training report

PROJECT

‘TRANSMISSION AND CONTROLLING OF POWER IN

GRID’

OBJECTIVES

1. To study the need of power transmission.

2. To study the need of control of power transmission.

3. To study the application of SCADA in power transmission.

CONTROL ROOM OF 400KV SUBSTN, SAROJINI NGR.

BRIEF HISTORY

The power system in the country is operated and controlled on a regional basis. Each region comprises a mix of state utilities, central sector generating and transmission utilities, independent power producers and other agencies that play an important role in the integrated grid operation. The requirement to bring out a code, which lays down the rules, guidelines and standards to be followed by all such agencies, was being felt for quite some time.

A comprehensive document against such requirement had been released in December 1999, in the form of the Indian Electricity Grid Code (IEGC) by Power Grid Corporation of India Ltd. in its capacity as the Central Transmission Utility (CTU) and in line with the Central Electricity Regulatory Commission’s (CERC) orders dated 21st

December 1999. The IEGC brings together the different terms, encompassing all the utilities connected

to / or using the Inter-State Transmission System (ISTS) and provides documentation in regard to relationship between various users of the ISTS. It lays down the rules and guidelines for planning, development, operation and maintenance of the grid in an efficient, reliable and economical manner.

The Uttar Pradesh Government has declared UP Power Corporation Limited (UPPCL) as State Transmission Utility (STU) under section 27-B of Indian Electricity Act, 1910. As per the Indian Electricity Act, 1910 following are the functions of State Transmission Utility toa. Undertake transmission of energy through intra-State transmission system;b. Discharge all functions of planning and coordination relating to intra-State transmission system with -

Central Transmission Utility;

State Governments;

Generating companies;

Regional Electricity Boards;

Authority;

Licensees;

Transmission licensees;

Any other person notified by the State Government in this behalf.

c. The State Transmission utility shall exercise supervision and control over the intra-State transmission system.

d. The State Transmission Utility shall comply with and ensure compliance by others in that State of the directions which the Central Transmission Utility may give from time to time in connection with the integrated grid operations and operation of the power system or otherwise in regard to matters which affect the operation of the inter-State transmission system.

ORGANISATIONAL CHART

SYSTEM PLANT LAYOUT

GRID MAP OF UTTAR PRADESH

(Courtesy: Er. S.M.Zainvi)

SINGLE LINE DIAGRAM OF 400KV SUBSTATION

SAROJINI NAGAR, LUCKNOW

ACTIVITIES

POWERGRID:-POWERGRID, the Central Transmission Utility (CTU) of the country is engaged

in power transmission business with the mandate for planning, co-ordination, supervision and control over complete inter-State transmission system. POWERGRID, as on July 2009, owns and operates about 71,600 ckt kms of transmission lines at 800/765 kV, 400 kV, 220 kV & 132 kV EHVAC & +500 kV HVDC levels and 122 sub-stations with transformation capacity of about 81,200 MVA. This gigantic transmission network, spread over length and breadth of the country, is consistently maintained at an availability of over 99% through deployment of state-of-the-art Operation & Maintenance techniques which are at par with global standards. About 45% of total power generated in the country is wheeled through this transmission network.

Ministry of Power, Government of India is envisaging addition of about 78,700 MW during XI Plan. Accordingly, transmission system is being planned by POWERGRID with an investment about Rs. 55,000 Crore in the XI Plan.

POWERGRIDs achievements have been continuously been praised in terms of awards from GoI and various other agencies. The Company recently received Three National Awards for meritorious performance in the field of Transmission sector for system availability and early completion of project for the year 2007-08, All India Organization of Employers Industrial Relations award 2007-08, and IEEMA Power Awards 2009 for “Excellence in Power Transmission”. Further, POWERGRID has been conferred the “The First DSIJ PSU Awards 2009” by Dalal Street Group of Publications for being “one of the largest transmission utilities in the world”.

NLDC:-National Load Dispatch Centre (NLDC) has been constituted as per Ministry of

Power (MOP) notification, New Delhi dated 2nd March 2005 and is the apex body to ensure integrated operation of the national power system.

The main functions assigned to NLDC are:

1. Supervision over the Regional Load Dispatch Centres. 2. Scheduling and dispatch of electricity over the inter-regional links in accordance with

grid standards specified by the authority and grid code specified by Central Commission in coordination with Regional Load Dispatch Centres.

3. Coordination with Regional Load Dispatch Centres for achieving maximum economy and efficiency in the operation of National Grid.

4. Monitoring of operations and grid security of the National Grid. 5. Supervision and control over the inter-regional links as may be required for ensuring

stability of the power system under its control.

Connection b/w different Load Dispatch Centres

6. Coordination with Regional Power Committees for regional outage schedule in the national perspective to ensure optimal utilization of power resources.

7. Coordination with Regional Load Dispatch Centres for the energy accounting of inter-regional exchange of power.

8. Coordination for restoration of synchronous operation of national grid with Regional Load Dispatch Centres.

9. Coordination for trans-national exchange of power.10. Providing Operational feedback for national grid

planning to the Authority and Central Transmission Utility.

