Chapter 4

Sub Station Engineering

4.1 Site selection for EHV substation

Substations play a critical role in an integrated power system for proper load

management, enhancing reliability & security of power supply. This is true for

all stations ranging from 765 kV grid station to a 33 kV rural distribution

centre. Size and location of substation has a direct bearing on its economy,

design, execution and subsequent O&M. It is often experienced that a

judicious site selection of a substation is pivotal for smooth project

implementation, reduces time & cost over runs and increases its service life.

With increasing constraints of transmission line corridors, difficulty in

availability of land due to urbanization and economic development,

emergence of stringent social & environmental regulations and public

awareness, the task of site selection for a substation has become more and

more complex.

The following factors often govern finalization of an optimal site for any

substation.

Technical

Physical

Infrastructural

Social & Environmental

Commercial

4.1.1 Technical Factors

Area Requirement

For deciding the area requirement of a substation, its voltage level(s),

number of feeders, requirements of step-up/ down transformers &

reactors, infrastructural facilities like housing, associated paraphernalia

etc, for present and future expansion on a 10-15 year scenario are to

be planned. After such an assessment, a first estimate of the area is to

be made on the basis of existing practices of the Utility.

For a typical 400/220 kV Substation, the area requirement for

switchyard is around 30 to 35 acres with I-type layout for 400 kV

system and double main and transfer bus arrangement for 220 kV

system.

Corridors for line, aeronautics and forest (or any other civic, military or

infrastructural facility for that matter) are important aspects for the

feasibility of the substation location. It is prudent to locate sites around

existing line corridors. Sometimes such locations simply do not exist

and a suitable choice will be confined to locations which have only

some of the above characteristics.

Pollution

Substation location should be away from the polluted area as far as

possible. The small particles (pollutants) may deposit on the insulators

due to the pollution. As pollution levels increase, the insulator creepage

distance of equipments will also increase, which may increase the cost

of the equipments. In extreme cases, in heavily polluted area cleaning

facilities or the use of protective products may be necessary. This may

cause higher cost towards O&M. Saline and other types of industrial

pollution cause corrosion in supporting structures and protective

coating may be required. The risk of failure of equipments increases

with the pollution level.

In case there is no choice but to select a substation in a polluted area,

the alternate technology like GIS/ indoor substation options needs to

be examined. This shall of course reflect on the cost of the substation.

4.1.2 Physical Features

Following factors need to be reviewed for site selection:

Topography

Geology

Geography

Topography

Standardization is being adopted by utilities for symmetry, reduced

inventory, reduced engineering and construction time. To achieve this

objective through standardization of supporting structures, approach to

equipment, uniform equipment terminal heights and judicious space

utilization, it is advisable to level the substation land. Uniform gradual

slopes must be provided for proper drainage. Wherever, high cost of

leveling and retaining walls is anticipated, various terraces can be

formed. Generally for deciding the level of substation, the flood level of

that area must be known and substation to be located on the level

around 0.5 m higher than highest recorded flood level. It is preferable

to select the site as even as possible to save time in leveling and to

minimize not only the cost of leveling but also cost of civil foundation

buildings.

In such areas leveling cost may force the reduction of substation size

which means a review of substation schemes and layouts.

Geological

The type of soil & its bearing capacity should be investigated and the

soil should be suitable of construction of roads and foundation. A high

water level may require the construction of drainage facilities which

would increase the cost and cause construction delay. The foundations

may also call for special kind of treatment. Hence cost of substation

may vary depending upon nature of soil. Similarly, if the natural soil has

a high resistivity, the earth mat becomes costly accordingly.

Geography

The location of substation should be selected away from the hazardous

area like mines, land slides, flood prone areas. They should be away

from airports and aeronautic corridors as there are usually restrictions

on the maximum height of structures and due to possible disturbance

on navigation equipment. The orientation of substations should be

selected keeping in view the line corridors orientations.

4.1.3 Infrastructural Factors

While identifying a site for a substation, availability of following

infrastructural facilities must be examined so that personnel working

and located in the substation may not face any problem during

execution and subsequent O&M

- Easy Access

- Amenities Availability

- Reliable power & water supply

Substation site should be preferred as near a city/town as possible.

Though due to transmission line corridors it may also not be always

feasible. There has been appropriate mix of proximity to an urban area

and openness for future line corridors. Further, efforts should be made

to locate the substation near a rail head for transportation of heavy

equipments like transformers and reactors. In case of access

constraints for three phase transformers and reactors, the single phase

transformers and reactors may have to be insisted.

Other amenities such as education, medical, communication facilities

etc should be reasonably available. The availability of reliable power

supplies for substation auxiliaries, for residential and construction

purpose should be examined. The water should be available be

construction of substation as well as for drinking purpose.

4.1.4 Social & Environmental Aspects

Following social aspects should be considered while selecting the site:

- Habitation

- Govt. or Private land

- Forest encroachment

- Landscaping

With more awareness amongst general public and strict laws on land

acquisition, resettlement of PAPs (Project Affected Persons), a greater

attention needs to be accorded to this aspect. It is common to see

projects languishing for years to settle related issues. It would be

essential to consult public at various stages of land identification and

acquisition to avoid disputes at a later stage. It would be wise to

develop an organizational policy dining procedures, R&R issues to

establish a transparency. This would obviate problems from PAPs to a

large extent. This any way is a prerequisite for availing multi-lateral

assistance. While selecting a site, minimum number of families should

be disturbed. It is preferable to go for a govt. land rather than private

land as the process may take less time. In case of going for private

land, we may ensure that there is minimum number of land owners so

that acquisition, negotiations could be manageable.

Forest land should be avoided unless unavoidable. Out of various

options available for locating substation, the choice which involves

minimum forest encroachment by lines should be preferred. Trees,

bushes along the substation periphery and use of natural soil instead of

gravel (if acceptable from touch and step potential point of view) may

help to improve environmental aspects. Low noise transformers and

reactors should be installed wherever station is near residential areas.

4.1.5 Commercial aspects

While selecting substation site, cost of substation considering land cost

& its development needs to be examined with respect to the cost of

transmission lines. In case of bulk power handling substations, it would

also be appropriate to take into consideration requirements of

distribution centers.

4.2 Types of substation

4.2.1 General

Substations may be categorized as distribution substations,

transmission substations, switching substations, or any combination

thereof. One design tendency is to reduce costs by reducing the

number of substations and taking advantage of economies of scale.

Conversely, practical system design and reliability considerations tend

to include many substations. One function of system studies is to

balance these two viewpoints.

4.2.2 Distribution Substations

A distribution substation is a combination of switching, controlling, and

voltage step-down equipment arranged to reduce subtransmission

voltage to primary distribution voltage for residential, farm, commercial,

and industrial loads. Rural distribution substation capacities vary.

Substations generally include one l.5 MVA to three 5 MVA

transformers. These substations may be supplied radially, tapped from

a subtransmission line, or may have two sources of supply.

4.2.3 Transmission Substations

A transmission substation is a combination of switching, controlling,

and voltage step-down equipment arranged to reduce transmission

voltage to subtransmission voltage for distribution of electrical energy

to distribution substations. Transmission substations frequently have

two or more large transformers. Transmission substations function as

bulk power distribution centers, and their importance in the system

often justifies bus and switching arrangements that are much more

elaborate than distribution substations.

4.2.4 Switching Substations

A switching substation is a combination of switching and controlling

equipment arranged to provide circuit protection and system switching

flexibility. Flexible switching arrangements in a transmission network

can aid in maintaining reliable service under certain abnormal or

maintenance conditions.

4.3 Substation Single Line Diagram

In single line diagram of a substation, the current ratings for bus bar and all

the feeder equipment are decided based on possible current flow (i.e. Kirchoff

law of summation of currents) through the feeder after deciding the suitable

bus switching arrangement as described later in this chapter. Normal current

rating as well as short time current ratings and the insulation levels for all the

equipment are marked up in the single line diagram.

4.3.1 Bay numbering and bay equipment identification

A bay is line feeder module or transformer feeder module or bus

coupler or a bus transfer module which is controlled by a breaker and

number of isolators. As there are many circuit breakers, isolators,

current transformers, capacitive voltage transformers, surge arresters,

wave traps etc., each equipment are given a code for identification

which is normally the bay number followed by equipment code. For

example, there are four isolators (one connected to Bus –A, one

connected to Bus-B, one connected to Bus –C and one connected to

line) in a line bay with double main and transfer scheme, one breaker,

one CT, one CVT, one surge arrester. The equipment identification can

be done as 1-52 for breaker, 1-89A for isolator connected with Bus-A,

1-89B for isolator connected with Bus-B, 1-89C for isolator connected

with Bus-C, 1-89L for line isolator, 1-CT for current transformer, 1-CVT

for capacitive voltage transformer, 1-WT for wave trap and 1-LA for

surge arrester. A single line diagram with double main and transfer bus

arrangement is shown in Fig.4.1.

Fig: 4.1: Single Line Diagram (Double Main & Transfer Scheme)

4.4 Substation Layout and Structures

4.4.1 Substation Layout

General

In India different types of switching schemes and layouts have been

used for EHV substation by different utilities. With the non-availability of

desired size of land at a desired location, it has become necessary to

plan the substation layout in the available land itself irrespective of

constraints of line corridors, irregular shapes of land and other site

constraints. In spite of these site constraints, it is necessary to adopt

uniform switching scheme and layout as far as possible from operation

and maintenance point of view.

Planning Aspect

Following details are required for planning the substation layout.

Bus switching scheme to be adopted

Details of feeders requirements

Future/anticipated expansion of the substation

Available size of plot

Switching schemes are selected based on techno-economic criteria. As

per established practices breaker and half schemes have been used

world-wide for voltage level 400 kV and above because of its high

reliability, safety and system security. In 220 kV voltage level, double

main and transfer bus scheme has been considered due to economic

criteria. For 132 kV & below level, single main and transfer scheme is

generally in use.

Based on feeder’s requirement for present and future expansion,

identification of feeders is done keeping in view minimum line crossings

and compactness of the substation. In the available land, the

substation alongwith substation buildings are to be located generally at

high leveled area with respect to the surrounding area so that these are

safe even during flood situation.

Type of layout

Based on the selected switching scheme & land size, type of layout is

to be decided. For a particular bus switching scheme, different options

of layout are available. Depending upon availability of land, simple &

understandable layout of substation should be so selected that during

operation and maintenance no problem is faced at a later date.

4.4.2 Major factors deciding a layout:

Standard Factors

a) Electrical clearances

b) Electric fields & Magnetic Fields - Heights of different conductor levels

Variable Factors

a) Shape of land & feeder orientation

b) Bus bar arrangements

c) Type of isolators used

d) Type of structures used

e) Arrangement for lightning protection

f) Location of control room building, fire fighting pump house building, DG

set

g) Roads and Rail tracks

Electrical Clearances

While working out the switchyard layout, the clearances between live

parts, earthed structures should ensure the following:

a) Normal operation of the equipment and safe work of the personnel

b) If a circuit is de-energised, the safe inspection, replacement and repair

of equipments

c) Possibilities of convenient equipment haulage

To meet the above requirement, following insulating electrical clearances

as mentioned in Table: 4-1 are maintained based on flashover probabilities

in case of lighting & switching impulse voltage levels and air gap

geometry.

Table- 4.1Clearance of between phase to phase earth & different voltage level

132 kV 220 kV 400kV 765 kV

1. Minimum

Clearances

1.a) Phase to Earth

(in meters)

1.3 2.1 3.5 4.9

(conductor-structure)

6.4

(rod –structure)

1.b) Phase to

Phase

(in meters)

1.4 2.1 4.0

(conductor-conductor)

4.2

(rod –structure)

7.6

(conductor-

conductor)

9.4

(rod –structure)

1.c) Sectional

clearance

(in meters)

4.0 5.0 6.5 10.3

2. Basic Impulse

Level (KVp)

650 1050 1550 2100

3. Switching

Impulse Level

(KVp)

- - 1050 1550

Effect of electric field & magnetic field and height of different conductor

levels:

The regular influence of electric field may be harmful to 400 kV- 765 kV

switchyard staff health. Presently there is no well defined guideline in

India for the limits of electro static levels in substation. Researches

carried out in USSR had derived following (Table:4-2) limits of electric

field intensity tolerable by human beings within a period of time.

Table- 4.2 field intensity limits

Field Intensity (KV/M) Permissible duration (Minute per day)

5 Unlimited

5-10 180

10-15 90

15-20 10

20-25 5

International Non-ionizing Radiation committee of the International

Radiation Protection Association has suggested that continuous

occupational exposure the working day should be limited to 10KV/mtr.

