places.

Basically the input feeders are of 220kv and they are joined together and distributed to 8-places, those are named as
• Nirmal
• Bhemgal
• Dichpally
• Warangal-I
• Warangal-II
• Durshed-I
• Durshed-II
• Jagityal

Inputs are basically from N.T.P.C and those are named as
• N.T.P.C – I
• N.T.P.C - II
• N.T.P.C - III

These input and out put feeders are connected to the Double bus bar system it is shown in the single line diagram of the sub-station























SWITCHYARD COMPONENTS
&
ITS FUNCTIONS



Switch yard is the place where different equipments like Bus-bars, Circuit breakers, etc., are arranged in the proper way for the protection of Transmission lines under different fault conditions (i.e., short circuit etc.)


The different switchyard equipments are:


• BUS BARS
• CIRCUIT BREAKERS
• ISOLATORS
• LIGHTNING ARRESTERS
• CURRENT TRANSFORMERS
• CAPACITOR VOLTAGE TRANSFORMERS
• WAVE TRAP
• BATTERY OPERATION and
• GROUNDIMG OF SUB-STATION



About each and every component explained in below section

























Bus bar arrangement:

Bus bars are used to connect various incoming and outgoing circuits electrically. Bus bars are copper rods or thin walled tubes and operate at constant voltage.
They are two types of bus bars
• Single Bus bar
• Double Bus bar


Here in this sub-station we can see that the arrangement of double Bus bar connections

Double bus bar arrangement
In large sub-stations, it is important that break down and maintenance should be interfering as little as possible with continuity of supply. The following figure shows the arrangement of two bus-bar system.
The scheme envisages use of two identical bus bars so that, each load may be fed from either bus. Either bus may be taken out for maintenance work. The in feed loads circuits may be divided into separate groups in need from operation consideration.
This arrangement has been adopted where the loads and continuity of supply justify additional costs. In such a scheme a bus coupler breaker is mostly provided as or enables “on load” change over from one bus to other. However this arrangement does not permit breaker maintenance without causing stoppage of supply.

Advantages of Double Bus Bar:

If a fault occurs on bus bar, the continuity of supply to the circuit can be maintained by transferring it to the other bus bar.
If repair and maintenance is to be carried on the main bus, the supply need not be interrupted as the entire load can be transferred to another bus.

The two busses are connected by system called bus coupler it is used for connecting and disconnecting of two busses from one and another