11. Levy and collection of such fee and charges from the generating companies or licensees involved in the power system, as may be specified by the Central Commission.

12. Dissemination Of information relating to operations of transmission system in accordance with directions or regulations issued by Central Government from time to time.

NRLDC:-Northern Region Load Dispatch Centre (NRLDC)

is the apex body to ensure integrated operation of the power system in the Northern Region. The main responsibilities of NRLDC are:

1. System parameters and security.2. To ensure the integrated operation of the power

system grid in the region.3. System studies, planning and contingency analysis.4. Analysis of tripping/disturbances and facilitating

immediate remedial measures.5. Daily scheduling and operational planning.6. Facilitating bilateral and inter-regional exchanges.7. Computation of energy dispatch and drawl values using SEMs.8. Augmentation of telemetry, computing and communication facilities.

SLDC:-In accordance with section 32 of Electricity Act, 2003, the State Load Dispatch Centre

(SLDC) shall have following functions: (1) The State Load Dispatch Centre shall be the apex body to ensure integrated operation

of the power system in a State. (2) The State Load Dispatch Centre shall -

NLDC

NRLDC

SLDC

Sub LDC

Sub Station

a) Be responsible for optimum scheduling and dispatch of electricity within a State, in accordance with the contracts entered into with the licensees or the generating companies operating in that State;

b) Monitor grid operations; c) Keep accounts of the quantity of electricity transmitted through the State grid; d) Exercise supervision and control over the intra-State transmission system; and e) Be responsible for carrying out real time operations for grid control and dispatch

of electricity within the State through secure and economic operation of the State grid in accordance with the Grid Standards and the State Grid Code.

In accordance with section 33 of the Electricity Act, 2003 the State Load Dispatch Centre in a State may give such directions and exercise such supervision and control as may be required for ensuring the integrated grid operations and for achieving the maximum economy and efficiency in the operation of power system in that State. Every licensee, generating company, generating station, sub-station and any other person connected with the operation of the power system shall comply with the directions issued by the State Load Dispatch Centre under sub-section (1) of Section 33 of the Electricity Act, 2003. The State Load Dispatch Centre shall comply with the directions of the Regional Load Dispatch Centre. .

In case of inter-state bilateral and collective short-term open access transactions having a state utility or an intra-state entity as a buyer or a seller, SLDC shall accord concurrence or no objection or a prior standing clearance, as the case may be, in accordance with the Central Electricity Regulatory Commission (Open Access in inter-state Transmission) Regulations, 2008, amended from time to time.

STU:-Section 39 of the Electricity Act, 2003, outlines that the functions of the State

Transmission Utility (STU) shall be –

(1)a) To undertake transmission of electricity through intra-State transmission system; b) To discharge all functions of planning and co-ordination relating to intra-state

transmission system with- i. Central Transmission Utility;

ii. State Governments;iii. generating companies;iv. Regional Power Committees;v. Authority;

vi. licensees;vii. any other person notified by the State in this behalf;

c) To ensure development of an efficient, coordinated and economical system of intra-State transmission lines for smooth flow of electricity from a generating station to the load centers;

d) To provide non-discriminatory open access to its transmission system for use by -

i. Any licensee or generating company on payment of the transmission charges; or ii. Any consumer as and when such open access is provided by the state

commission under sub-section (2) of section 42 of the act, on payment of the transmission charges and a surcharge thereon, as may be specified by the state commission.

(2) Until a Government company or any authority or corporation is notified by the State Government, the State Transmission Utility shall operate the State Load Dispatch Centre.

SUBSTATION:-An electrical substation is a subsidiary station of an electricity generation,

transmission and distribution system where voltage is transformed from high to low or the reverse using transformers. Electric power may flow through several substations between generating plant and consumer, and may be changed in voltage in several steps.

A substation that has a step-up transformer increases the voltage while decreasing the current, while a step-down transformer decreases the voltage while increasing the current for domestic and commercial distribution. The word substation comes from the days before the distribution system became a grid. The first substations were connected to only one power station where the generator was housed, and were subsidiaries of that power station.

Power Sector at a Glance "ALL INDIA"As on 31-05-2010 Source: CEA

1.Total Installed Capacity: Power for All by 2012

Sector MW %age

State Sector 80,525.12 52.5

Central Sector 50,992.63 34.0

Private Sector 29,834.05 13.5

Total 1,61,351.80

Fuel MW %age

Total Thermal 103448.98 64.6

                                             Coal 85,193.38 53.3

                                             Gas 17,055.85 10.5

NOTE:-Renewable Energy Sources (RES) include SHP, BG, BP, U&I and Wind Energy.

                                             Oil 1,199.75 0.9

Hydro (Renewable) 36,913.40 24.7

Nuclear 4,560.00 2.9

RES** (MNRE) 16,429.42 7.7

Total 1,61,351.80

Abbreviation:--- SHP= Small Hydro Project BG= Biomass Gas fire BP= Biomass Power U & I=Urban & Industrial

Water Power RES=Renewable Sources.