Therefore, for safe working near charged equipment the electric field

should not be more than 10KV/mtr at 1.8 meter level. Electric field is

one of the selection criteria for bus bar levels, conductor configuration,

phase spacing etc. The limit the electric field & to maintain electrical

clearances, the following (Table: 4-3) conductor levels have been

generally considered.

Table- 4-3 conductor levels & different voltages

Voltage level First level Second level Third level

765kV 14.0m 27.0m 39.0m

400kV 8.0m 15.0m 22.0m

220kV 5.9m 11.7m 16.2m

132kV 4.6m 7.5/8.0m 10.8/12.0m

As per calculations and measurements carried out in 400 kV

substations with 8 meter ground clearance and with 6 meter phase to

phase distance, electric fields at various locations have been found to

be well within the limit of 10KV/mtr. To limit the electric fields in

substations, faraday cage can be provided with wire mesh above

equipment control cabinet at a height slightly above normal human

height to protection the operator.

4.4.3 Shape of Land and Feeder Arrangement:

Shape of land varies from site to site and each site has its own

constraint. The layout of substation should be so selected that lines

could be terminated easily with minimum crossings of lines. Feeder

allocation plays a vital role in exploiting the potentialities of a particular

bus scheme.

4.4.4 Bus Bar Arrangement:

The selection of bus bar arrangement has a great impact in deciding

the levels in the substation. Rigid type of bus bar would result low level

type of layout (i.e. equipment connection/ bus bar level and strung

cross over level) and flexibly bus bar arrangement would result high

level type layout (i.e. equipment connection level, strung bus bar level

and strung cross over level). Both types of layouts have its advantages

and disadvantages. The low level layout has following advantages:

Lesser height of gantry structures an associated lesser foundations

No overhead conductor over main equipments for ease of maintenance

Better aesthetic appearance

On the other hand, high level layout has following advantages in spite

of having high level structures and comparatively heavy foundations:

Lesser No. of structures

No. of equipments (CB, Isolators) may reduce depending upon

optimum utilization of feeders

Lesser land requirement

While comparing both type of layout, lesser no. of structures and lesser

requirement of land in high level layout, the overall cost saving due to

above and associated work like leveling, fencing, road, gravel filling,

earth mat etc. would be of the order of 20-30% compared to the cost of

low level layout.

4.4.5 Type of Isolators Used:

Following different types of isolators are available:

Horizontal Centre Break Isolator (HCB)

Double Break Isolator (DB)

Pantograph Isolator (Panto)

Vertical Break Isolator (VB)

Type of isolators has great influence in bay width and level of the

substation. Using double break type of Isolators compared to

Horizontal Centre Break Isolators, bay width can be reduced by 10-

15%. Pantograph isolators are best suited for DMT scheme (with

flexible bus arrangement) but it requires proper & careful erection of

isolator and stringing of buses. By using vertical break isolators, the

height of levels increases but vertical break isolators are more

economical for voltages more than 400 kV due to lesser length of

beam, bay width and ultimately lesser requirement of land.

Type of Structures Used:

Enclosed (П) type of structures is generally in use upto 400 kV voltage

level. But at higher level these structures become uneconomical as bay

width (beam length) increases. For 765 kV voltage levels, pie (╥) type

structures are generally in use because in these structures only phase

to earth spacing are required to be maintained.

Arrangement for Lighting Protection:

Depending upon type of lightning protection to be used i.e. by using

shield wire or separate lightning mast (LM), the height of structures

may vary. Use of shield wire adds to another level which increases the

structure height and makes the heavy foundations but no separate

space is required. On the other hand, lighting mast are better from

aesthetic point of view and also serves the purpose of holding lighting

fixtures which provides good uniform illumination in substation.

Lightning masts require separate space so these cannot be used in

high level layout arrangement where no space is available between the

bays.

Location of Control Room, Fire Fighting Pump House Building, DG

Set:

The location of control room building, fire fighting pump house

building, DG set in the substation play a major role for economic

design of substation. While locating control room building, following

points are to be considered:

i) Safety & Security - Location of control room should be directly

accessible without passing through the charged switchyard

area.

ii) Clear view of substation should be visible from control room.

iii) Cable lengths should be minimum to avoid voltage drops.

4.4.6 Roads & Rail Track:

It is an important aspect from operation and maintenance point of view.

These are judiciously chosen keeping in view the cost, easy movement

of trailer/ crane for maintenance of transformer, CB etc. or

transportation of these equipments in the substation without causing

shutdown of other healthy/charged equipments.

4.4.7 Other Parameters:

Type of insulator strings, conductor, Aluminium bus, earthing etc. are

other parameters of substation design for which no compromise can be

done but they do not have much impact in the layout design of

substation.

4.4.8 Conclusion

Substation layout design is generally dependent upon the availability of

land, site constraints and system requirement but still it is preferable to

adopt uniform type of layout as far as possible as per selected

switching scheme which is very useful in a long run for operation,

maintenance and extension point of view. A typical layout (Plan &

Sections) for single line diagram shown in Fig.4.1 is mentioned below

in Fig.4.2 (a), (b), (c), (d) &(e).

Fig: 4.2 (a): Typical 220 KV DMT Layout Plan

Fig: 4.2 (b); Typical 220 KV DMT Layouts (Section-Transformer Bay)

Fig: 4.2 (c); Typical 220 KV DMT Layouts (Section-Line Bay)

Fig: 4.2 (d); Typical 220 KV DMT Layout (Section-TBC bay)

Fig: 4.2 (e); Typical 220 KV DMT Layout (Section-Bus coupler bay)

4.5 Switching Schemes

The various types of bus-bar schemes are:

Single bus-bar

Main and transfer bus-bar

Double bus-bar

Double main and transfer bus

Ring bus-bar and mesh bus-bar

One and half circuit breaker

Double bus and double breaker scheme

4.5.1 Selection of bus-bar scheme

The selection of a bus-bar scheme and its possible extension is an

important initial step in substation design. The aspects which influence

this decision are operational flexibility, system safety, reliability,

availability, ability to facilitate system control and cost. An important

factor in selection of bus-bar scheme is the degree of reliability of

supply expected during maintenance or faults. Careful consideration

has also to be given regarding the amount of redundancy to be

provided so as to determine the amount of plant, which can be

permitted out of use on account of maintenance or faults. Certain

amount of sectionalisation has also to be provided in a substation so as

to ensure that in the event of a fault, a large power source does not get

disconnected. In the case of step-up substations associated with large

generating stations a fault within the substation may have serious

repercussions from the point of view of the system operating as a

whole and, therefore, a very high degree of reliability is required in

such cases as compared to step down or switching stations. Similarly,

the exposure of a substation to atmospheric hazards such as lightning,

marine and industrial pollution etc. also plays an important part in

deciding the type of the bus-bar system. Then there is the problem of

future expansion of the bus-bar system at least in a foreseeable future.

4.5.2 Single bus bar scheme

A single bus configuration consists of one main bus that is energized at

all times and to which all circuits are connected. This arrangement is

the simplest, but provides the least amount of system reliability. The

entire substation is lost in case of a fault on the bus bar or any bus-bar

isolator and also in case of maintenance of circuit breaker thereof. The

single bus configuration can be constructed by using either low or high-

profile structures and is generally limited to distribution and

subtransmission voltage levels. A typical single bus bar arrangement is

shown in Figure 4.3. One of the methods for reducing the number of

circuits lost in case of a bus fault is to sectionalize the bus as shown in

Figure 4.3(a).

Fig: 4.3 : Single Main Bus Scheme

Fig: 4.3(a) : Single Main Bus Scheme (Sectionized)

Advantages:

Lowest cost

Small land area required

Easily expandable

Simple in concept and operation

Relatively simple for the application of protective relaying

Disadvantages:

A single bus arrangement has the lowest reliability.

Failure of a circuit breaker or a bus fault causes loss of the entire

substation.

Maintenance switching can complicate and disable some of the

protective relay scheme and overall relay coordination.

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4FEEDER-3FEEDER-2FEEDER-1

MAIN BUS

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4FEEDER-3FEEDER-2FEEDER-1

MAIN BUS

Maintenance at the upper elevations of high-profile arrangements

necessitates de-energization or protection of the lower equipment.

4.5.3 Main and transfer bus bar scheme

A main and transfer bus configuration consists of two independent

buses, one of which, the main bus, is normally energized. Under

normal operating conditions, all incoming and outgoing circuits are fed

from the main bus through their associated circuit breakers and

isolators. A typical main and transfer bus bar arrangement is shown in

Figure 4.4. This scheme has been used in India for 132 kV systems in

general, U.S.A. and also in some of the European countries,

particularly for step-down substations, as bus-bar faults are rare.

Transfer bus is energised from main bus bars through a bus coupler

circuit i.e. for ‘n’ number of circuits it employs n+1 circuit breakers. The

additional provision of Transfer bays and Bus Coupler circuit facilitates

taking out one circuit breaker at a time for routine overhaul and

maintenance without de-energising the circuit controlled by that

breaker as that circuit then gets energised through Bus Coupler

breaker and transfer bus bar. Each circuit is connected to the main bus

bar through a circuit breaker with isolators on both side and through an

isolator to the transfer bus bar.

As in the case of single bus arrangement, this scheme also suffers

from the disadvantage that in the event of a fault on the main bus bar

or the associated isolator, there is a complete shutdown of the

substation. Complete shutdown can be avoided through sectionalizing

the main bus as shown in Figure 4.4(a) & 4.4 (b).

Fig: 4.4 : Main and Transfer Bus Scheme

Fig: 4.4(a) : Main and Transfer Bus Scheme (Sectionized)

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4FEEDER-3FEEDER-2FEEDER-1

MAIN BUS

BUSCOUPLER

TRANSFER BUS

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

MAIN BUS

FEEDER-1 FEEDER-2 BUS FEEDER-4FEEDER-3COUPLER

TRANSFER BUS

Fig: 4.4(b) : Main and Transfer Bus Scheme (Sectionized)

Advantages:

Accommodation of circuit breaker maintenance while maintaining

service and line protection

Reasonable in cost

Fairly small land area

Easily expandable

Disadvantages:

An additional circuit breaker is required for bus coupler.

Since the bus coupler breaker has to be able to be substituted for any

line breaker, its associated relaying may be somewhat complicated.

Failure of a circuit breaker or a bus fault causes loss of the entire

substation.

Somewhat complicated switching is required to remove a circuit

breaker from service for maintenance.

4.5.4 Double bus-bar scheme

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4FEEDER-3FEEDER-2FEEDER-1

MAIN BUS

BUSCOUPLER-1 COUPLER-2

BUS

TRANSFER BUS

In this scheme a double bus bar is provided and each circuit can be

connected to either one of these through bus-bar isolators as shown in

Figure 4.5. Bus coupler breaker is also provided so that the circuits can

be switched on from one bus to the other on-load.

The scheme suffers from the disadvantage that when the circuit

breaker is taken out for maintenance, the associated feeder has to be

shutdown. This can be avoided by providing, a by-pass isolator across

circuit breaker as shown in Figure 4.5(a) (with four isolators) and

Figure 4.5(b) (with five isolators). But under this condition all the

circuits have to be transferred to one bus and protection of feeder has

to be transferred to bus coupler. This scheme has the limitation that

only one bus is available when any breaker has to be taken out for

maintenance. The double bus-bar scheme with by-pass isolator across

circuit breakers is very suitable for large generating stations.

Advantages:

Bus maintenance possible. With by-pass isolator, it has the same

advantages of main and transfer bus bar scheme

Reasonable in cost

Fairly small land area

Easily expandable

Disadvantages:

Circuit breaker maintenance is not possible without shutdown of the

feeder. But with by-pass isolator scheme, circuit breaker can be taken

for maintenance with complicated switching operation.

Lack operation flexibility.

Complicated switching is required to remove a circuit breaker from

service for maintenance.

Fig: 4.5 : Double Bus Bar Scheme

Fig: 4.5(a) : Double Bus Bar Scheme (with by-pass isolator)

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-1 FEEDER-2 FEEDER-3 FEEDER-4 COUPLERBUS

MAIN BUS-I

MAIN BUS-II

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4FEEDER-3FEEDER-2FEEDER-1BUS

COUPLER

MAIN BUS-I

MAIN BUS-II/TRANSFER BUS

4.5.5 Double main and transfer bus-bar scheme

In this bus bar scheme, in addition to the two main buses there is a

separate transfer bus also. Since separate transfer bus is available

there is no need of transferring the load from one bus to the other bus

unlike in a double main cum transfer bus arrangement. Other features

are similar to the one described in double bus with bypass

arrangement.