Circuit Breaker:
An early form of circuit breaker was described by Edison in an 1879 patent application, although his commercial power distribution system used fuses. [1] Its purpose was to protect lighting circuit wiring from accidental short-circuits and overloads.
All circuit breakers have common features in their operation, although details vary substantially depending on the voltage class, current rating and type of the circuit breaker.
The circuit breaker must detect a fault condition; in low-voltage circuit breakers this is usually done within the breaker enclosure. Circuit breakers for large currents or high voltages are usually arranged with pilot devices to sense a fault current and to operate the trip opening mechanism. The trip solenoid that releases the latch is usually energized by a separate battery, although some high-voltage circuit breakers are self-contained with current transformers, protection relays, and an internal control power source.
Once a fault is detected, contacts within the circuit breaker must open to interrupt the circuit; some mechanically-stored energy (using something such as springs or compressed air) contained within the breaker is used to separate the contacts, although some of the energy required may be obtained from the fault current itself. Small circuit breakers may be manually operated; larger units have solenoids to trip the mechanism, and electric motors to restore energy to the springs.
The circuit breaker contacts must carry the load current without excessive heating, and must also withstand the heat of the arc produced when interrupting the circuit. Contacts are made of copper or copper alloys, silver alloys, and other materials. Service life of the contacts is limited by the erosion due to interrupting the arc. Mechanical circuit breakers are usually discarded when the contacts are worn, but power circuit breakers and high-voltage circuit breakers have replaceable contacts.
When a current is interrupted, an arc is generated - this arc must be contained, cooled, and extinguished in a controlled way, so that the gap between the contacts can again withstand the voltage in the circuit. Different circuit breakers use vacuum, air, insulating gas, or oil as the medium in which the arc forms. Different techniques are used to extinguish the arc including:
• Lengthening of the arc
• Intensive cooling (in jet chambers)
• Division into partial arcs
• Zero point quenching
• Connecting capacitors in parallel with contacts in DC circuits
Finally, once the fault condition has been cleared, the contacts must again be closed to restore power to the interrupted circuit.
Arc interruption
Mechanical low-voltage circuit breakers use air alone to extinguish the arc. Larger ratings will have metal plates or non-metallic arc chutes to divide and cool the arc. Magnetic blowout coils deflect the arc into the arc chute.
In larger ratings, oil circuit breakers rely upon vaporization of some of the oil to blast a jet of oil through the arc. Gas (usually sulfur hexafluoride) circuit breakers sometimes stretch the arc using a magnetic field, and then rely upon the dielectric strength of the sulfur hexafluoride (SF6) to quench the stretched arc.
Vacuum circuit breakers have minimal arcing (as there is nothing to ionize other than the contact material), so the arc quenches when it is stretched a very small amount (<2-3 mm). Vacuum circuit breakers are frequently used in modern medium-voltage switchgear to 35,000 volts.
Air circuit breakers may use compressed air to blow out the arc, or alternatively, the contacts are rapidly swung into a small sealed chamber, the escaping of the displaced air thus blowing out the arc.
Circuit breakers are usually able to terminate all current very quickly: typically the arc is extinguished between 30 ms and 150 ms after the mechanism has been tripped, depending upon age and construction of the device.
Short circuit current
A circuit breaker must incorporate various features to divide and extinguish the arc.
The maximum short-circuit current that a breaker can interrupt is determined by testing. Application of a breaker in a circuit with a prospective short-circuit current higher than the breaker's interrupting capacity rating may result in failure of the breaker to safely interrupt a fault. In a worst-case scenario the breaker may successfully interrupt the fault, only to explode when reset.
Miniature circuit breakers used to protect control circuits or small appliances may not have sufficient interrupting capacity to use at a panel board; these circuit breakers are called "supplemental circuit protectors" to distinguish them from distribution-type circuit breakers.
Electrical power transmission networks are protected and controlled by high-voltage breakers. The definition of "high voltage" varies but in power transmission work is usually thought to be 72,500 V or higher, according to a recent definition by the International Electro technical Commission (IEC). High-voltage breakers are nearly always solenoid-operated, with current sensing protective relays operated through current transformers. In substations the protection relay scheme can be complex, protecting equipment and busses from various types of overload or ground/earth fault.
High-voltage breakers are broadly classified by the medium used to extinguish the arc.
• Bulk oil
• Minimum oil
• Air blast
• SF6
Some of the manufacturers are ABB, AREVA, Cutler-Hammer (Eaton), Mitsubishi Electric, Pennsylvania Breaker, Schneider Electric, Siemens, Toshiba, and others.
Circuit breaker can be classified as "live tank", where the enclosure that contains the breaking mechanism is at line potential, or dead tank with the enclosure at earth potential. High-voltage AC circuit breakers are routinely available with ratings up to 765,000 volts.
High-voltage circuit breakers used on transmission systems may be arranged to allow a single pole of a three-phase line to trip, instead of tripping all three poles; for some classes of faults this improves the system stability and availability.
Sulfur Hexafluoride (SF6) high-voltage circuit-breakers
High-voltage circuit-breakers have greatly changed since they were first introduced about 40 years ago, and several interrupting principles have been developed that have contributed successively to a large reduction of the operating energy. These breakers are available for indoor or outdoor applications, the latter being in the form of breaker poles housed in ceramic insulators mounted on a structure.
Current interruption in a high-voltage circuit-breaker is obtained by separating two contacts in a medium, such as SF6, having excellent dielectric and arc quenching properties. After contact separation, current is carried through an arc and is interrupted when this arc is cooled by a gas blast of sufficient intensity.
Gas blast applied on the arc must be able to cool it rapidly so that gas temperature between the contacts is reduced from 20,000 K to less than 2000 K in a few hundred microseconds, so that it is able to withstand the transient recovery voltage that is applied across the contacts after current interruption. Sulphur hexafluoride is generally used in present high-voltage circuit-breakers (of rated voltage higher than 52 kV).
In the 1980s and 1990s, the pressure necessary to blast the arc was generated mostly by gas heating using arc energy. It is now possible to use low energy spring-loaded mechanisms to drive high-voltage circuit-breakers up to 800 kV.
Brief history
The first patents on the use of SF6 as an interrupting medium were filed in Germany in 1938 by Vitally Grosse (AEG) and independently later in the USA in July 1951 by H.J. Lingual, T.E. Browne and A.P. Storm (Westinghouse). The first industrial application of SF6 for current interruption dates back to 1953. High-voltage 15 kV to 161 kV load switches were developed with a breaking capacity of 600 A. The first high-voltage SF6 circuit-breaker built in 1956 by Westinghouse, could interrupt 5 kA under 115 kV, but it have 6 interrupting chambers in series per pole. In 1957, the puffer-type technique was introduced for SF6 circuit breakers where the relative movement of a piston and a cylinder linked to the moving part is used to generate the pressure rise necessary to blast the arc via a nozzle made of insulating material (figure 1). In this technique, the pressure rise is obtained mainly by gas compression. The first high-voltage SF6 circuit-breaker with a high short-circuit current capability was produced by Westinghouse in 1959. This dead tank circuit-breaker could interrupt 41.8 kA under 138 kV (10,000 MV•A) and 37.6 kA under 230 kV (15,000 MV•A). These performances were already significant, but the three chambers per pole and the high pressure source needed for the blast (1.35 MPa) was a constraint that had to be avoided in subsequent developments. The excellent properties of SF6 lead to the fast extension of this technique in the 1970s and to its use for the development of circuit breakers with high interrupting capability, up to 800 kV.

The achievement around 1983 of the first single-break 245 kV and the corresponding 420kV to 550 kV and 800 kV, with respectively 2, 3, and 4 chambers per pole, lead to the dominance of SF6 circuit breakers in the complete range of high voltages.
Several characteristics of SF6 circuit breakers can explain their success:
• Simplicity of the interrupting chamber which does not need an auxiliary breaking chamber;
• Autonomy provided by the puffer technique;
• The possibility to obtain the highest performance, up to 63 kA, with a reduced number of interrupting chambers;
• Short break time of 2 to 2.5 cycles;
• High electrical endurance, allowing at least 25 years of operation without reconditioning;
• Possible compact solutions when used for "gas insulated switchgear" (GIS) or hybrid switchgear;
• Integrated closing resistors or synchronized operations to reduce switching over-voltages;
• Reliability and availability;
• Low noise levels.
The reduction in the number of interrupting chambers per pole has led to a considerable simplification of circuit breakers as well as the number of parts and seals required. As a direct consequence, the reliability of circuit breakers improved, as verified later on by CIGRE surveys.
Thermal blast chambers
New types of SF6 breaking chambers, which implement innovative interrupting principles, have been developed over the past 15 years, with the objective of reducing the operating energy of the circuit-breaker. One aim of this evolution was to further increase the reliability by reducing the dynamic forces in the pole. Developments since 1996 have seen the use of the self-blast technique of interruption for SF6 interrupting chambers.
These developments have been facilitated by the progress made in digital simulations that were widely used to optimize the geometry of the interrupting chamber and the linkage between the poles and the mechanism.
This technique has proved to be very efficient and has been widely applied for high voltage circuit breakers up to 550 kV. It has allowed the development of new ranges of circuit breakers operated by low energy spring-operated mechanisms.