PRODUCT FLOW CHART

Electric power transmission or "high voltage electric transmission" is the bulk transfer of electrical energy, from generating power plants to substations located near to population centers. This is distinct from the local wiring between high voltage substations and customers, which is typically referred to as electricity distribution. Transmission lines, when interconnected with each other, become high voltage transmission networks. In the INDIA, these are typically referred to as "power grids" or sometimes simply as "the grid". 

Historically, transmission and distribution lines were owned by the same company, but over the last decade or so many countries have introduced market reforms that have led to

the separation of the electricity transmission business from the distribution business.

Transmission lines mostly use three phase alternating current (AC), although single phase AC is sometimes used in railway electrification systems. High-voltage direct current (HVDC) technology is used only for very long distances (typically greater than 400 miles, or 600 km); undersea cables (typically longer than 30 miles, or 50 km); or for connecting two AC networks that are not synchronized.

Electricity is transmitted at high voltages (32 kV or above) to reduce the energy lost in long distance transmission. Power is usually transmitted through overhead power lines. Underground power transmission has a significantly higher cost and greater operational limitations but is sometimes used in urban areas or sensitive locations.

A key limitation in the distribution of electricity is that, with minor exceptions, electrical energy cannot be stored, and therefore it must be generated as it is needed. A sophisticated system of control is therefore required to ensure electric generation very closely

Diagram of an electrical system.

matches the demand. If supply and demand are not in balance, generation plants and transmission equipment can shut down which, in the worst cases, can lead to a major regional blackout, such as occurred in India in 2000, California and the US Northwest in 1996 and in the US Northeast in 1965, 1977 and 2003. To reduce the risk of such failures, electric transmission networks are interconnected into regional, national or continental wide networks thereby providing multiple redundant alternate routes for power to flow should (weather or equipment) failures occur. Much analysis is done by transmission companies to determine the maximum reliable capacity of each line which is mostly less than its physical or thermal limit, to ensure spare capacity is available should there be any such failure in another part of the network.

YARD OF A SUB STATION

GENERATIONOVERVIEW

The annual growth in power generation during 10th Plan period and the first two year of 11th Plan has been as under:

10th PlanGrowth in Achievement(%)

2002-03 3.12003-04 5.02004-05 5.22005-06 5.12006-07 7.311th Plan2007-08 6.32008-09 2.7

The growth in electricity generation during 2008-09 was constrained due to unsatisfactory performance of some of new thermal generating units commissioned during 2006-07 and 2007-08, delay in commissioning of new units during 2008-09, long outages, shortage of coal/gas/nuclear fuel, poor hydrology, etc.

TRANSMISSIONOverview

The Government of India has an ambitious mission of ‘POWER FOR ALL BY 2012’. This mission would require that our installed generation capacity should be at least 2, 00,000 MW by 2012 from the present level of 1, 14,000 MW. To be able to reach this power to the entire country an expansion of the regional transmission network and inter regional capacity to transmit power would be essential. The latter is required because resources are unevenly distributed in the country and power needs to be carried great distances to areas where load centres exist.

The transmission system planning in the country, in the past, had traditionally been

linked to generation projects as part of the evacuation system. Ability of the power system to safely withstand a contingency without generation rescheduling or load-shedding was the main criteria for planning the transmission system. However, due to various reasons such as spatial development of load in the network, non-commissioning of load centre generating units originally planned and deficit in reactive compensation, certain pockets in the power system could not safely operate even under normal conditions. This had necessitated backing down of generation and operating at a lower load generation balance in the past. Transmission planning has therefore moved away from the earlier generation evacuation system planning to integrated system planning.

While the predominant technology for electricity transmission and distribution has been Alternating Current (AC) technology, High Voltage Direct Current (HVDC) technology has also been used for interconnection of all regional grids across the country and for bulk transmission of power over long distances.

Certain provisions in the Electricity Act 2003 such as open access to the transmission and distribution network, recognition of power trading as a distinct activity, the liberal definition of a captive generating plant and provision for supply in rural areas are expected to introduce and encourage competition in the electricity sector. It is expected that all the above measures on the generation, transmission and distribution front would result in formation of a robust electricity grid in the country.

DISTRIBUTIONOverview

However, due to lack of adequate investment on T&D works, the T&D losses have been consistently on higher side, and reached to the level of 32.86% in the year 2000-01.The reduction of these losses was essential to bring economic viability to the State Utilities.

As the T&D loss was not able to capture all the losses in the net work, concept of

Aggregate Technical and Commercial (AT&C) loss was introduced. AT&C loss captures technical as well as commercial losses in the network and is a true indicator of total losses in the system.

High technical losses in the system are primarily due to inadequate investments over the years for system improvement works, which has resulted in unplanned extensions of the distribution lines, overloading of the system elements like transformers and conductors, and lack of adequate reactive power support.

The commercial losses are mainly due to low metering efficiency, theft & pilferages. This may be eliminated by improving metering efficiency, proper energy accounting & auditing and improved billing & collection efficiency. Fixing of accountability of the personnel / feeder managers may help considerably in reduction of AT&C loss.