The limitation of double bus bar scheme with bypass isolator can be

overcome with double main and transfer bus scheme as shown in

Figure 4.6 by using additional transfer bus, transfer bus breaker and

isolators. In this arrangement, the feeder, the breaker of which is to be

maintained is transferred to the transfer bus without affecting the other

circuits. This scheme has been widely used for the highly

interconnected power networks where switching flexibility is important

and multiple supply routes are available. This scheme is also used for

splitting networks, which are only connected in emergencies.

Fig: 4.5(b) : Double Bus Bar Scheme (with by-pass isolator)

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

MAIN BUS-I

COUPLERFEEDER-1 FEEDER-2 FEEDER-3 FEEDER-4BUS

MAIN BUS-II

Fig: 4.6 : Double Main and Transfer Bus Bar Scheme

Advantages:

Maintenance of circuit breaker is possible with the help of transfer bus

coupler feeder without shut down of the feeder

Redundancy available

More operation flexibility with two main buses and one transfer bus

Failure of a circuit breaker or a bus fault does not cause loss of the

substation

Easily expandable

Disadvantages:

An additional circuit breaker is required for transfer bus coupler in

addition to the bus coupler bay which increases the cost

Reasonably more land area

4.5.6 Mesh/ring bus-bar scheme

A ring bus configuration is an extension of the sectionalized bus

arrangement and is accomplished by interconnecting the two open

LEGEND:-

ISOLATOR

CIRCUIT BREAKER

FEEDER-1 FEEDER-2 FEEDER-3 FEEDER-4 COUPLERBUS

COUPLERBUS

TRANSFER

MAIN BUS-I

MAIN BUS-II

TRANSFER BUS

ends of the buses through another sectionalizing breaker. This result in

a closed loop or ring with each bus section separated by a circuit

breaker. For maximum reliability and operational flexibility, each

section should supply only one circuit.

In this arrangement, as with the sectionalized bus configuration, only

limited bus sections and circuits are removed from service because of

line or bus faults or circuit breaker failure. For a line or bus fault, the

two circuit breakers on the sides of the affected bus section open to

isolate the fault. The remaining circuits operate without interruption. For

a breaker failure, the two breakers on the sides of the affected breaker

open, along with a transfer trip to a remote breaker, to isolate the failed

breaker and remove two bus sections from service.

The ring bus arrangement provides for circuit breaker maintenance

since any breaker can normally be removed from service without

interruption of service to any circuits. As a result, separate circuit

breaker bypass facilities are not required.

A number of equipment arrangements may be used to provide a ring

bus configuration, depending on anticipated substation expansion and

possible system modifications. Figure 4.7 illustrates a typical ring bus

configuration. The arrangement shows four circuit positions, which is a

practical maximum for a ring bus configuration. Rather than expanding

the ring bus to accommodate additional circuits, other more flexible and

reliable configurations, such as the breaker-and-a-half scheme, can be

adopted. However, the relay and control panels have to be carefully

planned to be modified later for breaker-and-a-half operation. Bay

centerline spacing should be carefully planned to permit equipment

maintenance and removal.

Fig: 4.7 : Mesh/Ring Bus Bar Scheme

Advantages:

Flexible operation

High reliability

Isolation of bus sections and circuit breakers for maintenance without

disrupting circuit operation

Double feed to each circuit

No main buses

Expandable to breaker-and-a-half configuration

Economic design

Disadvantages:

Ring may be split by faults on two circuits or a fault during breaker

maintenance to leave possibly undesirable circuit combinations

(supply/load) on the remaining bus sections. Some consider this,

however, to be a second contingency factor.

Each circuit has to have its own potential source for relaying.

This configuration is usually limited to four circuit positions, although

larger rings are in service, including 10-position ring buses. A 6-

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4

FEEDER-3

FEEDER-2

FEEDER-1

position ring bus is usually considered as a maximum limit for the

number of terminals in a ring bus.

4.5.7 Breaker and half scheme

The breaker-and-a-half configuration consists of two main buses, each

normally energized. Electrically connected between the buses are

three circuit breakers and, between each two breakers, a circuit as

diagrammed in Figure 4.8. In this arrangement, three circuit breakers

are used for two independent circuits; hence, each circuit shares the

common center circuit breaker, so there are one-and-a-half circuit

breakers per circuit.

The breaker-and-a-half configuration provides for circuit breaker

maintenance, since any breaker can be removed from service without

interrupting any circuits.

A fault on any bus is cleared by the opening of the associated circuit

breakers without affecting continuity for supply. All load transfer is done

by the breakers and therefore, the operation is simple. However

relaying is somewhat more involved as the third breaker has to be

responsive to troubles on either feeder in the correct sequence.

Besides, each breaker has to be suitable for carrying the currents of

two circuits to meet the requirements of various switching operations,

which may in some cases increase the cost. The breaker and a half

scheme are suitable for those substations which handle large amounts

of power on each circuit. The scheme has been widely used in U.S.A.

particularly for their EHV substations operating at 330 kV and above.

This scheme has been applied widely in the 420 kV systems in India

also.

Fig: 4.8 : Breaker and Half Bus Bar Scheme (D Type)

Fig: 4.8(a) : Breaker and Half Bus Bar Scheme (I Type)

Advantages:

Flexible operation

High reliability

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-4FEEDER-3FEEDER-2FEEDER-1

MAIN BUS-II

MAIN BUS-I

ISOLATOR

LEGEND:-

CIRCUIT BREAKER

MAIN BUS-II

MAIN BUS-IFEEDER-1

FEEDER-2

FEEDER-3

FEEDER-4

Can isolate either main bus for maintenance without disrupting service

and hence it provides active redundancy

Can isolate any circuit breaker for maintenance without disrupting

service

Double feed to each circuit

Bus fault does not interrupt service to any circuits

All switching done with circuit breakers

Moreover, in case of bus fault, a feeder can also be diverted through tie

breaker

Disadvantages:

One-and-a-half breakers are required per circuit which increases cost

Complicated Relaying is involved, since the center breaker has to

respond to faults of either of its associated circuits.

4.5.8 Double bus & double breaker scheme

The double breaker–double bus configuration consists of two main

buses, each normally energized. Electrically connected between the

buses are two circuit breakers and, between the breakers, one circuit,

as diagrammed in Figure 4.9. Two circuit breakers are required for

each circuit.

In the double breaker–double bus configuration, any circuit breaker can

be removed from service without interruption of any circuits. Faults on

either of the main buses cause no circuit interruptions. Circuit breaker

failure results in the loss of only one circuit.

Use of the double breaker–double bus configuration is usually limited

to large generating stations because of the high cost. The additional

reliability afforded by this arrangement over the breaker-and-a-half

scheme usually cannot be justified for conventional transmission or

distribution substations. Because of increase in number of breakers per

bay and higher cost, double bus double breaker scheme is suitable for

those substations, which handle large amount of power.

Fig: 4.9 : Double Bus and Double Breaker Scheme

Advantages:

Flexible operation

Very high reliability

Isolation of either main bus for maintenance without disrupting service

Isolation of any circuit breaker for maintenance without disrupting

service

Double feed to each circuit

No interruption of service to any circuits from bus fault

Loss of only one circuit for breaker failure

All switching with circuit breakers

Disadvantages:

This configuration carries a high cost.

Two circuit breakers are required for each circuit.

CIRCUIT BREAKER

ISOLATOR

LEGEND:-

FEEDER-2FEEDER-1 FEEDER-3 FEEDER-4

MAIN BUS-I

MAIN BUS-II

4.5.9 General Arrangement

General Arrangement of a substation is the most important engineering

plan, based on which the entire engineering of the substation proceeds

further. The location of substation, associated buildings, colony area is

identified in this plan.

Switching scheme should be finalized and areas to be earmarked

based on layout to be adopted. Different types of switching schemes

are available. For 400 kV voltage level, breaker and half schemes bus

scheme is generally in use.

For 220 kV voltage level, double main and transfer scheme has been

generally preferred. Different types of layout can be prepared for a

particular scheme. These layouts are to be selected based on available

land and techno-economic consideration.

The GA drawing broadly should include following building/facilities:

Control Fire fighting pump house placement

DG set placement

LT station placement

Placement of switchyard

Identification of roads & rail tracks

Identification of boundary wall and fencing

Identification of approach roads

Space for colony and other infrastructures

Control Room Building: The placement of this building has been made

keeping in view the following considerations: Optimization of size and

length of cables for various bays allocated for future and present

scope, centrally located for operational convenience and visibility,

avoid flooding in cable gallery during rains, reasonable security, avoid

filled up areas.

Fire Protection Room should be so located to minimize head loss at

various transformer & reactor units, optimize size of fire fighting system

and cabling works. It should preferably be outside the switchyard fence

for security reasons.

DG set location is generally governed by following considerations:

Convenience of approach in the event of auxiliary power failure

Handling of diesel shall be away from the yard.

Cable length to control room is optimized.

Vibrations of DG set do not effect equipment and other structures.

Exhaust shall be away the from main control room building.

Roads shall be well laid out for convenience of approach during

construction and O&M. This also helps in movement of operators for

monitoring the equipments and transportation of heavy equipments

such as transformers and reactors. Filtration plant and oil tanks. In

case of switchyard terraces, only gradual slopes are to be provided for

safety of the equipments and personnel.

4.5.10 Substation earthing

Provision of adequate earthing system in a substation is extremely

important for safety of the operating personnel as well as for proper

system operation and performance of the protection devices. The

primary requirements of a good earthing system in a substation are:

The impedance to ground should be as low as possible. In the

substations with high fault levels, it should not exceed 1 ohm and in the

substations with low fault levels it should not exceed 5 ohms.

The step and touch potentials should be within safe limits.

To meet these requirements, an earthing system comprising an

earthing mat buried at a suitable depth below ground, supplemented

with ground rods at suitable points is provided in the substations. All

the non-current carrying metal parts of the equipments in the

substation are connected to the earthing mat so as to ensure that

under fault conditions, none of these parts is at a potential higher than

that of the earthing mat. Under normal condition, the ground rods make

little contribution in lowering the earth resistance: these are, however,

helpful in maintaining low value of résistance under all weather

conditions which is particularly important for installations with high

system earth fault currents.

All substations should have provision for earthing the following:

The neutral points of equipment in each separate system. There should

be independent earth for the different systems. Each of these earthed

points should be interconnected with the station earthing mat by two

different diagonally opposite connectors to avoid common mode failure.

Equipment framework and other non-current carrying metal parts.

All extraneous metal frameworks not associated with equipment.

Lightning arresters: These should have independent earthing which

should in turn be connected to the station grounding grid or Earthman.

The earthing of substation fence has to be considered from the

viewpoint of touch and step potentials in the peripheral area outside the

fence. Normally the earth mat has to be extended by 2m beyond the

fence so as to ensure that the area in the vicinity of the substation

fence is safe.

Where the fence is large and mat area is small, in that case fence

earthing should be isolated from the main earth mat so that person

touching the fence is protected from danger due to transfer voltage.

Earthing in a substation must conform to the requirements of the Indian

Electricity Rules and the provisions of the relevant sections of IS: 3043-

1987. The earthing is designed as per IEEE-80 (Latest Edition). The

earthing system should be designed to have low overall impedance

and a current carrying capacity consistent with the fault current

magnitude.

Bare stranded copper conductor or copper strip used to find extensive

application in the construction of earth mat in the past. However, on

account of high cost of copper and the need to economise in the use of

copper, current practice in the country is based on the use of steel

conductor for earth mat.

In view of fast deterioration of GI pipe electrode, cast iron pipe

electrode is preferred for earthing. The minimum distance between the

electrodes shall be twice the length of electrode.

Design procedure

For detailed design of earth mat reference may be made to the latest

edition of IEEE-80, CBIP Technical Report on “Manual on AC

substation grounding”.

4.5.11 Design of earthing system in uniform soil

Required Data

The data, which ought to be determined before starting the design of

earthing system for a high voltage substation, where the soil at the site

can be considered to be uniform, are:

Area covered by the substation

Resistivity of the soil at the substation site

The maximum earth fault current

Fault clearing time for conductor size and for shock duration

The maximum grid current

Resistivity and depth of surface layer

Area Covered by the Substation

The area over which the earth electrode is to be placed depends on the

substation plan. The area over which the conductors of earth electrode

system are usually buried shall include all the fenced area including

switchyard, control room, DG building, fire-fighting building and LT

switchyard for supply within the fenced area. The conductors of earth

electrode may not be buried under the buildings but only on the

periphery of the buildings.