The reduction of operating energy was mainly achieved by the lowering energy used for gas compression and by making increased use of arc energy to produce the pressure necessary to quench the arc and obtain current interruption. Low current interruption, up to about 30% of rated short-circuit current, is obtained by a puffer blast.
Self-blast chambers
Further development in the thermal blast technique was made by the introduction of a valve between the expansion and compression volumes. When interrupting low currents the valve opens under the effect of the overpressure generated in the compression volume. The blow-out of the arc is made as in a puffer circuit breaker thanks to the compression of the gas obtained by the piston action. In the case of high currents interruption, the arc energy produces a high overpressure in the expansion volume, which leads to the closure of the valve and thus isolating the expansion volume from the compression volume. The overpressure necessary for breaking is obtained by the optimal use of the thermal effect and of the nozzle clogging effect produced whenever the cross-section of the arc significantly reduces the exhaust of gas in the nozzle. In order to avoid excessive energy consumption by gas compression, a valve is fitted on the piston in order to limit the overpressure in the compression to a value necessary for the interruption of low short circuit currents.


Self-blast circuit breaker chamber (1) closed, (2) interrupting low current, (3) interrupting high current, and (4) open.
This technique, known as “self-blast” has now been used extensively since 1996 for the development of many types of interrupting chambers. The increased understanding of arc interruption obtained by digital simulations and validation through breaking tests, contribute to a higher reliability of these self-blast circuit breakers. In addition the reduction in operating energy, allowed by the self blast technique, leads to longer service life.
Double motion of contacts
An important decrease in operating energy can also be obtained by reducing the kinetic energy consumed during the tripping operation. One way is to displace the two arcing contacts in opposite directions so that the arc speed is half that of a conventional layout with a single mobile contact.

The thermal and self blast principles have enabled the use of low energy spring mechanisms for the operation of high voltage circuit breakers. They progressively replaced the puffer technique in the 1980s; first in 72.5 kV breakers, and then from 145 kV to 800 kV.
Comparison of single motion and double motion techniques
The double motion technique halves the tripping speed of the moving part. In principle, the kinetic energy could be quartered if the total moving mass was not increased. However, as the total moving mass is increased, the practical reduction in kinetic energy is closer to 60%. The total tripping energy also includes the compression energy, which is almost the same for both techniques. Thus, the reduction of the total tripping energy is lower, about 30%, although the exact value depends on the application and the operating mechanism. Depending on the specific case, either the double motion or the single motion technique can be cheaper. Other considerations, such as rationalization of the circuit-breaker range, can also influence the cost.
Thermal blast chamber with arc-assisted opening
In this interruption principle arc energy is used, on the one hand to generate the blast by thermal expansion and, on the other hand, to accelerate the moving part of the circuit breaker when interrupting high currents. The overpressure produced by the arc energy downstream of the interruption zone is applied on an auxiliary piston linked with the moving part. The resulting force accelerates the moving part, thus increasing the energy available for tripping.
With this interrupting principle it is possible, during high-current interruptions, to increase by about 30% the tripping energy delivered by the operating mechanism and to maintain the opening speed independently of the current. It is obviously better suited to circuit-breakers with high breaking currents such as Generator circuit-breakers


SF6 Circuit Breaker

Circuit breaker opening mechanism


Isolator:
Isolator is a no-load switch whether the circuit breaker is an on-load switch. To operate the isolator we should have to disconnect the load from the feeder by tripping the circuit breaker after that by using opening and closing mechanism of the isolator we can operate it, it contains a thick copper rod for the flow of current. These are of two types divided based on opening and closing mechanisms, those are
i. Automatic operation
ii. Manual operation
In automatic mechanism an electric motor is used for the operation of the isolator ,from the control room only we can handle the isolator but in manual operating type externally we have to apply the mechanical force to the system to open and closing functions when ever we need




Lightning Arrester:

An electric discharge between cloud and earth , between clouds or between the charge centers of the same cloud is known as lightning.
The equipment is used to protect the equipment of sub-station from the these lightning are called as “Lightning arresters”, these are also called as surge diverters . Under normal conditions , the lightning arresters is off the line i.e. it conducts no current to earth , if any lightning strokes are attacked it attract those strokes and makes the current flow to ground.
These are of different types, those are
1. Road gap arresters
2. Horn gap arresters
3. Multi gap arresters
4. Expulsion type arresters
5. Valve type arresters

The lightning arrester presents at the starting position of the feeder that may be input feeder or out put feeder , why because to avoid the entering of high voltages to the sub-station which is produced due to lightning mainly in rainy season.
WORKING PRINCIPLE
It is just like a series of capacitors are connected in series and grounded we know that whenever thundering is produced it causes high current flow from the feeder with high frequency, for high frequency capacitor acts as a short circuit one then whenever lightning is occurred arrester will become short circuit and grounds the high currents produced due to lightning.

Current transformer:
A current transformer is a device for measuring a current flowing through a power system and inputting the measured current to a protective relay system. Electrical power distribution systems may require the use of a variety of circuit condition monitoring devices to facilitate the detection and location of system malfunctions. Current transformers and current sensors are well known in the field of electronic circuit breakers, providing the general function of powering the electronics within the circuit breaker trip unit and sensing the circuit current within the protected circuit. Ground fault circuit breakers for alternating current distribution circuits are commonly used to protect people against dangerous shocks due to line-to-ground current flow through someone's body. Ground fault circuit breakers must be able to detect current flow between line conductors and ground at current levels. Upon detection of such a ground fault current, the contacts of the circuit breaker are opened to reenergize the circuit. Current transformers are an integral part of ground fault circuit breakers. Current transformer assemblies are often positioned between the line side of a trip unit of a circuit breaker and the load side in order to monitor the current there between. Current transformers in electrical substations measure the system currents at predetermined measuring points of the switchgear with a certain measurement inaccuracy. The measuring points are typically located at all incoming and outgoing lines and possibly also within the system, e.g. for the bus bar protection. The current measurement signals are used for protective functions, for monitoring the substation, for calculating performance data for operating purposes or for consumption billing and for the representation on a display. The output of the current transformer provides a representation of the current flowing through the assembly that is being monitored. Associated monitoring and control instrumentation in combination with the current transformer may provide critical system functions such as overload protection and power usage monitoring.