With the initiative of the Government of India and of the States, the Accelerated Power Development & Reform Programme (APDRP) was launched in 2001, for the strengthening of Sub Transmission and Distribution network and reduction in AT&C losses.

The main objective of the programme was to bring Aggregate Technical & Commercial (AT&C) losses below 15% in five years in urban and in high-density areas. The programme, along with other initiatives of the Government of India and of the States, has led to reduction in the overall AT&C loss from 38.86% in 2001-02 to 34.54% in 2005-06. The commercial loss of the State Power Utilities reduced significantly during this period from Rs. 29331 Crore to Rs. 19546 Crore. The loss as percentage of turnover was reduced from 33% in 2000-01 to 16.60% in 2005-06.

The APDRP programme has been restructured by the Government of India, in order that reliable and verifiable baseline data of revenue and enegry in APDRP Project areas is attained over an IT plateform and that AT& C loss reduction is achieved on a sustained basis. The Restructured APDRP (R-APDRP) was launched by MoP, Gol in July 2008 as a central sector scheme for XI plan. The scheme comprises of two parts-Part-A & Part-B, Part-A of the scheme being dedicated to establishment of IT enabled system for achieving reliable & verifiable baseline data system in all towns with population greater than 30,000 as per 2001 census (10,000 for Special Category Status). Installation of SCADA/DMS for towns with population greater than 4 lakhs & annual input energy greater than 350MU is also envisaged under Part-A. 100% loan is provided under R-APDRP for Part-A projects & shall be converted to grant on completion and verification of same by Third Party independent

evaluating agencies (TPIEA) being appointed by MoP. MoP, Gol has earmarked Rs. 10,000 Crores for R-APDRP Part-A.

Part-B of the scheme deals with regular Sub Transmission & Distribution system strengthening & upgradation projects.The focus for Part-B is on AT&C loss reduction on sustainable basis.25% loan is provided under Part-B projects and upto 50% of scheme cost is convertible to grant depending on extent of maintaining AT&C loss level at 15% level for five years. For special category states, 90% loan is provided by GOI for Part-b projects and entire GOI loan shall be converted to grant in five tranches depending on extent of maintaining AT&C loss level at 15% level for five years. MoP , Gol has earmarked sanctioning of schemes upto Rs. 40,000 Crores under R-APDRP Part-B. Of this, upto Rs. 20,000 Crore would be converted to grant depending on extent to which utilities reduce AT&C losses in project areas.

R-APDRP also has provision for Capacity Building of Utility personnel and development of franchises through Part-C of the scheme. Few pilot projects adopting innovations are also envisaged under Part-C.

CHRONOLOGICALTRAINING DIARY

FIRST 2 WEEKS (14/06/2010 TO 27/06/2010)

400KV SUBSTATION AT SAROJINI NAGAR, LUCKNOW

Electrical substation

A 50 Hz electrical substation. This is showing 3 of the 5 220 kV/66 kV transformers each with a capacity of 185 MVA.(in fig.)

An electrical substation is a subsidiary station of an electricity generation, transmission and distribution system where voltage is transformed from high to low or the reverse using transformers. Electric power may flow through several substations between generating plant and consumer, and may be changed in voltage in several steps.

A substation that has a step-up transformer increases the voltage while decreasing the current, while a step-down transformer decreases the voltage while increasing the current for domestic and commercial distribution. The word substation comes from the days before the distribution system became a grid. The first substations were connected to only one power station where the generator was housed, and were subsidiaries of that power station.

Elements of a substationFormer electrical substation inWashington, D.C. used by the United States Navy during World War I and World War II.(in fig.)

Substations generally have switching, protection and control equipment and one or more transformers. In a large substation, circuit breakers are used to interrupt anyshort-circuits or overload currents that may occur on the network. Smaller distribution stations may use recloser circuit breakers or fuses for protection of distribution circuits. Substations do not

usually have generators, although a power plant may have a substation nearby. Other devices such as power factor correction capacitors and voltage regulators may also be located at a substation.

Substations may be on the surface in fenced enclosures, underground, or located in special-purpose buildings. High-rise buildings may have several indoor substations. Indoor substations are usually found in urban areas to reduce the noise from the transformers, for reasons of appearance, or to protect switchgear from extreme climate or pollution conditions.Where a substation has a metallic fence, it must be properly grounded (UK: earthed) to protect people from high voltages that may occur during a fault in the network. Earth faults at a substation can cause a ground potential rise. Currents flowing in the Earth's surface during a fault can cause metal objects to have a significantly different voltage than the ground under a person's feet; this touch potential presents a hazard of electrocution.

Transmission substationA transmission substation connects two or more transmission lines. The simplest

case is where all transmission lines have the same voltage. In such cases, the substation contains high-voltage switches that allow lines to be connected or isolated for fault clearance or maintenance. A transmission station may have transformers to convert between two transmission voltages, voltage control devices such as capacitors, reactors or static VAr compensator and equipment such as phase shifting transformers to control power flow between two adjacent power systems.