Resistivity of the Soil at the Station

The average resistivity is usually determined by the four-electrode

Wenner method. The resistivity value should be preferably obtained by

making measurements over a period of at least one year; if time is

short, measurements may be made during dry, cold season.

The Maximum Earth Fault Current

The maximum earth fault current occurs in case of either two-phase to

earth or single phase to earth fault. But because of much higher

probability of occurrence, the single phase to earth fault current may be

used to calculate the maximum earth fault current. Its magnitude

should be available from results of System Fault Studies.

Fault Duration and Shock Duration Time

Shock duration time is the fault clearing time including that of

reclosures if automatic reclosures are used. The value of 0.5 s, for

shock duration time, may be used to determine the permissible values

of Estep and Etouch. However, to calculate the conductor cross-section,

the time should be the maximum possible fault clearing time including

backup; this can be up to 1 s. In case of small substations, 3-second

time has been used. A design engineer should choose the appropriate

value applicable at the station for which the earth electrode is

designed.

Design of Grid Earth Electrode

Design of the grid earth electrode involves the following steps:

Selection of the material of conductors of earth electrode,

Determination of the size of conductors of earth electrode,

Preliminary arrangement of the conductors of earth electrode system,

Conductor length required for gradient control, and

Calculation of earth resistance of the earthing system and the grid

potential rise.

The last phase of the design consists of

Checking of earth fault current and grid current,

Calculation of step voltage at the periphery of the substation and mesh

voltage, and

Investigation of transferred potential.

Selection of Material of Conductors of Earth Electrode

The material of earth electrode should have high conductivity and low

underground corrosion. Now a day’s mild steel is used in India. Its use

avoids galvanic action between earth electrode and other underground

utilities, which are mostly of steel. Galvanized steel, if used, retards the

rate of corrosion in initial stages; however, if the zinc coating is

scratched/eroded at some locations, the rate of corrosion increases.

Depending on the corrosivity of soil, zinc coating may be destroyed in

two to twenty years. When designing the earth electrode for thirty to

fifty years it is preferable to increase the size to make provision for

corrosion during its life.

Determination of Size of Conductors of Earth Electrode

Proper size of the earth electrode conductor should be such that it has

(i) thermal stability to flow of earth fault current, (ii) it lasts for 30 - 50

years without causing break in the earthing circuit due to corrosion, and

(iii) it is mechanically strong.

For current of magnitude I kA, conductor size (mm2), when conductor

material is mild steel, is determined by

fc tI15.12A

Preliminary Arrangement of the Conductors of Earth Electrode System

The main earthing system is formed of a grid of conductors, mostly

perpendicular to each other, buried horizontally, usually at a depth of

0.6 m below the surface of earth.

Provision of Vertical Rods

The grid earth electrode may be assumed to consist of only horizontal

conductors to start with. Vertical rods may be provided at this stage at

stations where resistivity of soil is likely to vary with change of seasons.

Driven vertical earth rods of 3 m - 5 m length with their upper ends

connected to mesh junctions are suitably provided. A vertical rod is

very effective if its length is such that it can penetrate the moist subsoil.

Where the top layer of soil is dry and of very high resistivity, enough

number of vertical rods may be provided to carry current to the

underlying soil without overheating and drying of the soil. Rods on the

periphery of grid electrode are more effective than those towards

central portion.

Permissible Values of Dangerous Voltages

The spacing between conductors of the grid electrode has to be such

that the touch and step voltages are within its safe permissible value.

Safe/permissible values of step and touch voltages are obtained from

s

ssstept

116.0C61000E

s

sstoucht

116.0C5.11000E

Cs is a reduction factor which accounts for the effect of finite depth of

surface layer on foot resistance. Its value dependent on hs, depth of

surface layer of crushed rock or stone and the reflection factor K,

where

ssK

s being resistivity of stone/gravel layer and of the soil. Value of Cs

can be determined from the graph of Figure 4.10. The value of Cs can

also be obtained from the relation

09.0h2

109.0

1Cs

ss

Figure: 4.10 C versus h

Determination of Magnitude of Dangerous Voltages

Figure 5.4. C versus h

s s

Empirical formulae for determining the magnitude of dangerous

voltages that will actually occur at the site of grid earth electrode are

given below. The mesh voltage and step voltage, which shall occur in

the gird earth electrode, can be calculated from the expressions

mGimmm L/IKKE

sGisss L/IKKE

The factors Km and Ks are given by

1n2

8ln

K

K

d4

h

Dd8

h2D

hd16

Dln

2

1K

h

ii22

m

2n

s 5.01D

1

hD

1

h2

11K

Where

D=spacing between parallel conductors, m

h= depth of conductors of earth grid electrode, m

d= diameter of grid conductor (for strip conductor d = width/2), m

Lp= peripheral length of grid, m

Lx = maximum length of grid in x direction, m

Ly = maximum length of grid in y direction, m

Dm= maximum distance between any two points on the grid, m

A = Area of the grid, m2

Kii= 1/(2n)(2/n), for grids with no or few vertical earth rods, with none in

the corners or on the periphery; = 1 otherwise

Kh = (1 +h) 0.5

n = na nb nc nd

na = 2 Lc / Lp

nb = [Lp / (4 A)]0.5

yxLL

A7.0

yxc ]

A

LL[n

n148.0644.0KK isim

nd = Dm / (Lx2 + Ly

2 ) 0.5

In case of grid with only a few vertical earth rods scattered throughout

the grid, but none located in the corners or along the periphery, the

effective buried conductor length, Lm, is determined from

Lm = Lc + Lr

Lc = total length of conductor in the horizontal grid, m.

lr = length of each vertical earth rods, m

Lr = total length of vertical earth rods, m = Nr . lr

Nr = Number of vertical rods

For grids with vertical earth rods in the corners, as well as along the

perimeter and throughout the grid, the effective buried conductor length

Lm is

LrLL

l22.155.1LL

2y

2x

rcm

For determining Es, for grids with or without vertical earth rods, the

effective buried conductor length Ls, is

Ls = 0.75 Lc + 0.85 Lr

For computing the length of conductor in the grid, with equispaced

earth conductors, required to keep touch voltage below the permissible

value. The total length required to limit the maximum touch voltage

within permissible value is

ss

sGimmm

C174.0116

tIKKL

If the length so obtained is less than that obtained from the preliminary

layout no change in the layout of conductors is necessary; otherwise

closer meshes especially in the areas, which are frequently visited by

operating personnel, are to be adopted.

Calculation of Resistance of Grid Earth Electrode and the Maximum

Grid Potential

A simple formula is as follows

A/20h1

11

A20

1

L

iR

tG

Lt is to the total length of buried conductors i.e. length of horizontal grid

conductors and the length of vertical earth rods if any, i.e. Lt = Lc + Lr.

The maximum rise in potential of the grid above remote earth, IGRG,

needs investigation if a case of transferred potential occurs. If

necessary, resistance of the electrode may be decreased by modifying

the design by increasing area of the grid; using more conductor length

without increasing area is not effective for decreasing RG to any

appreciable extent.

The following steps may be taken to decrease both step and touch

voltage and EPR:

Diverting a part of the fault current to other parts, by overhead earth /

shield wires, which divert current to footing resistance of transmission

line towers,

Diverting a part of fault current to another earth electrode at a distance

from the station, and

Limiting earth fault circuit current if possible.

Steps that may be taken to provide safety against unsafe touch voltage

are:

Barring access to limited areas like having a narrow and deep ditch

outside the fence,

For limiting the touch voltage inside the grid, the meshes near the

corners can be subdivided by additional conductors in between the

main conductors or by using unequally spaced conductors. This serves

to modify earth surface potential gradients and thus reduces the mesh

voltage.

Instead of using a chain link fence at the boundary of the property, a 2

m high boundary wall topped by one-meter high chin link fence can be

used to mitigate the problem of unsafe touch voltage from outside.

Investigations of Transferred Potential

Transfer of potential between the areas covered by earth grid and

outside points, by conductors such as communication signal, and

control cables, low voltage neutral wires, water or conduit pipes, rails,

metallic fences etc., is possible. Transferred potential should be

checked as a serious hazard. Earth resistance of the earthing system

should be kept as low as possible to reduce magnitude of this voltage.

However once the area of grid earth electrode and value of soil

resistivity are frozen, there is little control over earth resistance of a grid

earth electrode.

In case of communication circuits protective devices and isolating and

neutralizing transformers are used. When such circuits are routed

outside the area of grid electrode, an earth conductor should be run

along the circuit in the same trench and connected to the metal

brackets. Use of fiber optics can eliminate this hazard. Insulation level

of control circuit wires should be of proper voltage class. The rails

entering a substation can become connected to grid intentionally or

otherwise. The hazard due to them can be removed by using several

insulating joints at two places such that a metal car or the soil itself

cannot short circuit the insulating joints. A simple and practical method

to avoid transfer of potential through rails is to remove a section of

rails, which is inserted only when needed. If low voltage feeders

starting inside the station feed an outside area, the neutral connected

to the station grid and possibly earthed at a far point also creates a

hazard. In such a case either the neutral should be treated as a phase

wire with appropriate level of insulation or preferably no low voltage

supply is taken outside the station area. Piping, cable sheaths etc. if

any should be tied to the station earthing system at several points in

the station area. These can in fact greatly reduce the earth resistance.

The distance to and the manner in which voltage is transferred to

outside area depend on the propagation constant λ. If voltage of the

grid becomes VG volts the linearized approximate value of voltage

gradient along its length is (VG/2λ). If soil resistivity is 100 ohm-m in the

area, propagation constant is approximately half a kilometer. The

voltage gradient along the pipe or sheath will be approximately VG

volt/km that is if the pipe is at least 1 km long; and gradient is assumed

to be linear. In water supply pipes, insulating pipe sections of concrete

or plastic capable of withstanding the potential difference equal to VG

can be inserted in the pipe. If there are buildings at the station site and

they are linked to station by L.T. supply, water pipe, or telephone lines

they should be treated as part of the station area. If they are to be kept

as separate units, they should be provided with their own earthing and

outside LT supply from the local area and adequately protected against

potentials transferred from the station. Road side lighting or safety

lights outside the station area should also be energized with LT supply

from outside.

If there is metallic gate in the boundary wall/fence, it should normally

open inside. If however it opens outside, an earth mat should be laid up

to its full open position. This mat is to be connected to the earth grid.

4.5.12 Lightning protection

A substation has to be shielded against direct lightning strokes either

by provision of overhead shield wire/earthwire or spikes (masts). The

methodology followed for systems upto 145 kV is by suitable

placement of earthwires/masts so as to provide coverage to the entire

station equipment. Generally, an angle of shield of 60° for zones

covered by two or more wires/masts and 45° for single wire/mast and

45° for single wire/mast is considered adequate. For 245 kV

installations and above, normally use of electromagnetic methods is

resorted to. The most used method for determining shielded zones is

the Mousa Method and Razevig Method.

Besides direct strokes, the substation equipment has also to be

protected against travelling waves due to lightning strokes on the lines

entering the substation.

The apparatus most commonly used for this purpose is the lightning

arrester.

An advance in material technology has resulted in the development of

metal oxide gapless type surge arrestors which are being most widely

used because of higher reliability.

The most important and costly equipment in a substation is the

transformer and the normal practice is to install lightning arresters as

near the transformer as possible. The fixing up of insulation level for

various equipments within a substation requires a detailed study of

insulation coordination with lightning arrester as the focal point for

providing protection to the equipment from power frequency over-

voltage exceeding the rating of the arrester. In the EHV range, there is

also the problem of switching over-voltage exceeding the rating of the

arrester. In the EHV range, there is also the problem of switching over-

voltages as the life of the arrester may be considerably reduced due to

frequent operations due to such over voltages. Sometimes it is not

possible to locate the lightning arrester very near the transformer.

However, there is no problem so long as the transformer is within the

protective distance from the lightning arrester. Besides protecting the

transformers, the lightning arresters also provide protection to the

equipment on the bus side located within certain distances. In the case

of very large substations where the lightning arrester for the

transformer does not provide adequate protection to the other

equipment, additional lightning arresters either on the bus or on various

lines have to be provided. For determination of number of lightning

arresters and their locations, each case has to be studied taking the

size and importance of the substation, isoceraunic level, anticipated

over voltages etc. into consideration.

4.6 EHV Power Transformers

General

A transformer is a static piece of apparatus with two or more windings which,

by electromagnetic induction, transforms a system of alternating voltage and

current into another system of voltage and current usually of different values

and at the same frequency for the purpose of transmitting electrical power.