Contacts of a current transformer

Current transformer




Capacitor Voltage Transformer:
This is basically used for communication between the sub-station and sub-station we know that capacitor is a short circuit one for the high frequency signals and the signals used for communication purpose are of high frequency type .one end of CVT connected to the feeder and second one is connected to the controlling room for the transmission of the communication signals this cannot interrupts the flow of power from the feeder
Wave trap:

We know the working of the CVT but while we are using high frequency waves for the communication purpose if that high frequency signals are enters in to the bus system it may damages the equipment why because all the equipments are manufactured for 50Hz frequency only. For that we have to protect over system for that we need WAVE TRAP it works on the principle of Inductor, we know that for high frequencies Inductor is a open circuit it not transmits the power from it , if any high frequency signal is comes to wards the sub station it passes through CVT only not through the entire system why because presence of WAVE TRAP after the CVT.


Capacitor voltage transformer wave trap



Three Phase Transformers:
Three phase transformers are used throughout industry to change values of three phase voltage and current. Since three phase power is the most common way in which power is produced, transmitted, a used, an understanding of how three phase transformer connections are made is essential. In this section it will discuss different types of three phase transformers connections, and present examples of how values of voltage and current for these connections are computed.
Three Phase Transformer Construction:
A three phase transformer is constructed by winding three single phase transformers on a single core. These transformers are put into an enclosure which is then filled with dielectric oil. The dielectric oil performs several functions. Since it is a dielectric, a nonconductor of electricity, it provides electrical insulation between the windings and the case. It is also used to help provide cooling and to prevent the formation of moisture, which can deteriorate the winding insulation.
Three-Phase Transformer Connections:
There are only 4 possible transformer combinations:
1. Delta to Delta - use: industrial applications
2. Delta to Wye - use : most common; commercial and industrial
3. Wye to Delta - use : high voltage transmissions
4. Wye to Wye - use: rare, don't use causes harmonics and balancing problems.
Three-phase transformers are connected in delta or Wye configurations. A Wye-delta transformer has its primary winding connected in a Wye and its secondary winding connected in a delta (see figure 1-1). A delta-Wye transformer has its primary winding connected in delta and its secondary winding connected in a Wye (see figure 1-2).

Fig 1.1

Fig 1.2
Delta Connections:
A delta system is a good short-distance distribution system. It is used for neighborhood and small commercial loads close to the supplying substation. Only one voltage is available between any two wires in a delta system. The delta system can be illustrated by a simple triangle. A wire from each point of the triangle would represent a three-phase, three-wire delta system. The voltage would be the same between any two wires (see figure 1-3).

Fig 1.3
Wye Connections:
In a Wye system the voltage between any two wires will always give the same amount of voltage on a three phase system. However, the voltage between any one of the phase conductors (X1, X2, and X3) and the neutral (X0) will be less than the power conductors. For example, if the voltage between the power conductors of any two phases of a three wire system is 208v, then the voltage from any phase conductor to ground will be 120v. This is due to the square root of three phase power. In a Wye system, the voltage between any two power conductors will always be 1.732 (which is the square root of 3) times the voltage between the neutral and any one of the power phase conductors. The phase-to-ground voltage can be found by dividing the phase-to-phase voltage by 1.732

Fig 1.4
Connecting Single-Phase Transformers into a Three-Phase Bank:
If three phase transformation is need and a three phase transformer of the proper size and turns ratio is not available, three single phase transformers can be connected to form a three phase bank. When three single phase transformers are used to make a three phase transformer bank, their primary and secondary windings are connected in a Wye or delta connection. The three transformer windings in figure 1-5 are labeled H1 and the other end is labeled H2. One end of each secondary lead is labeled X1 and the other end is labeled X2.

Fig 1.5
Figure 1-6 shows three single phase transformers labeled A, B, and C. The primary leads of each transformer are labeled H1 and H2 and the secondary leads are labeled X1 and X2. The schematic diagram of figure 1-5 will be used to connect the three single phase transformers into a three phase Wye-delta connection as shown in figure 1-7.



Fig 1.7
The primary winding will be tied into a Wye connection first. The schematic in figure 1-5 shows, that the H2 leads of the three primary windings are connected together, and the H1 lead of each winding is open for connection to the incoming power line. Notice in figure 1-7 that the H2 leads of the primary windings are connected together, and the H1 lead of each winding has been connected to the incoming primary power line.
Figure 1-5 shows that the X1 lead of the transformer A is connected to the X2 lead of transformer c. Notice that this same connection has been made in figure 1-7. The X1 lead of transformer B is connected to X1, lead of transformer A, and the X1 lead of transformer B is connected to X2 lead of transformer A, and the X1 lead of transformer C is connected to X2 lead of transformer B. The load is connected to the points of the delta connection.
Open Delta Connection:
The open delta transformer connection can be made with only two transformers instead of three (figure 1-8). This connection is often used when the amount of three phase power needed is not excessive, such as a small business. It should be noted that the output power of an open delta connection is only 87% of the rated power of the two transformers. For example, assume two transformers, each having a capacity of 25 kVA, are connected in an open delta connection. The total output power of this connection is 43.5 kVA (50 kVA x 0.87 = 43.5 kVA).