Transmission substations can range from simple to complex. A small "switching station" may be little more than a bus plus some circuit breakers. The largest transmission substations can cover a large area (several acres/hectares) with multiple voltage levels, many circuit breakers and a large amount of protection and control equipment (voltage and current transformers, relays and SCADA systems). Modern substations may be implemented using International Standards such as IEC61850.

A 115 kV to 41.6/12.47 kV 5 MVA 60 Hz substation with circuit switcher, regulators, reclosers and control building.(in fig.)

Distribution substation

A distribution substation disguised as a house, complete with a driveway, front walk and a mown lawn and shrubs in the front yard. A warning notice can be clearly seen on the "front door". (in fig.)

A distribution substation transfers power from the transmission system to the distribution system of an

area. It is uneconomical to directly connect electricity consumers to the high-voltage main transmission network, unless they use large amounts of power, so the distribution station reduces voltage to a value suitable for local distribution.

The input for a distribution substation is typically at least two transmission or subtransmission lines. Input voltage may be, for example, 115 kV, or whatever is common in the area. The output is a number of feeders. Distribution voltages are typically medium voltage, between 2.4 and 33 kV depending on the size of the area served and the practices of the local utility.

The feeders will then run overhead, along streets (or under streets, in a city) and eventually power the distribution transformers at or near the customer premises.

Besides changing the voltage, the job of the distribution substation is to isolate faults in either the transmission or distribution systems. Distribution substations may also be the points of voltage regulation, although on long distribution circuits (several km/miles), voltage regulation equipment may also be installed along the line.

Complicated distribution substations can be found in the downtown areas of large cities, with high-voltage switching, and switching and backup systems on the low-voltage side. More typical distribution substations have a switch, one transformer, and minimal facilities on the low-voltage side.

Collector substationIn distributed generation projects such as a wind farm, a collector substation may be

required. It somewhat resembles a distribution substation although power flow is in the opposite direction, from many wind turbines up into the transmission grid. Usually for economy of construction the collector system operates around 35 kV, and the collector substation steps up voltage to a transmission voltage for the grid. The collector substation can also provide power factor correction if it is needed, metering and control of the wind farm. In some special cases a collector substation can also contain an HVDC static inverter plant.Collector substations also exist where multiple thermal or hydroelectric power plants of comparable output power are in proximity. Examples for such substations are Brauweiler in Germany and Hradec in the Czech Republic, where power of lignite fired power plants nearby is collected. if no transformers are installed for increase of voltage to transmission level, the substation is a switching station.

Stations with change of current typeSubstations may be found in association with HVDC converter plants or, formerly,

where rotary converters changed frequency or interconnected non-synchronous networks.

Substations for railway suppliesSubstations for railway supplies are most often distribution substations. In some cases

a conversion of the current type takes place, commonly with rectifiers for DC trains, or rotary converters for trains using AC other than that of the public grid. Sometimes they are also transmission substations or collector substations if the railway network also operates its own grid and generators.

Switching substationA switching substation is a substation which does not contain transformers and

operates only at a single voltage level. Switching substations are sometimes used as collector and distribution stations. Sometimes they are used for switching the current to back-up lines or for paralellizing circuits in case of failure. Example herefore are the switching stations at HVDC Inga-Shaba.

DesignThe main issues facing a power engineer are reliability and cost. A good design

attempts to strike a balance between these two, to achieve sufficient reliability without excessive cost. The design should also allow easy expansion of the station, if required.

Selection of the location of a substation must consider many factors. Sufficient land area is required for installation of equipment with necessary clearances for electrical safety, and for access to maintain large apparatus such as transformers. Where land is costly, such as in urban areas, gas insulated switchgear may save money overall. The site must have room for expansion due to load growth or planned transmission additions. Environmental effects of the substation must be considered, such as drainage, noise and road traffic effects. Grounding (earthing) and ground potential rise must be calculated to protect passers-by during a short-circuit in the transmission system. And of course, the substation site must be reasonably central to the distribution area to be served.

LayoutSubstation set in wild parkland in North

London, United Kingdom (in fig.)The first step in planning a substation layout is the

preparation of a one-line diagram which shows in simplified form the switching and protection arrangement required, as well as the incoming supply lines and outgoing feeders or transmission lines. It is a usual practice by many electrical utilities to prepare one-line diagrams with principal elements (lines, switches, circuit breakers, and transformers) arranged on the page similarly to the way the apparatus would be laid out in the actual station.

Incoming lines will almost always have a disconnect switch and a circuit breaker. In some cases, the lines will not have both; with either a switch or a circuit breaker being all that is considered necessary. A disconnect switch is used to provide isolation, since it cannot interrupt load current. A circuit breaker is used as a protection device to interrupt fault currents automatically, and may be used to switch loads on and off. When a large fault current flows through the circuit breaker, this may be detected through the use of current transformers. The magnitude of the current transformer outputs may be used to 'trip' the circuit breaker resulting in a disconnection of the load supplied by the circuit break from the feeding point. This seeks to isolate the fault point from the rest of the system, and allow the rest of the system to continue operating with minimal impact. Both switches and circuit

breakers may be operated locally (within the substation) or remotely from a supervisory control center.