Various components of transformer are shown in Figure 4.11.

The primary function of a power transformer is to transform system voltage

from one nominal level to another. The transformer has to be capable of

carrying the power flow for its particular location in the system under various

operating conditions and contingencies, such as line or transformer outages.

Transformer is the largest piece of equipment in a substation and it is,

therefore, important from the point of view of station layout. For instance on

account of large dimensions, it is generally not possible to accommodate two

transformers in adjacent bays. One of the problems is the installation of

radiators which makes the width of the transformer much more than bay

width. In order to reduce the risk of spread of fire, large transformers are

provided with stone metal filled soaking pits with voids of capacity adequate to

contain the total quantity of oil. Besides, separation walls are provided in-

between the transformers.

Silicagel Breaher

Winding

Temperature

Indicators

Oil Temperature

Indicator

Magnetic Oil

Level Gauge

Main Conservator

I.V. Bushing

Neutral Bushing

Lifting Bollard

Tertiary Bushing

Neutral Earthing

Upper Tank

OLTC Drive

Mechanism

Lower Tank

Rating & Diagram

Plate (English)

Roller Assembly

Jacking PadStorage Instructions

Plate

Rating & Diagram

Plate (Hindi)

Flexible Separator

Instruction Plate

In Line oil

Pump

Oil Flow

Indicator

Cooling Fans

Cooler Bank

Expansion JointMarshalling KioskBuchholz RelayO.L.T.C. ConservatorPressure Release

DeviceH.V Bushing

Fig: 4.11: Various parts of a Transformer

4.6.1 Basic Design & constructional details

Core and magnetic circuit

There are two basic types of transformers categorised by their core/

magnetic configuration: (a) shell type and (b) core type.

In a shell-type transformer the flux-return paths of the core are external

to and enclose the windings. Core-type transformers have their limbs

surrounded concentrically by the main windings.

The following is considered to be important for core and magnetic

design.

3 limb or 5 limb

core grade selection

core diameter, leg height & phase centre

over fluxing consideration

flux density selection

no load loss

specific weight (W/kg)

Noise

A three-phase transformer can often be more economical to build by

enclosing one core and coil structure inside one transformer tank

instead of building three separate core and coil structures and tanks.

The first basic design for three-phase transformers is the core form

design. This design includes the three-legged core form design and the

five-legged core form design. In the three-legged core form design,

three sets of windings are placed over three vertical core legs. Each

core leg and its set of windings is corresponds to one phase. Each core

leg is joined to a top yoke and a bottom yoke, which complete the

magnetic circuit. The general layout of the three-legged core form

design is shown in Figure 4.12. The set of windings on the center

phase are cut away to show the placement of the LV and HV windings

around the center core leg.

Fig: 4.12: Three-legged core form transformer.

In large power transformers, third harmonic flux and stray 50 Hz flux

from unbalanced voltages may leave the iron core and enter free space

inside the transformer. This induces currents in the internal metal parts

of the transformer and may cause severe localized overheating. The

five-legged core form design solves this problem by providing flux

paths around the three core legs between the top and bottom yokes.

The layout of the five-legged core form transformer is shown in Fig:

4.13. Residual flux is the total flux arriving at the top core yoke from the

core legs of the three phases. A fourth and fifth core leg provide two

return paths for the residual flux from the top to the bottom yoke. The

top and bottom core yokes are often made with a reduced cross

sectional area because they do not have to carry the full complement

of flux from each phase. This has the advantage of reducing the overall

height of the transformer. The disadvantage of reducing the cross-

sectional area of the yokes is that a portion of the normal flux from the

outer phases must now flow through the fourth and fifth core legs. This

makes the actual flux path uncertain and makes calculating core losses

difficult. The five-legged core form design has electrical characteristics

that are very similar to a bank of three single-phase transformers; i.e.,

the three phases operate more or less independently with a relatively

small magnetic interaction between the phases.

Fig: 4.13: Five-legged core form transformer.

The core is made of thin steel laminations that are stacked together.

The cross section area of the yokes must be sufficient to carry the full

flux of each phase. There has been a steady development of core steel

material from non oriented steels to scribed grain oriented steels. The

major development in core material is the introduction of grain oriented

silicon steel which possesses excellent magnetic properties in the

rolling directions and is indispensable as the core material for

transformers.

One of the ways to reduce the core losses (i.e no load loss or iron loss)

is to use better and thinner grades of core steels. Presently, the lowest

thickness of commercially available steel is 0.23 mm. Although the loss

is lower, the core-building time increases for the thinner grades. The

price of the thinner grades is also higher. Despite these disadvantages,

core materials with still lower thicknesses will be available and used in

the future. Commonly available CRGO core materials are M4, M6,

M2H, MOH, and ZDKH.

One of the major problems with large power transformers is audible

noise that can be loud enough to be very annoying. Essentially all

transformer noise is due to a phenomenon called magnetostriction.

When a strip of steel is magnetized, it contracts very slightly. Due to

the fact that magnetostriction is not linear with respect to the flux

density there are also harmonics of 100 Hz present in the noise. If any

part of the transformer is in resonance with any of the harmonics, the

noise can be amplified hundreds of times. Therefore, part of the core

design and the overall transformer design is an analysis of the

resonant frequencies.

The shell form design is a completely different design from the three

phase core form design. In a shell form transformer, the windings are

constructed from flat coiled spirals that are stacked together like

pancakes. For this reason, the windings in a shell form design are often

referred to as pancake windings. In a two-winding shell form

transformer, the low-voltage winding is usually split into two windings

with the high-voltage winding sandwiched between the two halves of

the low-voltage winding. Instead of a circular shape, the pancake coils

are actually square shaped with the outer corners rounded off. The

centers of the pancake coils are hollow and square-shaped. Core legs

with square cross sections pass through the centers of the pancake

coils. The core legs are laid horizontally so the coils are stacked

horizontally on edge. The return paths for the core go around the coils

forming a ‘‘shell’’ around the windings; hence the name shell form. The

basic shell form design is shown schematically in Figure 4.14. The core

without windings is shown on the left hand part of Figure 4.14. The

core is divided into two halves with each half carrying approximately

50% of the total flux. The three sets of windings are placed around the

longitudinal sections of the core as shown in the middle part of the

figure as viewed from above the transformer. The top part of the figure

shows the end cut away, clearly illustrating that the pancake coils are

square-shaped with rounded corners. The edges of the core

laminations are also seen in this view. The right part of the figure is an

exploded end view of the pancake windings divided into three sections:

The low-voltage winding is split into two halves, which sandwich the

high-voltage winding in the middle. The electrical characteristics of the

shell form transformer are similar to a five-legged core form

transformer or a bank of three single-phase transformers

Fig: 4.14: Three-Phase Shell Form Transformer.

4.6.2 Winding

Schematically, it is depicted the primary and secondary windings as

being wound around a common core but located on opposite core legs.

In any transformer design, however, the primary and secondary

windings are always mounted in close proximity to each other in order

to maximize the mutual coupling between the windings and thereby

increase the overall efficiency. Fig: 4.15 illustrate part of a two winding

core form transformer as a cut away view from the side and the end.

This configuration has one set of low-voltage and high-voltage

windings mounted over a vertical core leg. Note that the core leg and

the top and bottom core yokes are stepped to approximate a circular

cross section. The laminations are too thin to be seen individually in the

edge view. By convention, the HV winding is usually called the primary

and the LV winding is called the secondary; however, either the HV or

the LV winding can be the input winding.

Fig: 4.15 Cross section of a transformer with primary and secondary windings on a

common circular core leg.

Primary function of the copper (or aluminum) conductor of transformer

windings is to carry current. The flow of current produces load losses,

commonly known as copper losses. The copper losses comprise d.c

I2R losses, conductor eddy current and other eddy current losses (stray

losses).

Windings are subject to non-linear transient voltage distribution under

lightning and switching impulse voltage withstands tests. Windings

have to withstand dielectric stresses under one minute power

frequency induced over potential tests as well as one minute power

frequency separate source voltage withstand tests. It is also expected

that the windings shall demonstrate PD characteristics within

permissible levels during one hour induced over voltage test at 1.5 p.u.

The primary and secondary windings in a core type transformer are of

the concentric type only, while in case of shell type transformer these

could be of sand-witched type as well. The concentric windings are

normally constructed in any of the following types depending on the

size and application of the transformer

1. Cross over Type.

2. Helical Type.

3. Continuous Disc Type.

Cross-over type winding is normally employed where rated currents are

up-to about 20 Amperes or so. In this type of winding, each coil

consists of number of layers having number of turns per layer. The

conductor being a round wire or strip insulated with a paper covering. It

is normal practice to provide one or two extra lavers of paper insulation

between lavers. Further, the insulation between lavers is wrapped

round the end turns of the lavers there by assisting to keep the whole

coil compact. The complete windings consists of a number of coils

connected in series. The inside end of a coil is connected to the

outside end of adjacent coil. Insulation blocks are provided between

adjacent coils to ensure free circulation of oil.

In helical winding, the coil consists of a number of rectangular strips

wound in parallel racially such that each separate turn occupies the

total radial depth of the winding. Each turn is wound on a number of

key spacers which form the vertical oil duct and each turn or group of

turns is spaced by radial keys sectors. This ensures free circulation of

oil in horizontal and vertical direction. This type of coil construction is

normally adopted for low voltage windings where the magnitude of

current is comparatively large.

The continuous disc type of windings consists of number of Discs

wound from a single wire or number of strips in parallel. Each disc

consists of number of turns, wound radically, over one another. The

conductor passing uninterruptedly from one disc to another. With

multiple-strip conductor. Transpositions are made at regular intervals to

ensure uniform resistance and length of conductor. The discs are

wound on an insulating cylinder spaced from it by strips running the

whole length of the cylinder and separated from one another by hard

pressboard sectors keyed to the vertical strips. This ensures free

circulation of oil in horizontal and vertical direction and provides

efficient heat dissipation from windings to the oil. The whole coil

structure is mechanically sound and capable of resisting the most

enormous short circuit forces.

The windings coils after manufacture are subjected to drying out in an

oven by circulation of hot air at around 80 degree centigrade. The pre

drying and shrinking of coils is achieved in this process. The coils are

further dried UN-till the required insulation resistance is achieved. In

case of larger distribution and power transformers, the assembled core

and windings are further subjected to drying out at about 100C and

730mm absolute pressure to drive out water vapor and gas from the

windings. Appropriate clamping arrangements in the form of rings are

provided on the windings to adjust for any shrinkage of insulation. The

clamping rings could be either metallic with suitable earthing

arrangements or of insulating material. The insulation of the windings

comprises of insulating cylinders between LV windings and core and

between HV winding. Also insulating barriers are provided where

necessary, between adjacent limbs, in some cases and between core

yoke and coils.

The leads from top and bottom end of windings and from such tapings,

as may be provided, are brought out to a few centimeters length only.

The electrical connection from these leads to the terminals or bushings

consist of either copper rod or strips depending on the current to be

carried. Copper rods are insulated with bakelite tubes and supported

by cleats. Which in turn are supported from the vertical tie rods passing

through the top and bottom yoke clamps. When copper strips are used

for low voltage leads no insulation need to be provided, except the

cleats, which hold the strip in position. The strips are however wrapped

with linen or varnish cloth at the point where it passes through the

leads. Leads from tapings are brought out to a point just below the top

oil and so arranged that tapings may be readily changed by means of

off load Tap changer.

4.6.3 Insulation

Insulation design is one of the most important aspects of the

transformer design. It is the heart of transformer design, particularly in

high voltage transformers. Sound design practices, use of appropriate

insulating materials, controlled manufacturing processes and good

house-keeping ensure quality and reliability of transformers.

Comprehensive verification of insulation design is essential for

enhancing reliability as well as for material cost optimization.

The transformer insulation system can be categorized into major

insulation and minor insulation. The major insulation consists of

insulation between windings, between windings and limb/yoke, and

between high voltage leads and ground. The minor insulation consists

of basically internal insulation within the windings, viz. inter-turn and

inter-disk insulation.

Internal/minor insulation consists of all the insulation components

within the winding, viz. conductor paper covering, insulation between

layers in the radial direction, insulation between turns or disks in the

axial direction, and special insulating components that are placed close

to the insulated conductors.

Removal of moisture and impurities from the insulation is one of the

most important processes of transformer manufacture. With the

increase in the size of transformers, the time taken for processing of

their insulation also increases.