Fig 1.8
Another figure given for this calculation is 58%. This percentage assumes a closed delta bank containing 3 transformers. If three 25 kVA transformers were connected to form a closed delta connection, the total output would be 75 kVA (3 x 25 = 75 kVA). If one of these transformers were removed and the transformer bank operated as an open delta connection, the output power would be reduced to 58% of its original capacity of 75 kVA. The output capacity of the open delta bank is 43.5 kVA (75 kVA x .58% = 43.5 kVA).
The voltage and current values of an open delta connection are computed in the same manner as a standard delta-delta connection when three transformers are employed. The voltage and current rules for a delta connection must be used when determining line and phase values of voltage current.
Closing a Delta:
When closing a delta system, connections should be checked for proper polarity before making the final connection and applying power. If the phase winding of one transformer is reversed, an extremely high current will flow when power is applied. Proper phasing can be checked with a voltmeter at delta opening. If power is applied to the transformer bank before the delta connection is closed, the voltmeter should indicate 0 volts. If one phase winding has been reversed, however, the voltmeter will indicate double the amount of voltage.
It should be noted that a voltmeter is a high impedance device. It is not unusual for a voltmeter to indicate some amount of voltage before the delta is closed, especially if the primary has been connected as a Wye and the secondary as a delta. When this is the case, the voltmeter will generally indicate close to the normal output voltage if the connection is correct and double the output voltage if the connection is incorrect.
Over current Protection for the Primary:
Electrical Code Article 450-3(b) states that each transformer 600 volts, nominal or less, shall be protected by an individual over current device on the primary side, rated or set at not more than 125% of the rated primary current of the transformer. Where the primary current of a transformer is 9 amps or more and 125% of this current does not correspond to a standard rating of a fuse or nonadjustable circuit breaker, the next higher standard rating shall be permitted. Where the primary current is less than 9 amps, an over current device rated or set at not more than 167% of the primary current shall be permitted. Where the primary current is less than 2 amps, an over current device rated or set at not more than 300% shall be permitted.
Example #1:
What size fuses is needed on the primary side to protect a 3 phase 480v to 208v 112.5 kVA transformer?
* Important when dealing with 3 phase applications always use 1.732 (square root of 3).
To solve: P / I x E
112.5 kVA X 1000 = 112500 VA
112500 VA divided by 831 (480 x 1.732) = 135.4 amps
Since the transformer is more than 9 amps you have to use 125 %.
135.4 X 1.25 = 169 amps
Answer: 175 amps use (the next higher standard, Electrical Code 240-6).
Example #2:
What size breaker is needed on the primary side to protect a 3 phase 208v to 480v 3kVA transformer?
To solve: P / I x E
3kVA X 1000 = 3000 VA
3000 VA divided by 360 (208 x 1.732) = 8.3 amps
Since the transformer is 9 amps or less you have to use 167%.
8.3 X 1.67 = 13.8 amps
Answer: 15 amp breaker (preferably a 20 amp breaker)
Electrical Code Article 450-3(b)(2) states if a transformer 600 v, nominal, or less, having a an over current device on the secondary side rated or set at not more than 125% of the rated secondary current of the transformer shall not be required to have an individual over current device on the primary side if the primary feeder over current device is rated or set at a current value not more than 250% of the rated primary current of the transformer.


Over current Protection for the Secondary:
Electrical Code Article 450-3(b)(2) states that a transformer 600 v, nominal, or less, shall be protected by an individual over current device on the secondary side, rated or set at not more than 125% of the rated secondary current of the transformer. Where the secondary current of a transformer is 9 amps or more and 125% of this current does not correspond to a standard rating of a fuse or nonadjustable circuit breaker, the next higher standard rating shall be permitted. Where the secondary current is less than 9 amps, an over current device rated or set at not more than 167% of the secondary current shall be permitted.
Example:
What size breaker is needed on the secondary side to protect a 3 phase 480v/208v 112.5 kVA transformer?
To solve: P / I x E
112.5 kVA x 1000 = 112500 VA
112500 divided by 360 (208 x 1.732) = 312.5 amps
312.5 X 1.25 = 390.6 amps
Answer: 400 amp breaker

Internal Connection of 3-phase Transformer

Relays:
An electric current through a conductor will produce a magnetic field at right angles to the direction of electron flow. If that conductor is wrapped into a coil shape, the magnetic field produced will be oriented along the length of the coil. The greater the current, the greater the strength of the magnetic field, all other factors being equal:

Inductors react against changes in current because of the energy stored in this magnetic field. When we construct a transformer from two inductor coils around a common iron core, we use this field to transfer energy from one coil to the other. However, there are simpler and more direct uses for electromagnetic fields than the applications we've seen with inductors and transformers. The magnetic field produced by a coil of current-carrying wire can be used to exert a mechanical force on any magnetic object, just as we can use a permanent magnet to attract magnetic objects, except that this magnet (formed by the coil) can be turned on or off by switching the current on or off through the coil.
If we place a magnetic object near such a coil for the purpose of making that object move when we energize the coil with electric current, we have what is called a solenoid. The movable magnetic object is called an armature, and most armatures can be moved with either direct current (DC) or alternating current (AC) energizing the coil. The polarity of the magnetic field is irrelevant for the purpose of attracting an iron armature. Solenoids can be used to electrically open door latches, open or shut valves, move robotic limbs, and even actuate electric switch mechanisms. However, if a solenoid is used to actuate a set of switch contacts, we have a device so useful it deserves its own name: the relay.
Relays are extremely useful when we have a need to control a large amount of current and/or voltage with a small electrical signal. The relay coil which produces the magnetic field may only consume fractions of a watt of power, while the contacts closed or opened by that magnetic field may be able to conduct hundreds of times that amount of power to a load. In effect, a relay acts as a binary (on or off) amplifier.
Just as with transistors, the relay's ability to control one electrical signal with another finds application in the construction of logic functions. This topic will be covered in greater detail in another lesson. For now, the relay's "amplifying" ability will be explored.