Once past the switching components, the lines of a given voltage connect to one or more buses. These are sets of bus bars, usually in multiples of three, since three-phase electrical power distribution is largely universal around the world.

The arrangement of switches, circuit breakers and buses used affects the cost and reliability of the substation. For important substations a ring bus, double bus, or so-called "breaker and a half" setup can be used, so that the failure of any one circuit breaker does not interrupt power to branch circuits for more than a brief time, and so that parts of the substation may be de-energized for maintenance and repairs. Substations feeding only a single industrial load may have minimal switching provisions, especially for small installations.

Once having established buses for the various voltage levels, transformers may be connected between the voltage levels. These will again have a circuit breaker, much like transmission lines, in case a transformer has a fault (commonly called a 'short circuit').Along with this, a substation always has control circuitry needed to command the various breakers to open in case of the failure of some component.

Switching functionAn important function performed by a substation is switching, which is the

connecting and disconnecting of transmission lines or other components to and from the system. Switching events may be "planned" or "unplanned".

A transmission line or other component may need to be de-energized for maintenance or for new construction; for example, adding or removing a transmission line or a transformer.

To maintain reliability of supply, no company ever brings down its whole system for maintenance. All work to be performed, from routine testing to adding entirely new substations, must be done while keeping the whole system running.

Perhaps more importantly, a fault may develop in a transmission line or any other component. Some examples of this: a line is hit by lightning and develops an arc, or a tower is blown down by a high wind. The function of the substation is to isolate the faulted portion of the system in the shortest possible time.

There are two main reasons: a fault tends to cause equipment damage; and it tends to destabilize the whole system. For example, a transmission line left in a faulted condition will eventually burn down, and similarly, a transformer left in a faulted condition will eventually blow up. While these are happening, the power drain makes the system more unstable. Disconnecting the faulted component, quickly, tends to minimize both of these problems.

Substation Design and Layout

The First Step in designing a Substation is to design an Earthing and Bonding System.

EARTHING AND BONDINGThe function of an earthing and bonding system is to provide an earthing system

connection to which transformer neutrals or earthing impedances may be connected in order to pass the maximum fault current. The earthing system also ensures that no thermal or mechanical damage occurs on the equipment within the substation, thereby resulting in safety to operation and maintenance personnel. The earthing system also guarantees equi-potential bonding such that there are no dangerous potential gradients developed in the substation.

In designing the substation, three voltages have to be considered.

1. Touch Voltage: This is the difference in potential between the surface potential and the potential at an earthed equipment whilst a man is standing and touching the earthed structure.

2. Step Voltage: This is the potential difference developed when a man bridges a distance of 1m with his feet while not touching any other earthed equipment.

3. Mesh Voltage: This is the maximum touch voltage that is developed in the mesh of the earthing grid.

Substation Earthing Calculation Methodology

Calculations for earth impedances and touch and step potentials are based on site measurements of ground resistivity and system fault levels. A grid layout with particular conductors is then analyzed to determine the effective substation earthing resistance, from which the earthing voltage is calculated.

In practice, it is normal to take the highest fault level for substation earth grid calculation purposes. Additionally, it is necessary to ensure a sufficient margin such that expansion of the system is catered for.

To determine the earth resistivity, probe tests are carried out on the site. These tests are best performed in dry weather such that conservative resistivity readings are obtained.

Earthing Materials

1. Conductors : Bare copper conductor is usually used for the substation earthing grid. The copper bars themselves usually have a cross-sectional area of 95 square millimeters, and they are laid at a shallow depth of 0.25-0.5m, in 3-7m squares. In addition to the buried potential earth grid, a separate above ground earthing ring is usually provided, to which all metallic substation plant is bonded.

2. Connections : Connections to the grid and other earthing joints should not be soldered because the heat during fault conditions could cause a soldered joint to fail. Joints are usually bolted, and in this case, the face of the joints should be tinned.

3. Earthing Rods : The earthing grid must be supplemented by earthing rods to assist in the dissipation of earth fault currents and further reduce the overall substation earthing resistance. These rods are usually made of solid copper, or copper clad steel.

4. Switchyard Fence Earthing : The switchyard fence earthing practices are possible and are used by different utilities. These are:

i. Extend the substation earth grid 0.5m-1.5m beyond the fence perimeter. The fence is then bonded to the grid at regular intervals.

ii. Place the fence beyond the perimeter of the switchyard earthing grid and bond the fence to its own earthing rod system. This earthing rod system is not coupled to the main substation earthing grid.

Layout of SubstationThe layout of the substation is very important since there should be a Security of Supply.

In an ideal substation all circuits and equipment would be duplicated such that following a fault, or during maintenance, a connection remains available. Practically this is not feasible since the cost of implementing such a design is very high. Methods have been adopted to achieve a compromise between complete security of supply and capital investment. There are four categories of substation that give varying securities of supply:

Category 1: No outage is necessary within the substation for either maintenance or fault conditions.