4.6.4 Cooling System

The magnetic circuit and windings are the principal sources of losses

and resulting temperature rise in various parts of a transformer. Core

loss, copper loss in windings (I2R loss), stray loss in windings and stray

loss due to leakage/high current field are mainly responsible for heat

generation within the transformer. Sometimes loose electrical

connections inside the transformer, leading to a high contact

resistance, cause higher temperatures. Excessive temperatures due to

heating of curb bolts, which are in the path of stray field, can damage

gaskets. The heat generated due to all these losses must be dissipated

without allowing the core, winding and structural parts to reach a

temperature which will cause deterioration of insulation. If the insulation

is subjected to temperatures higher than the allowed value for a long

time, it looses insulating properties; in other words the insulation gets

aged, severely affecting the transformer life.

Accurate estimation of temperatures on all surfaces is very critical in

the design of transformers to decide the operating flux density in core

and current densities in windings/connections. It helps in checking the

adequacy of cooling arrangements provided for the core and windings.

It also helps in ensuring reliable operation of the transformer since the

insulation life can be estimated under overload conditions and

corrective actions can be taken in advance.

The values of maximum oil and winding temperatures depend on the

ambient temperature, transformer design, loading conditions and

cooling provided. The limits for ambient temperature and the

corresponding limits for oil temperature rise and winding temperature

rise are specified in the international standards.

Almost all the types of transformers are either oil or gas filled, and heat

flows from the core and windings into the cooling medium. From the

core, heat can flow directly, but from the winding it flows through the

insulation provided on the winding conductor. In large transformers, at

least one side of insulated conductors is exposed to the cooling

medium, and the heat flows through a small thickness of the conductor

insulation. But in small transformers the heat may have to flow through

several layers of copper and insulation before reaching the cooling

medium.

Depending upon the size of the transformer, the cooling can of ONAN

(Oil Natural and Air Natural) type or ONAF (Oil Natural and Air Forced)

or OFAF (Oil Forced and Air Forced)

The radiator bank can be of 2x50% or 3x33.3% or 1X100% or 2x100%

design.

4.6.5 Mechanical Design

Transformer tanks commonly used are of the following types;

Plain sheet steel tank.

Sheet steel tank with external cooling tubes.

Radiator banks.

Tanks with corrugated wall panels.

Plain sheet steel tanks are used where the size of the tank provides

adequate cooling surface to dissipate the heat generated on account of

losses inside the transformer. Normally transformers up-to 50KVA

could be manufactured without external cooling tubes. For transformers

of higher rating, tanks are constructed with external cooling tubes to

provide additional surface for heat dissipation. The cooling tubes could

be circular or elliptical. Elliptical tubes with smaller width are employed

where one of the sides of the transformer is fully occupied by on load

tap changer. This ensures more tubes on the given surface thereby

providing more area for heat dissipation. In larger tanks, stiffeners are

also provided on the sides of the tank to prevent bulging of the tank

under oil pressure. The tubes are welded on the inside of the tank,

while all other joints are welded both, inside and outside.

Large size transformers, above 5 MVA rating are normally provided

with detachable Radiator banks to provide required cooling surface.

The radiator bank consists of series of elliptical tubes or a pressed

steel plate assembly welded into top and bottom headers. The radiator

bank is bolted on to the tank wall and two isolating valves are fitted into

the oil inlet and outlet. In case of very large transformers, even

detachable radiator banks mounted onto the tank walls do not provide

adequate cooling surface. IN such cases, separate self supporting

coolers are provided which are connected to the main transformer

through large detachable pipes. This type of arrangement is good for

naturally cooled transformers, as well as, for forced cooled

transformers. Forced air cooling could be provided by means of

suitable fans located below the cooler banks. Similarly, forced oil

cooling could be provided by installing an oil pump in the return cold oil

pipe connecting the main transformer tank to the cooler bank. For

outdoor transformers, the transformer has to be water-tight. For this

purpose, the cover bolts are closely spaced and a substantial tank

flange of ample width is provided. Further a Neoprene bonded cork

gasket is provided between the tank flange and the cover. The bushing

insulators are selected considering the maximum system voltages

encountered in the system and pollution conditions prevailing at site.

The joints are made water-tight by use of Neoprene bonded cork

gaskets.

Transformers of rating 1 MVA or more are also normally provided with

a conservator tank connected to the main tank. The conservator tank

has a capacity of about 10% of the oil content of the main tank.

4.6.6 Transformer Fittings & Accessories

Fittings listed below are normally provided on the transformers for the

correct and safe operation of the unit.

1. Rating and terminal marking plate.

2. Tap Changing arrangement

Off – circuit tap changing switch

Off – circuit tap changing link

On Load tap changer

3. Two earthing terminals

4. Lifting Lugs

5. Drain – cum filter valve

6. Pressure Relief Device

7. Silicagel dehydrating breather.

8. Oil Level Indicator.

9. Thermometer Pocket.

10. Conservator with drain plug and filling hole.

11. Air Release plug.

12. Jacking lugs

13. Filter valve (top tank)

14. Under base unidirectional flat rollers.

15. Terminal arrangement

16. Winding temperature indicator

17. Oil temperature indicator

18. Gas and oil actuated (Buchholz) relay

19. Conservator drain valve

20. Shut off valve between conservator and tank.

21. Magnetic oil level gauge

22. Explosion vent

23. Filter valve (Bottom of tank)

24. Skid under base with haulage holes

25. Junction box.

Rating and Terminal marking plate

The transformer is supplied with rating and terminal marking plate of a

non corrosive metal or metal with protective covering on which all

information concerning the rating. Voltage ratio, weights, oil quality etc.

along with the serial number of the unit is engraved.

Tap changing arrangement

Off - circuit tap changing switch

The transformer is fitted with an off-circuit tap changing switch to obtain

required tap voltage. It can be hand operated by a switch handle

mounted on the tank. Locking device is fitted to the handle to padlock it

on any tap position and also to prevent any unauthorized operation of

switch. The switch mechanism is such that it can be locked only when

it is bridging two contacts on any particulars tapping position and

cannot be locked in any intermediate position. It is important that the

transformer should be isolated from the live lines, before moving the

switch. Operating the switch when transformer is energized, will

damage the switch contacts due to severe arcing between the

contacts, and may damage windings also.

Off – circuit tap changing links

Contact bridging links are provided inside the transformer tank, to

obtain required tap voltage. Links are required to be unbolted and are

fixed in any required position of the tap. Links are approachable from

inspection holes in tank cover. In case of conservator units, oil level

has to be dropped below the inspection opening before unbolting

inspection covers.

On – Load tap changer

On load tap changer is normally mounted on the tank is a separate

housing and connected to winding leads through copper studs fixed on

a insulated terminal board Terminal board is on leak proof. Oil in the

tank need not be lowered down for a attending to OLTC gear. Please

see OLTC leaflet for the operation and maintenance instructions.

Earthing Terminals

Core laminations assembly is connected to core clamping frame by a

cu. strip which is in turn connected to the tank. Two earthing terminals

are provided on the tank which should be connected to the earthing

system of supporting structure of transformer or the station.

Lifting Lugs

Two / Four lifting lugs of adequate capacity are provided on tanks to lift

completely assembled transformer filled with oil. All lugs are designed

for simultaneous use and should be used simultaneously to lift the

transformer. Two/Four lifting lugs are provided on core clamps for UN

tanking the core and windings. All heavy fittings are also provided with

individual lifting lugs.

Valves and drain plugs

Valves

Transformer is equipped with Drain cum filter valve at bottom of tank.

Filter valve at top of tank. Valves are fitted with plugs / blanking plates

to stop the dirt or moisture entering inside the valve and avoid the

contamination of the transformer oil.

Drain Plugs

Drain Plug is provided on conservator to drain out oil.

Silicagel dehydrating breather

Silica gel breather is fitted with silica gel which absorbs moisture from

the air entering the transformer, thus preventing deterioration of oil and

insulation due to moisture condensation. The breather contains oil unit

at the bottom which prevents the entry of dust solid particles present in

the air. The colour of silica gel is blue when dry and turns pink when it

has absorbed a certain percentage of moisture by weight. The change

in colour of gel can be observed through window on a container.

Breather when fitted should examined to ascertain, that the silica gel is

dry (blue in colour) the frequency of inspection of gel depends upon

local climate and operating conditions. This dehydrating breather is

used in conventional type of transformer where breather in transformer

is applicable. In case of hermetically sealed transformer, silica gel

breathers are not required, there is no breathing in this transformer.

Oil Level indicator

Plain Oil level gauge Indicates oil level in tank or conservator, window

opening is fitted with grooved Perspex sheet and metal frame to give

clear indication of oil level.

Thermometer Pockets

This pocket is provided to measure temperature of the top oil in tank

with a mercury in glass type thermometer. It is essential to fill the

pocket with transformer oil before inserting the thermometer, to have

uniform and correct reading. One additional pocket is provided for dial

type thermometer (OTI) with contacts.

Conservator with drain plug and filling hole

Conservator is normally provided on all ratings of transformers which

provides the space for the expansion / contraction of oil on account of

the variation of oil temperature during service. It prevents the oil in the

tank from coming in direct contact with the atmosphere and protects it

from deterioration. Conservator is provided with silica gel breather, oil

level gauge, oil filling hole with blanking plate and drain plug for

draining/ sampling of oil contaminated by moisture and sludge.

Air release plug

Air release plug is normally provided on the tank cover for transformer

with conservator. Space is provided in the plug which allows air to be

escaped without removing the plug fully from the seat. Plug should be

unscrewed till air comes out from cross hole and as soon as oil flows

out it should be closed. Air release plugs are also provided on radiator

headers and outdoor bushings.

Jacking lugs

Four jacking lugs are normally provided for transformers above 1600

KVA. All lugs should be used simultaneously to avoid damage to

jacking pads and tank. Suitable hydraulic or mechanical jacks may be

used to jack up the transformer.

Rollers

Four rollers, plain or flanged type, are provided on e4very transformer.

Suitable arrangement of track for the rollers should be made at site, to

facilitate movement of the transformer. The track provided should be

leveled properly so that all wheels rest on the track. Rollers are

normally detached from the tank base at the time of transport.

Terminal Arrangement

i) Draw through bushing (oil flood type)

Winding lead is soldered to the stem of bushings which is drawn

through the hole in porcelain and is fixed outside the porcelain with

leak proof gasket. Oil is flooded through the hole of the porcelain which

acts as an insulation between the lead and earth in addition to the

porcelain insulation.

ii) Solid Bushing (through stem type)

Through stem protruding out of porcelain on either side is provided with

nuts and washers to take windings lead on one side and supply cable

on the other side. Bushing is completely sealed on one end for oil

tightness.

Winding temperature Indicator

The windings temperature indicator indicates ‘’ Hot spot’’ temperature

of the winding. This is a ‘’Thermal Image type’’ indicator. This is

basically an oil temperature indicator with a heater responsible to raise

the temperature equal to the ‘’Hot spot’’ gradient between winding and

oil over the oil temperature. Thus, this instrument indicates the ‘’Hot

Spot’’ temperature of the windings. Heater coil is fed with a current

proportional to the windings current through a current transformer

mounted on the winding under measurement. Heater coil is either

placed on the heater bulb enveloping the sensing element of the

winding temperature indicator immersed in oil or in the instrument. The

value of the current fed to the heater is such that it raises the

temperature by an amount equal to the hot spot gradient of the

winding, as described above. Thus temperature of winding is simulated

on the dial of the instrument. Pointer is connected thought a

mechanism to indicate the hot spot temperature on dial. WTI is

provided with a temperature recording dial main pointer. Maximum

pointer and re setting device and two sets of contacts for alarm and

trip.

Oil Temperature Indicator

Oil temperature indicator provides local temperature of top oil.

Instruments are provided with temperature sensing bulb, temperature

recording dial with the pointer and maximum reading pointer and

resetting device. Electrical contacts are provided to give alarm or trip at

a required setting (on capillary tube type thermometer).

Gas and oil actuated Buchholz relay

In the event of fault in an oil filled transformer gas is generated, due to

which buchholz relay gives warning of developing fault. Buchholz relay

is provided with two elements one for minor faults (gives alarm) and

other for major faults (tripping). The alarm elements operates after a

specific volume gets accumulated in the relay.

Magnetic Oil Gauge

This is a dial type gauge, mounted directly on the conservator to

indicate oil level. This is supplied with low level alarm contacts (if asked

for) and the electrical connections of which are brought out to a

terminal box of the oil gauge. Suitable alarm circuit may be connected

to these terminals. This oil gauge is not dispatched separately, but is

mounted on the conservator, with float arm adjusted to correct length.