In the above schematic, the relay's coil is energized by the low-voltage (12 VDC) source, while the single-pole, single-throw (SPST) contact interrupts the high-voltage (480 VAC) circuit. It is quite likely that the current required to energize the relay coil will be hundreds of times less than the current rating of the contact. Typical relay coil currents are well below 1 amp, while typical contact ratings for industrial relays are at least 10 amps.
One relay coil/armature assembly may be used to actuate more than one set of contacts. Those contacts may be normally-open, normally-closed, or any combination of the two. As with switches, the "normal" state of a relay's contacts is that state when the coil is de-energized, just as you would find the relay sitting on a shelf, not connected to any circuit.
Relay contacts may be open-air pads of metal alloy, mercury tubes, or even magnetic reeds, just as with other types of switches. The choice of contacts in a relay depends on the same factors which dictate contact choice in other types of switches. Open-air contacts are the best for high-current applications, but their tendency to corrode and spark may cause problems in some industrial environments. Mercury and reed contacts are sparkles and won't corrode, but they tend to be limited in current-carrying capacity.
Shown here are three small relays (about two inches in height, each), installed on a panel as part of an electrical control system at a municipal water treatment plant:

The relay units shown here are called "octal-base," because they plug into matching sockets, the electrical connections secured via eight metal pins on the relay bottom. The screw terminal connections you see in the photograph where wires connect to the relays are actually part of the socket assembly, into which each relay is plugged. This type of construction facilitates easy removal and replacement of the relay(s) in the event of failure.
Aside from the ability to allow a relatively small electric signal to switch a relatively large electric signal, relays also offer electrical isolation between coil and contact circuits. This means that the coil circuit and contact circuit(s) are electrically insulated from one another. One circuit may be DC and the other AC (such as in the example circuit shown earlier), and/or they may be at completely different voltage levels, across the connections or from connections to ground.
While relays are essentially binary devices, either being completely on or completely off, there are operating conditions where their state may be indeterminate, just as with semiconductor logic gates. In order for a relay to positively "pull in" the armature to actuate the contact(s), there must be a certain minimum amount of current through the coil. This minimum amount is called the pull-in current, and it is analogous to the minimum input voltage that a logic gate requires to guarantee a "high" state (typically 2 Volts for TTL, 3.5 Volts for CMOS). Once the armature is pulled closer to the coil's center, however, it takes less magnetic field flux (fewer coils current) to hold it there. Therefore, the coil current must drop below a value significantly lower than the pull-in current before the armature "drops out" to its spring-loaded position and the contacts resume their normal state. This current level is called the drop-out current, and it is analogous to the maximum input voltage that a logic gate input will allow to guarantee a "low" state (typically 0.8 Volts for TTL, 1.5 Volts for CMOS).
The hysterics, or difference between pull-in and drop-out currents, results in operation that is similar to a Schmitt trigger logic gate. Pull-in and drop-out currents (and voltages) vary widely from relay to relay, and are specified by the manufacturer.


Inverse time directional over current relay

Battery operation

1. (a) The ampere hour capacity of 220V batteries at smaller sub-station shall be 80.
(b) The same EHT sub-station shall be 200
(c) Batteries with 300 Amps hour capacity shall be used only at power house or sub-stations where solenoid closing of circuit breaker is in use.

2. the trickle charging rate shall be
“Amp hour capacity X 2/24x 100 pulse regular discharge in amps”
3. The boost charger rate shall not exceed Amp. Hour capacity divided by ten.
4. The individual cell voltage shall not go down below 2.1 volts
5. The specific gravity should not differ by more than 30 points between cells in the same battery maximum and minimum. Where the difference is more; electrolyte should be diluted by adding distilled water in cells with higher specific gravity thus narrowing down the difference and all cells in the battery given a boost charge.
6. Usage of alkali cells and acid cells in the same sub-station should be avoided to avert inadvertent mix up of electrolyte usage of accessories of one with other.
7. Leakage induction lamps should be compulsory connected to the charges panel for continuous indication of healthiness.
8. Every D.C Circuit takes ff should be through protective fuses (H.R.C) or m.c.bs.
9. (i) Once in a day A.C. supply to charges should be switched off and D.C. voltage measured and noted.
(ii) In that condition no A.C supply to charger, the duty performance of the battery by closing or tripping of a relatively un-important breaker is to be ensured. Where availability of D.C voltage is no index of healthiness of battery.
(iii) A.C supply to charger is to charger is to be restored immediately after this test.

10. Certain charger panels have “switch off” arrangement whenever A.C supply fails. There should be switched on after each restoration of supply.
11. Leakages in D.C circuitry should be attended on top priority first by sectionalisation, then by isolation and finally be rectification.










COMPONENT RATINGS

Capacitor Voltage Transformer (CVT)
S.NO Item Rating
1 Rated Voltage 220/3 KV
2 O/P Max 750 VA
3 Highest system voltage 245/ 3 KV
4 Insulation level 460/1050 KV
5 Frequency 50Hz
6 Primary capacitance C1 4840 p.F+10%,-5%
7 Secondary capacitance C2 48400 p.F+10%,-5%


Isolator
S.NO Item Rating
1 Rated voltage 245 KV
2 Rated current 800 Amps
3 Short time current 3 sec – 40 KAmps
4 Impulse 1050 KV

Potential Transformer
S.NO Item Rating
1 NSV 132 KV
2 HSV 145 KV
3 Phase 1ø
4 Frequency 50 Hz
5 Oil Qty. 120 lts.
6 Ratio 132/ 3 KV
7 Insulation level 275/650 KV
8 Weight 500 Kgs

Current Transformer
S.NO Item Rating
1 Rated Voltage 245 KV
2 Frequency 50 Hz
3 Insulation Level 460/1050 Kvp
4 S.T current 40/1 sec
5 Rated Primary Current 1000 Amps

Circuit breaker
S.NO Item Rating
1 Rated lightning impulse with stand voltage 1050 Kvp
2 Rated short circuit breaking current 40 KA
3 Rated operating pressure 15 Kg/cm²-g
4 Rated duration of short circuit current 40 KA for 3sec
5 Rated line charging breaking current 125 Amps
6 Rated voltage 245 KV
7 Rated frequency 50 Hz
8 Rated normal current 2500 Amps

Rated operating sequence of Circuit breaker
O – 0.3 sec – C
C O – 3 min – C O

Transformer Rating

S.NO Item(ONAF) H.V L.V TERT.
1 Rated Power 1,00,000 KVA 1,00,000 KVA 33,333 KVA
2 Rated no-load voltage 2,20,000 KV 132000 KV 11,000 KV
3 Rated Line current 262.44 A 437.4 A 1749.5 A
S.NO Item(ONAN) H.V L.V TERT.
1 Rated Power 60,000 KVA 60,000 KVA 20,000 KVA
2 Rated no-load voltage 2,20,000 KV 132000 KV 11,000 KV
3 Rated Line current 157.5 A 262.4 A 1045.7 A