Category 2: Short outage is necessary to transfer the load to an alternative circuit for maintenance or fault conditions.

Category 3: Loss of a circuit or section of the substation due to fault or maintenance.

Category 4: Loss of the entire substation due to fault or maintenance.

Different Layouts for Substations

Single BusbarThe general schematic for

such a substation is shown in the figure below.

With this design, there is an ease of operation of the substation. This design also places minimum reliance on signalling for satisfactory operation of protection. Additionally there is the facility to support the economical operation of future feeder bays.

Such a substation has the following characteristics.

Each circuit is protected by its own circuit breaker and hence plant outage does not necessarily result in loss of supply.

A fault on the feeder or transformer circuit breaker causes loss of the transformer and feeder circuit, one of which may be restored after isolating the faulty circuit breaker.

A fault on the bus section circuit breaker causes complete shutdown of the substation. All circuits may be restored after isolating the faulty circuit breaker.

A busbar fault causes loss of one transformer and one feeder. Maintenance of one busbar section or isolator will cause the temporary outage of two circuits.

Maintenance of a feeder or transformer circuit breaker involves loss of the circuit.

Introduction of bypass isolators between busbar and circuit isolator allows circuit breaker maintenance facilities without loss of that circuit.

Mesh SubstationThe general layout for a full mesh substation is shown in the schematic below.  The characteristics of such a substation are as follows.

Operation of two circuit breakers is required to connect or disconnect a circuit, and disconnection involves opening of a mesh.

Circuit breakers may be maintained without loss of supply or protection, and no additional bypass facilities are required.

Busbar faults will only cause the loss of one circuit breaker. Breaker faults will involve the loss of a maximum of two circuits.

Generally, not more than twice as many outgoing circuits as infeeds are used in order to rationalise circuit equipment load capabilities and ratings.

One and a half Circuit Breaker layout

The layout of a 1½ circuit breaker substation is shown in the schematic below.

The reason that such a layout is known as a 1½ circuit breaker is due to the fact that in the design, there are 9 circuit breakers that are used to protect the 6 feeders. Thus, 1½ circuit breaker protects 1 feeder. Some characteristics of this design are:

There is the additional cost of the circuit breakers together with the complex arrangement.

It is possible to operate any one pair of circuits, or groups of pairs of circuits.

There is a very high security against the loss of supply.

Principle of Substation LayoutsSubstation layout consists essentially in arranging a number of switchgear components in an ordered pattern governed by their function and rules of spatial separation.

Spatial Separation

Earth Clearance : this is the clearance between live parts and earthed structures, walls, screens and ground.

Phase Clearance : this is the clearance between live parts of different phases.

Isolating Distance : this is the clearance between the terminals of an isolator and the connections thereto.

Section Clearance : this is the clearance between live parts and the terminals of a work section. The limits of this work section, or maintenance zone, may be the ground or a platform from which the man works.

Separation of maintenance zonesTwo methods are available for separating equipment in a maintenance zone that has been isolated and made dead.

1. The provision of a section clearance.

2. Use of an intervening earthed barrier

The choice between the two methods depends on the voltage and whether horizontal or vertical clearances are involved.

A section clearance is composed of a reach of a man, taken as 8 feet, plus an earth clearance.

For the voltage at which the earth clearance is 8 feet, the space required will be the same whether a section clearance or an earthed barrier is used.

HENCE: Separation by earthed barrier = Earth Clearance + 50mm for barrier + Earth Clearance

Separation by section clearance = 2.44m + Earth clearance

For vertical clearances it is necessary to take into account the space occupied by the equipment and the need for an access platform at higher voltages.

The height of the platform is taken as 1.37m below the highest point of work.

Establishing Maintenance ZonesSome maintenance zones are easily defined and the need for them is self evident as is

the case of a circuit breaker. There should be a means of isolation on each side of the circuit breaker, and to separate it from adjacent live parts, when isolated, either by section clearances or earth barriers. 

Electrical Separations Together with maintenance zoning, the separation, by isolating distance and phase

clearances, of the substation components and of the conductors interconnecting them constitute the main basis of substation layouts.

There are at least three such electrical separations per phase that are needed in a circuit:

1. Between the terminals of the busbar isolator and their connections. 2. Between the terminals of the circuit breaker and their connections. 3. Between the terminals of the feeder isolator and their connections.  

Components of a SubstationThe substation components will only be considered to the extent where they influence substation layout.

CIRCUIT BREAKERSThere are two forms of open circuit breakers:

1. Dead Tank - circuit breaker compartment is at earth potential.

2. Live Tank - circuit breaker compartment is at line potential.

The form of circuit breaker influences the way in which the circuit breaker is accommodated. This may be one of four ways.

Ground Mounting and Plinth Mounting : the main advantages of this type of mounting are its simplicity, ease of erection, ease of maintenance and elimination of support structures. An added advantage is that in indoor substations, there is the reduction in the height of the building. A disadvantage however is that to prevent danger to personnel, the circuit breaker has to be surrounded by an earthed barrier, which increases the area required.