Explosion Vent

Explosion vent is provided to give protection against the excessive

pressure that may developed inside the transformer due to internal

fault. On specific requirement the explosion vent is provided with two

diaphragms one at the bottom (near tank) and the other at the top. If

excessive pressure is developed in the tank, both diaphragms will

rupture and oil in tanks will be thrown out through the vent. One

pressure equalizer pipe is provided between explosion vent and the

conservator to maintain equal pressure in the empty spaces of vent

and conservator. In this case oil level indicator is provided on the

explosion vent to indicate rupture of bottom diaphragm.

Skid under base

Skid under base with haulage holes is provided at the bottom of tank.

The holes provided in the under base arrangement are suitable for

towing the complete transformer.

Junction Box

Terminal blocks are provided in the box to take the incoming and

outgoing cable leads from various instruments fitted on transformers

e.g. Buchholz relay, Winding temperature indicator, Oil temperature

indicator, Magnetic oil gauge etc. Box is provided with Blank gland

mounting plate, which should be drilled suitably to receive glands.

Temperature indicators with capillary tubes and electrical contacts are

mounted inside the box, when asked for.

4.6.7 Selection Criteria

Power transformers may be either autotransformers or multi winding

conventional transformers. A three-phase installation may consist of a

three-phase unit or three single-phase units. The decision as to what

type of transformer to purchase depends on such factors as initial

installed cost, maintenance costs, operating cost (efficiency), reliability,

etc. Three-phase units have lower construction and maintenance costs

and can be built to the same efficiency ratings as single-phase units.

The initial cost of a three-phase transformer is usually approximately

one-third less than four single-phase units. Additionally, the exposure

of three-phase units to long outages can be minimized system-wide

when a mobile substation or transformer is available for backup in case

of failure.

The MVA ratings for various sizes of transformers are covered by the

standards e.g Manual on Transformers (CBIP Publication), IEEE Std.

The selection of substation transformer MVA capacity should also be

based on an acceptable up-to-date engineering study. The selection

should consider the effects of load cycle, load factor, and ambient

temperature.

The choice between conventional two or three-winding transformers

and autotransformers involves their basic differences as they may

affect the application and cost factors. In general, autotransformers are

considered primarily because of cost advantages where the voltage

transformation ratio is favourable, up to possibly 3/1.

Other advantages of autotransformers are smaller physical size, lighter

weight, lower regulation (voltage drop in transformer), smaller exciting

currents (easier no-load switching), and lower losses. The main

disadvantages of autotransformers are lower reactance (impedance),

more complex design problems, and adverse affect on ground relaying.

These problems can usually be resolved.

4.6.8 Testing And Commissioning

It is important that tests shall be carried out to ensure reliable and

efficient performance of the transformer during its lifetime. The

followings tests are carried out on transformers as per national /

international standards.

Routine Tests

1. Voltage Ratio Measurement

2. Winding Resistance Measurement

3. Insulation Resistance & Polarization Index Measurement

4. Capacitance and tan delta Measurement of winding & bushings

5. Load Loss & Short circuit Impedance Measurement

6. Magnetic Balance & Magnetizing Current Measurement

7. Measurement of Vector Group Test

8. Full Wave Lightning Impulse Test on windings

9. Transfer Surge Test

10. Induced Over Voltage withstand Test with PD measurement

11. No- Load Loss & No Load Current Measurement

12. Test on OLTC

13. Auxiliary Loss measurement

14. Sweep Frequency Response Measurement

15. 2.5 kV AC insulation Test

16. Dimensional Verification

17. Test on PRD

18. Oil Leakage Test

19. Over excitation Test

20. High Voltage withstand test on auxiliary equipment & wiring after

assembly

21. Gas-in-oil analysis

Type Tests

1. Temperature Rise (Heat Run) Test

2. Zero Phase Sequence Impedance Measurement

3. Sound Level measurement

4. Harmonics measurements

5. Lightning Impulse Test on Neutral

6. Dynamic Short circuit Test

7. Tank vacuum & Pressure Test

Pre Commissioning Test at Site

1. Voltage Ratio Measurement

2. Winding Resistance Measurement at all taps

3. Insulation Resistance & Polarization Index Measurement

4. Capacitance and tan delta Measurement of winding & bushings

5. Magnetic Balance & Magnetizing Current Measurement

6. Measurement of No-load current with 415V,50 Hz AC on LV side

7. Measurement of Vector Group Test

8. Test on Oil

9. DGA of oil just before commissioning and after 24 hours energization

at site.

10. Observation of the transformer operation at no load for 24 hours.

11. FRA test

4.6.9 Oil Testing & DGA

Insulating oil which is also known as mineral oil is used as coolant as

well insulating medium in transformer & Reactors. Crude oil is the raw

material from which Insulating oil is produced. Following are the types

of insulating oil.

Crude oil – Divided into two (Light and Heavy)

Paraffinic (rich in gas oil, gasoline, and gases, light)

Naphthenic (rich in bitumen & heavy)

The insulating oil is tested to conform to all parameters specified

below, while tested against their acceptance norms as mentioned

below.

Sl.

No.

Property Test Method Limits

A

Function

1a Viscosity at 40degC ISO 3104 (Max.)12 mm2/s

1b Viscosity at -30degC ISO 3104 (Max.)1800 mm2/s

2 Appearance A representative

sample of the oil

shall be examined in

a 100 mm thick

layer, at ambient

temperature

The oil shall be

clear, transparent

and free from

suspended matter

or sediment

2 Pour point ISO 3016 (Max.)- 40degC

3 Water content

a) for bulk supply

b) for delivery in

Drums

IEC 60814

(Max.)

30 mg/kg

40 mg/kg

4 Electric strength

(breakdown voltage)

IEC 60156 (Min.) 30 kV/ 70 kV

(after

treatment)

5 Density at 20 deg C ISO 3675 or ISO

12185

(max)0.895 g/ml

6 Dielectric dissipation

factor (tan delta) at

90 deg C

IEC 60247 or IEC

61620

(Max)0.005

B Refining / Stability

1 Acidity IEC 62021-1 (Max)0.01 mg

KOH/g

2 Interfacial tension at

27degC

ISO 6295 (Min)0.04 N/m

Total sulfur content BS 2000 part 373 or

ISO

14596

0.15 %

3 Corrosive

sulphur

CIGRE test method

(TF A2.32.01

Revision of tests

and specifications

for corrosive sulfur

in Transformer Oils)

Non-Corrosive

4 Presence of

oxidation

inhibitor

IEC 60666 Not detectable

5 2-Furfural content IEC 61198 Max 0.1 mg/kg

C Performance

1 Oxidation stability

-Total acidity

-Sludge

IEC 61125 (method

c)

Test duration 164 h

Max 0.3 mg KOH/g

Max 0.05 %

2 Dielectric dissipation

factor (tan delta) at

90degC

IEC 60247 Max 0.05

3

Gassing IEC 60628 A No general

requirement,

however, negative

gassing

Tendency is not

acceptable.

D Health, Safety and

Environment (HSE)

1. Flash point ISO 2719 (Min.)135degC

2. PCA content BS 2000 Part 346 Max 3%

3. PCB

content

IEC 61619 Less than 1 mg/kg

4. Negative Impulse

testing KVp

ASTM D-3300 > 145

Prior to energisation at site, Oil shall be tested for following properties

& acceptance norms as per IS 1866 (2000):

1. BDV (kV rms) 70 kV (min.)

2. Moisture content 10 ppm (max.)

3. Tan-delta at 90degC 0.01 (max.)

4. Resistivity at 90degC 6 x 1012 ohm-cm (min.)

5. Interfacial Tension 35 mN/m (min.)

Dissolved Gas Analysis is a very powerful technique to find out

incipient faults within the transformer. Certain gases are produced by

decomposition of oil and/or paper insulation when transformer

undergoes abnormal thermal or electrical stresses. These gases come

out and get collected in buchholz relay when their quantity is more. But

when the fault is in very small area or if the severity of fault is less

these gases get dissolved in oil. As the composition and quantity of the

gases generated is dependent on type and severity of the fault, regular

monitoring of these dissolved gases reveals useful information about

healthiness of a transformer and prior information of fault can be had

observing the trend of various gas contents.

Information from the analysis of the gases dissolved in insulating oils is

valuable in a preventive maintenance program. Data from a DGA can

provide:

1. Advance warning of developing faults

2. A determination of the improper use of units

3. Status checks on new and repaired units

4. Low detection limits

5. Improved reproducibility

6. Detection of faults during the warranty period

7. Essential information for your Asset Management program

8. Recommendations for Additional Tests or Inspections

4.6.10 Fault gases are classified into three groups.

1. HYDROCARBONS AND HYDROGEN

METHANE CH4 ETHANE C2H6

ETHYLENE C2H4 ACETYLENE C2H2

HYDROGEN H2

2. CARBON OXIDES

CARBON MONOXIDE CO

CARBON DIAOXIDE CO2

3. NON-FAULT GASES

NITROGEN N2 OXYGEN 02

FAULT GASES AND TYPE OF FAULT

1. CORONA

A) OIL H2

B) CELLULOSE H2, CO, CO2

2. PYROLYSIS LOW TEMP. HIGH TEMP.

A) OIL CH4, C2H6 C2H4, H2 (CH4, C2H2)

B) CELLULOSE CO2 (CO) CO (CO2)

3. ARCING H2, C2H2 (CH4, C2H6, C2H4)

The solubility of gases in transformer oil by volume is given below.

HYDROGEN 7.0% (LEAST SOLUBLE)

NITROGEN 8.6%

CARBON MONOXIDE 9.0%

OXYGEN 16.0%

METHANE 30.0%

CARBONDIAOXIDE 120.0%

ETHANE 280.0%

ETHYLENE 280.0%

ACETYLENE 400.0 %( MOST SOLUBLE)

4.6.11 Failure analysis and DGA

1. Instantaneous failures like flashover with power flow through cannot be

prevented by DGA.

2. Serious failures, developing within Seconds cannot be detected by

DGA.

Broken or loose connection in a winding which lead to small arc which

burns the solid insulation

Deteriorated conductor insulation paper leading to inter turn fault

Broken loose or damaged draw rod in a bushing causing sparking and

arcing within tube

Bushing explosion leading to fire

3. Detectable faults by DGA

Within winding

Shorting of parallel wires in a bunch conductor within a common paper

covering

Lost potential connections to shielding rings, torroids- floating

potentials, sparking to grounds

Conditions partial discharges between discs or conductors due to

contaminated local oil-leading to flashover

Cleats and leads

Bolted connections, particularly between aluminium bus bars, if the

spring washers do not sustain the needed high pressure

All gliding moving contacts forming bad joints due to ageing

In the tank

Heating of tank part, bolt etc. Due to magnetic field

Overheating due to double grounding of the core

Damaged insulation between cover support point due to closed loop

Selector switch

Carbonisation of selector switch contacts and hotspot formation

Gap between selector switch contacts

Cores

Shorting at burrs of laminations

Failure of bolt insulation

DGA interpretation is done by various methods mentioned in CIGRE

guidelines, IEEE STD. C57.104 -1991.

4.7 EHV Circuit Breakers

Circuit Breakers (CB) are the switching and current interrupting devices.

Basically a circuit breaker comprises a set of fixed and movable contacts. The

contacts can be separated by means of an operating mechanism. The

separation of current carrying contacts produces an arc. The arc is

extinguished by a suitable medium such as dielectric oil, air vacuum and SF6

gas. The CBs are necessary at every switching point in the substation.

A circuit interrupting device operates in an electrical environment which

imposes a unique set of criteria on the device. There are three major

operating conditions - Closed, Open and the transition from closed to open. In

the closed position the device must conduct the continuous rated current

without exceeding the temperature limits. While closed, the complete

insulation system is stressed by system voltage and transient over voltage

caused by lightening, switching and system changes. In open position,

insulation across the open contacts is stressed in addition to the insulation to

ground.

If fault occurs, the Circuit Breaker is expected to interrupt the fault

current within rated interrupting time to minimize any disturbances to the

system. At some point during the opening operation the current is interrupted,

resulting in an electrical separation of the system at the Circuit Breaker

location. Immediately after current zero, the contacts are stressed by transient

voltages produced by the system as it reacts to the new operating state.

Additional requirements are inductive and capacitive current switching by

limiting over voltages within allowable limits.

These wide varieties of operating conditions impose conflicting constraints on

a circuit breaker.

The part of CB connected in one phase is called the pole. A circuit breaker

suitable for 3 phase system is called triple pole CB. Each pole of CB

comprises one or more interrupters or arc extinguishing chambers.

4.7.1 Basic Design

Circuit Breakers are classified in following categories based on arc

quenching medium.