MAINTENANCE SCHEDULE OF COMPONENTS

I. MAINTENANCE SCHEDULE OF POWER TRANSFORMERS
S.NO Item of Maintenance Periodicity Remarks
1 Checking the color of silicagel in the breather and replacement or reconditioning if color changes from blue to pink say about 50% of the total quantity. Checking up the oil level of the oil seal (to be up to the level marked in the cup ) Daily
2 Checking of oil level in a) main conservator b)OLTC conservator c)bushings and examining for leaks of oil Daily
3 Visual check for over heating if any at terminals connections and checking for unusual internal noises Daily each shift
4 Checking for noise and vibrations or an abnormality from oil pumps and cooling fans Daily
5 Checking up of oil and winding temperature Hourly
6 Checking for pressure relief explosion vent diaphragm from cracks Daily
6(a) Forced cooling system: checking for leakage of water in to cooler(forced cooling system by oil pumps) Daily
7 Cleaning of bushings. Inspect for any cracks or chippings of the porcelain. Monthly
8 Ensuring that oil comes out when air releases valve is opened (of the main tank) quarterly
9 Measuring insulation resistance of windings with an appropriate measure (note down oil temp.) quarterly
10(a) Checking up of winding and oil temperature Bucholtz and surge relay and oil level trips for correct operation quarterly
10(b) Checking up of auto starting of pumps and cooling fans quarterly
11 OLTC oil test for BDV and moisture content. Ensure oil level in OLTC quarterly
12 Main tank oil testing for BDV and moisture content Half yearly
13 a) Checking of Bucholtz relay for any gas collection and testing the gas collected.
b) Checking of operation of Bucholtz relay by air injection.
c) Noting the oil level in the inspection glass or Bucholtz relay, arresting. Quarterly of during fault . Half yearly or during shut down Monthly or as when shut down availed
14 Tap changer
a)lubricating/greasing all moving parts quarterly
15 Checking of all connections on the transformer for tightness such as bushings, tank earth connection ,etc. quarterly
16 Forced cooling system
a)measure testing of motors(pump) lubricating the mechanical parts and cooling fans yearly
17 Oil level in oil seal and replacement quarterly
18 Testing of oil for dissolved gas analysis for 100 MVA and above. If the results show abnormality ,frequency of DGA may be increased as per the recommendations of R&D Half yearly Other transformers such as 50 MVA,31.5 MVA and 10/16 MVA Trs. Which are in service in more than 5 years.
19 Pressure testing of oil coolers Half yearly
20 Testing of motors, pumps and calibrating pressure gauges, etc. Half yearly
21 Over heating of pumps , motors and cooling fans Yearly or as and when necessary
22 Testing of oil in main tank for acidity, tan delta, IFT and resistivity. yearly
23 Bushing testing for tan delta yearly
24 Calibration of oil and winding temperature indicator yearly
25 Measurement of excitation current at low voltage at normal tap and extreme tap yearly
26 Measurement of D.C winding resistance yearly
27 Ratio test of all taps yearly
28 Checking of bushing CT for WTI for correct ratio yearly
29 OLTC
a)inspection of contacts in diverter Depending upon the no. of operations as recommended by the manufacturer
b)driving mechanism visual checking up , overhaulting if necessary yearly
30 a)tap position indicator
b)checking for proper working of remote tap position indicator, remote winding test indicator yearly
31 Opening of Bucholtz relay for alarm and trip by draining of oil and injection of air with pump yearly
32 Checking for leakage in air cell yearly
33 Oil level in thermometer pocket top up if required yearly
34 Bushing partial discharge test and capacitance One in 5 years
35 General overhaul Once in 10 years
a)core tightening
b)De-sludging/washing of windings
36 Filtration of oil Whenever oil test results are below permissible limits





II. Maintenance schedule for SF6 circuit breaker

S.NO Item of maintenance period Remarks
1 SF6 density monitoring Daily in each shift If appreciable change is observed compared to earlier readings, leakage check to be carried out
2 Measurement of humidity of SF6 gas Yearly Use dew point meter. If deviation from standard norms is observed, the evacuation ,recycling and refilling of SF6 gas is to be carried out
3 Acid concentration measurement in SF6 gas Yearly
4 Air content measurement in SF6 gas Yearly
5 SF6 gas leakage test Yearly Check the complete breaker for SF6 gas leakage including the seal assembly of driving rod .if any leakage is detected the same should be arrested in consultation with manufacturer and after arresting the leakage of SF6 gas pressure is to be brought up to rated pressure by topping up SF6 gas
6 a. checking of insulation of control circuit wiring Yearly Minimum 2 Mega ohms with a 500v megger
b. measurement of insulation resistance across contacts (with breaker off)and pole to earth with breaker on To be done by 2.5 kv megger or above
7 Evaluation, recycling and refilling of SF6 gas 5 Years This mat be done whenever the humidity in SF6 gas excess of permissible value
8 Checking of Br. Level with spirit level Yearly









III. Maintenance schedule for Lightning Arrestors

S.NO Item of maintenance Period Remarks
1 Visual inspection Daily If chipping / crack in the insulators is observed replacement action to be taken
2 Surge counter reading Daily -
3 Leakage current reading and analysis Once for shift Should be in green zone
4 Earth resistance Quarterly -
5 Leakage current analysis Quarterly For gap less lightening arrestors only
6 IR value Yearly Compare results with those obtained previously
7 Connections Yearly -
8 Calibration of leakage current ammeter Yearly -
9 Cleaning of insulators Yearly -






IV. Current transformers Maintenance

Current transformers require little attention to except to see that their secondary circuits are completed before the switchgear is commissioned. An open circuit on the circuit side may result in a relatively high voltage due to the whole of the primary ampere turns. If the primary current is nearer to the rated value, the core will become saturated resulting in a flat topped flux wave. This in turn will produce a high peaked secondary include voltage wave because of the accelerated rate of flux change. The resulting high voltage may be harmful to equipment and personnel.