1. AIR BREAK CIRCUIT BREAKER

2. BULK OIL CIRCUIT BREAKER

3. MINIMUM OIL CIRCUIT BREAKER

4. AIR BLAST CIRCUIT BREAKER

5. SULPHER HEXAFLOURIDE (SF6) CIRCUIT BREAKER

6. VACUUM CIRCUIT BREAKER

AIR BREAK CIRCUIT BREAKER

In the air break circuit breakers, the contact separating and arc

extinction takes place in air at atmospheric pressure. As the contacts

are opened, arc is drawn between them. By cooling the arc, the

diameter of arc core is reduced; the arc is extinguished by lengthening

the arc, cooling the arc, splitting the arc. The arc resistance is

increased to such an extent that the system voltage can not maintain

the arc and arc gets extinguished.

BULK OIL CIRCUIT BREAKER

Oil used as an arc extinguishing medium and dielectric material. The

contact separation takes place in steel tanks filled with oil. The gases

formed due to the heat of the arc expand and set the turbulent flow in

the oil.

Arc is extinguished by the virtue of following process.

1) Cooling of arc – The heat of the arc is carried away by the gas.

2) Turbulent flow of oil

3) Rapid building of dielectric strength.

4) High pressure gas has better dielectric strength.

To assist the arc extinction process arc control devices are fitted to the

contact assembly (these are semi-enclosed chamber of dielectric

materials).

In the bulk oil Circuit breaker as a large quantity of oil is required for

clearance between the earthed tank and the live parts within the tank.

For rated voltages above 72.5 kV bulk oil circuit breaker become bulky,

difficult to transport erect and maintain.

MINIMUM OIL CIRCUIT BREAKER (MOCB)

In MOCB current interruption takes place inside “interrupters”. The

enclosure of the interrupter is made of insulating material like porcelain.

Hence the clearance between the live parts and the enclosure can be

reduced and lesser quantity of oil required for internal insulation.

Two chambers separated from each other but both filled with oil, upper

chamber is arc extinction chamber, lower chamber acts like a dielectric

support.

AIR BLAST CIRCUIT BREAKER (ABCB)

In ABCB high pressure, air 20 kg /cm² – 30 kg /cm² is forced on the arc

through a nozzle at the instant of contact separation. The ionized

medium between the contacts is blown away by the blast of the air.

After the arc extinction the chamber is filled with high pressure air

which prevents restrike.

Opening and closing are fast – because air takes a negligible time to

travel from reservoir to the moving contact. The arc is extinguished

within a cycle (Fast in breaking the current).Problem of current

chopping and re-ignition in case of small current breaking.

VACUUM CIRCUIT BREAKER

A metallic bellow is fixed to the moving contact so that housing can be

sealed and the movement of the movable contact can be permitted.

The chamber is evacuated to high vacuum of the order of 10ˉ5 mm of

mercury. The high vacuum has high dielectric strength and is good arc

extinguishing medium. After arc extinction dielectric strength of vacuum

is recovered at a very fast rate.

4.7.2 Selection Criteria And Constructional Details of Circuit

Breakers

Selection Criteria

The selection of the type of circuit breakers is governed mainly by the

following important factors:

1. Use of pre-insertion resistors (PIR) to control the switching surge

over-voltage

2. Requirement of inherent restrike-free operation under all conditions

3. Consistent characteristics ;

4. Simple and reliable mechanism ;

5. Operating speed ;

6. Ease in maintenance ;

7. Reliability and life of plant in view of future developments.

Use of Pre – insertion Resistors:

The importance of pre-insertion resistor in reducing over-voltages is of

extreme significance and is well-known. It must, therefore, have the

greatest reliability so far as switching-in action is concerned. Failure of

this item will mean outage of breaker besides the possible damage

which might result due to over voltages. The sequence of operation,

control of insertion time and synchronizing the complete action are

matters of great precision.

Requirement of inherent Re-strike free operation under all conditions:

The principal requirement of a circuit breaker for 400kV system is its

inherent ability to interrupt the charging current of the line.

The world practice is towards such design whose characteristics are

well defined. To this category comes the SF6 breaker whose

performance practically for all types of duties out class air blast. The

natural choice is SF6 breakers.

Simple and reliable mechanism:

The performance of circuit breaker depends quite a lot upon the

operating mechanism to close and open the contacts.

Operating Speed:

Not only from the considerations of transient stability but also because

of less system disturbances, less damage to the plant involved in a

fault and less wear and tear on the breaker contacts, shorter total

break time has been preferred. The high speed breakers have

assumed special importance both in the weak system having remotely

situated power station loosely connected and in the system stiffly

connected with strong sources. It is felt that reliability and high speed

operation must go together.

The other importance aspect is of pole span. The influence of non-

synchronous opening and closing of three poles when higher than five

millisecond is quite significant and is considered important from over-

voltages due to energization and re-energization. With increase in pole

span the over voltages are higher but after a certain limit there is no

noticeable increase. This occurs when all the unfavorable closing

moments are with in the pole span. With closing resistors it must,

however, be ensured that pre-insertion time is more than pole span of

the breakers.

Maintenance problem:

It has been the experience that most of the equipment induced major

failures has been caused by the mal functioning of very minor

components owning to defects which originated during equipment

design and modification stages. The second factor contributing to

trouble has been the installation problem. The lack of good

workmanship and skill causes many inherent failures.

4.7.3 Constructional details of Circuit Breaker

Interrupter

Interrupter houses the fixed, moving and arcing contacts and the

linkage mechanism for operating moving contacts.

Fig: 4.16 Interrupting chamber

Main Contacts conduct the current in closed position of the breaker. It

has low contact resistance and is silver plated. Arcing contact are hard,

heat resistant and are usually of copper alloy. While opening the

contacts, the main contacts dislodge first. The current is shifted to the

arcing contacts. The arcing contacts dislodge later and arc is drawn

between them. This arc is forced upwards by the electro-magnetic

forces and thermal action. The arc ends travel along the arc runner

(arcing horns). The arc moves upwards and is split by arc splitter

plates. The arc is extinguished by the lengthening, cooling, splitting. In

some breakers, the arc is drawn in the direction of the splitter by

magnetic field.

There are different types of interrupters depending upon the type of

nozzle design and arc extinction method:

1. Mono blast

2. Double blast

3. Partial double blast

4. Self blast

5. Double motion type

Grading capacitor is connected across the individual contacts of

interrupters with multiple breaks to ensure equal distribution of voltage

across individual contacts.

Where ever required, the closing resistor or Pre insertion resistor (PIR)

chambers also are attached along with the Interrupting Chamber. PIR

is generally used on CBs meant for switching of long transmission lines

or capacitor banks to control the switching over voltages

SUPPORT COLUMN

It is used for live tank type CB only. It houses the operating rod which

is an insulated rod connecting operating mechanism with Interrupter.

OPERATING MECAHNISM

Operating mechanism drive including trip coil, closing coil, auxiliary

switch etc.

TYPES OF OPERATING MECHANISM

a) Spring assisted motor mechanism

b) Pneumatic operating mechanism

c) Hydraulic mechanism

d) Combination of spring & pneumatic mechanisms.

a) Motor is used for charging the closing spring (manual charging in

addition to motor charging).

b) Preferred stations where compressed air supply is available i.e., where

air blast circuit breakers are installed.

c) Compressed air at high pressure is used for closing High pressure air

is stored in the receiver of the breaker. Air comes to reservoir from

compressed air system. While closing the air at high pressure (15 – 30

kg/cm²) is admitted in the Pneumatic cylinder.

d) Hydraulic mechanism motor driven hydraulic pump accumulators

- Hydraulic valves and piping.

- Oil tank

- Hydraulic cylinder piston

(Oil is maintained at high pressure in the accumulators 200 – 300

kg/cm²) Piston movement with high pressure by opening of hydraulic

valves.

CONTROL & MONITORING DEVICES

SF6 gas density monitor, pressure gauges, counter etc. control cubicle/

Marshalling box.

PUMPS & COMPRESSORS

Pumps, Compressors, drives etc., for the operating mechanism.

SOME FEATURES OF CIRCUIT BREAKERS:

POLE DESCRIPANCY

This feature is introduced to detect cases in which one or more poles of

a 3 phase CB remains in open condition where as the other poles are

closed. This may arise due to mal-operation or sluggish operation of

one or more poles. It essentially is a timer connected to a series

parallel connection of Auxiliary switch.

ANTI PUMPING

Anti pumping feature blocks the closing of a CB more than once

(multiple closing) with a single pro-longed closing impulse (say, the

operator keeps on giving a closing impulse without releasing the

closing handle).

AUTO RECLOSE

Circuit Breaker shall be capable of performing auto-reclose operation in

case of a transient fault.

LOCK OUTS AND ALARMS

- SF6 alarm and L/O

- Operating mechanism alarm / lock out

- Trip circuit supervision

CB OPERATION PHYLOSOPHY

1. CB shall be suitable for operation from Remote (control

Room/Remote control centre) as well as from local MB depending on

position of Local/Remote switch. The protection trip will be normally

directly extended (bypassing local selection)

2. Two trip coils and one close coils normally provided.

3. No interlocks from other equipments like Isolator and Earth switch for

local trip. But CB local close normally allowed only if associated earth

switches are closed.

4. For remote closing and required interlocks from other equipments like

Isolator and Earth switch are provided from CR panels.

5. Auto-reclose is done from CR panels only.

4.7.4 Properties of SF6 Gas

PHYSICAL PROPERTIES

- Colourless, Odourless, non-toxic and non-flammable.

- BOILING POINT = - 60° at atm. (760 mm)

- Sonic conductivity of SF6 is low (Speed of sound) = 138.5 m/s i.e.,

41% of that in air

CHEMICAL PROPERTY

- SF6 is chemically inert upto 150° C and will not attack metals, plastics

and other substances commonly used in the construction of H.V.

Circuit breaker.

- However, at the high temperature caused by Power arcs it

decomposes into various components (SF4, SF2 etc. and Fluorine).

- Complete absence of carbon in the SF6 molecule major advantage for

an arc interrupting medium.

- All the chemically active impurities formed by the arc at various

temperature recombine in the extremely short time of 10-10 seconds

after extinction of the arc.

- Remaining traces of impurities can be to eliminate by means of

absorbing material (activated alumina).

- Alumina also absorbs moisture and contribute to the SF6 stability.

- Absence of air eliminates contact oxidation. Contact abrasion

extremely small compared to contact in air.

- Contact service life is greatly increased and replacement is rarely

necessary.

ELECTRIC PROPERTY

- Ability to recover dielectric strength quickly after arc extinction (electro-

negative gas).

- (Electrons of electronegative gases get attached to the molecules and

thereby the dielectric strength of the gas is regained).

4.7.5 Testing of Circuit Breaker

Governing standards for testing CB in general are IEC-60694, and 62271-100.

A) TYPE TESTS

1. Insulation Tests :

a. Power Frequency withstand

b. Lightning Impulse withstand

c. Switching Impulse Withstand

2. Short Time Current

3. Temperature Rise Test

4. Mechanical Endurance Test (Duty M1 & M2)

5. Electrical Endurance (for distribution class )

6. Short Circuit tests

7. Capacitive Current switching tests.(line charging/cable charging)

8. Capacitive Current switching Duty C1 & C2

9. Reactor switching test.

10. Seismic withstand test

11. RIV/Corona extinction voltage tests.

12. Special tests –

- Critical current test

- Low and high temperature test

- Out of phase closing test

- Power Frequency withstand at zero gauge pressure & at lockout

pressure with CB in open condition (POWERGRID specification

requirement).

4.7.6 Salient Features Of Powergrid Specification

Applicable Standard – 62271 -100

Only SF6 type

C1-M1 class.

Solidly earthed system considered.

First pole to clear factor (depends on System earthing) - 1.3(for solidly earthed system).

CB suitable for auto-reclosures and for out of phase closing.

PIR for 400kV line breakers.

Shunt Reactor switching for 400kV CBs.

Guaranteed SF6 leakage 1% per year.

Separate SF6 monitoring for each poles for 145kV and above.

Operating duty – 0-0.3S – CO – 3 min. – CO.

S.C. rating – 40KA (for 400kV & 220KV)

31.5 kA for 145KV

Line charging interruption Capability – 600A for 420kV, 125A for 245kV (IEC), 50A for 145kV (IEC).

Operating Mechanism – Pneumatic/Spring/Hydraulic.

Aux. DC (220V) supply variation – 70 -110% for trip of 85 – 110% for close.

2 Independent trip circuits, each having separate pressure switches.