The secondary burden of CTs will depend not only on the instrument and relay coils but also on the length and cross-section of the leads between the switchgear and the control panels. Long control cable runs may require more cores of a multi-core CT to be put in parallel or leads of greater cross-section.


Maintenance schedule for Current Transformers
S.NO Item of maintenance Periodicity Remarks
1 Visual check
(Porcelain, unusual noise, discoloration of terminal etc.) Daily
2 Oil leakage Daily Visual check only
3 Oil level Monthly To be recorded
4 Space heater and lighting of marshalling box Monthly Operation check
5 Cleaning of marshalling box and junction boxes Half-yearly
6 All connections Yearly Check for looseness
7 IR value Yearly Compare with pre commissioning test results
8 Earth resistance Yearly
9 Tan delta test Yearly Compare with factory test results
10 Cleaning of insulator Yearly
11 DGA oil sample including BDV and moisture content 4 to 5 days after first changing Oil sample to be taken after obtaining permission from manufacturers


V. Potential Transformer Maintenance

EHV PT’s are normally supplied filled with oil and should not required drying out. Small units of lower voltage may require on filling on site and may there fore have absorbed moisture in transit. Where this is suspected, it is advisable to apply heat to the units to bring up the IR value before filling with oil. When dry the IR value of the windings will usually be found to be between 100 and 1000 Mega ohm. When in service the temperature rise is not so high so that the fall in IR value due to this is not of significance.

PT fuses where provided should be examined before commissioning. Some 11KV PTs are provide with fuses on the HV side to isolate the system in case of a fault in PT. it is not intended to protect the PT. A current limiting resistance is provided in such a case to limit fault current to a value with I the rupturing capacity of fuse. LV fuses provide protection to transformer against short circuits on the LV side. It is not desirable that either the HV or LV fosse should blow prematurely as that will affect metering and protective relaying and also any control circuits. An important precautions PT circuit is to verify that there are no parallel circuits on the LV side which could energize another PT inadvertently.


VI. Maintenance for CVT’S

S.NO Item of Maintenance Period Remarks
1 Oil leakage Daily Visual checks
2 Catering sound Daily If present, measure capacitance and compare with the design value
3 Oil level Monthly To be recorded
4 Earthing of PLCC link(in case it is not being used) Monthly -
5 H.F. Bushing Monthly Check for any breaking
6 Spartik gap cleaning Yearly If accessible
7 Cleaning of insulator Yearly -
8 Capacitance of maintenance Yearly Compare with the factory test results/designed value
9 Earthpit maintenance Yearly -
VII. Maintenance Schedule for Isolators

S.NO Item of Maintenance Period Remarks
1 Visual inspection Daily Visual checking for cleanliness of insulation ; proper alignment of contact arm blades , any abnormal noise and arcing will be carried out
2 a)Main contacts checking including earth switch high voltage terminal tightening contact resistance checking including cleaning and lubrication of main contacts Yearly Opportunity of shut down should be available of whenever possible, the checks and measurements should be performed without disturbing the connections
b) Main and main contacts checking of (i) alignment (ii) bolds. Nuts, washers, cotter pins, terminal connectors, are in place and tight. Examine the contacts, Yearly
3 Operating mechanism
Checking of
- Linkages including transmission
- Stopper bolt
- Limit switch setting
- Greasing of drive
- Greasing of auxiliary switch contacts
- Position and tightening of cable glands (before start of the rainy season)

Quarterly Check the isolator operation. If the operating efforts appear to be excessive check the rotor bearings, all the linkages for the proper operation
4 Insulators MOM box cleaning and lubrication of operating mechanism hinges locks, joints on levers, etc, check all mounting booth for tightness Yearly Opportunity of shut down should be availed of whenever possible
5 Visual check of auxiliary contacts Quarterly The check should be done for any arcing marks on contacts, burning of switch housing etc.
6 Checking for proper functioning of space heaters, illumination etc. Quarterly
7 Checking of Electrical/Mechanical inter locks Yearly
8 Earth-switch checking of
- Alignment of earth blade
- Contact cleanliness
- Correct operation of earth switch
- Aluminum/copper flexible (if provided) Yearly
9 Checking for earth connections Yearly

MAINTENANCE SCHEDULE FOR BATTERIES/BATTERY CHARGERS/DC DISTRIBUTION SYSTEM

S.NO Item of maintenance Period Remarks
1 Cleaning of battery surface joints and all connections Daily To be done on rotation so as to cover all the cells in 10 days
2 Specific gravity measurement of pilot cell Daily -do-
3 Voltage reading of pilot cell Daily -do-
4 Visual checking of battery room ventilation of lighting Daily -
5 Checking of electrical connections for tightness Weekly -
6 Application of petroleum jelly to joints and cell connections Weekly -
7 Checking electrolyte level and topping up with DM water Weekly -
8 Shallow discharge (10 hour rate) and recharging Yearly The discharge to be done for a specific period
9 Readjustment of specific gravity Yearly -
10 Checking of healthy ness of AC supply to the charger Daily -
11 Checking of float charging current (DC) Daily -
12 Output voltage check Daily -
13 Charger cleaning with blower Fortnightly -
14 Checking control chords Yearly -
15 Complete overhaul Yearly -
16 Checking for DC earth fault Daily Earth fault to be attended immediately
17 Checking of emergency lights Daily Fused lights to be replaced immediately
18 Auto-start and running up of BG set Daily -
19 Checking DC distribution
i) external Daily -
ii) internal Quarterly -
20 Checking of all electrical connections of charger panel for tightness and cleaning Quarterly -
21 Calibration of all meters and relays in the charger and the DCBs Yearly -


















CONCLUSION

The periodic supervision and maintenance improves the life time of equipment. Sometimes the defective equipment may be detected by comparing the variations in parameters, such as IR values, tanð values and other operating values. The break down time and damages to the nearby equipment may be avoided by replacing such defective equipment with in the time.

So that reliable & uninterrupted supply will be provided to the consumer.