Retractable Circuit Breakers : these have the advantage of being space saving due to the fact that isolators can be accommodated in the same area of clearance that has to be allowed between the retractable circuit breaker and the live fixed contacts. Another advantage is that there is the ease and safety of maintenance. Additionally such a

mounting is economical since at least two insulators per phase are still needed to support the fixed circuit breaker plug contacts.

Suspended Circuit Breakers : at higher voltages tension insulators are cheaper than post or pedestal insulators. With this type of mounting the live tank circuit breaker is suspended by tension insulators from overhead structures, and held in a stable position by similar insulators tensioned to the ground. There is the claimed advantage of reduced costs and simplified foundations, and the structures used to suspend the circuit breakers may be used for other purposes.

CURRENT TRANSFORMERS

CT's may be accommodated in one of six manners:

Over Circuit Breaker bushings or in pedestals.

In separate post type housings.

Over moving bushings of some types of insulators.

Over power transformers of reactor bushings.

Over wall or roof bushings.

Over cables.

In all except the second of the list, the CT's occupy incidental space and do not affect the size of the layout. The CT's become more remote from the circuit breaker in the order listed above. Accommodation of CT's over isolator bushings, or bushings through walls or roofs, is usually confined to indoor substations. 

ISOLATORS

These are essentially off load devices although they are capable of dealing with small charging currents of busbars and connections. The design of isolators is closely related to the design of substations. Isolator design is considered in the following aspects:

Space Factor

Insulation Security

Standardisation

Ease of Maintenance

Cost

Some types of isolators include:

Horizontal Isolation types

Vertical Isolation types

Moving Bushing types

CONDUCTOR SYSTEMS

An ideal conductor should fulfil the following requirements:

Should be capable of carrying the specified load currents and short time currents.

Should be able to withstand forces on it due to its situation. These forces comprise self weight, and weight of other conductors and equipment, short circuit forces and atmospheric forces such as wind and ice loading.

Should be corona free at rated voltage.

Should have the minimum number of joints.

Should need the minimum number of supporting insulators.

Should be economical.

The most suitable material for the conductor system is copper or aluminium. Steel may be used but has limitations of poor conductivity and high susceptibility to corrosion.

In an effort to make the conductor ideal, three different types have been utilized, and these include:

Flat surfaced Conductors

Stranded Conductors

Tubular Conductors

INSULATION

Insulation security has been rated very highly among the aims of good substation design. Extensive research is done on improving flashover characteristics as well as combating pollution. Increased creepage length, resistance glazing, insulation greasing and line washing have been used with varying degrees of success.  

POWER TRANSFORMERS

EHV power transformers are usually oil immersed with all three phases in one tank. Auto transformers can offer advantage of smaller physical size and reduced losses. The different classes of power transformers are:

o.n.: Oil immersed, natural cooling

o.b.: Oil immersed, air blast cooling

o.f.n.: Oil immersed, oil circulation forced

o.f.b.: Oil immersed, oil circulation forced, air blast cooling

Power transformers are usually the largest single item in a substation. For economy of service roads, transformers are located on one side of a substation, and the connection to switchgear is by bare conductors. Because of the large quantity of oil, it is essential to take precaution against the spread of fire. Hence, the transformer is usually located around a sump used to collect the excess oil.

Transformers that are located and a cell should be enclosed in a blast proof room.  

400KV Line

220 KV Line

Overhead Line Terminations

Two methods are used to terminate overhead lines at a substation.

Tensioning conductors to substation structures or buildings

Tensioning conductors to ground winches.

The choice is influenced by the height of towers and the proximity to the substation.

CAPACITOR VOLTAGE TRANSFORMER

A capacitor voltage transformer (CVT), or capacitance coupled voltage transformer (CCVT) is a transformer used in power systems to step down extra high voltage signals and

CAPACITOR VOLTAGE TRANSFORMER (CVT)

WAVE TRAP REACTORS

TRANSFORMER CIRCUIT BREAKER

CURRENT TRANSFORMER (CT)

LINE ISOLATOR

provide a low voltage signal, for measurement or to operate a protectiverelay. In its most basic form the device consists of three parts: two capacitors across which the transmission line signal is split, an inductive element to tune the device to the line frequency, and a transformer to isolate and further step down the voltage for the instrumentation or protective relay. The device has at least four terminals: a terminal for connection to the high voltage signal, a ground terminal, and two secondary terminals which connect to the instrumentation or protective relay. CVTs are typically single-phase devices used for measuring voltages in excess of one hundred kilovolts where the use of voltage transformers would be uneconomical. In practice, capacitor C1 is often constructed as a stack of smaller capacitors connected in series. This provides a large voltage drop across C1 and a relatively small voltage drop across C2.

The CVT is also useful in communication systems. CVTs in combination with wave traps are used for filtering high frequency communication signals from power frequency. This forms a carrier communication network throughout the transmission network.

CURRENT TRANSFORMERIn electrical engineering, a current transformer (CT) is used

for measurement of electric currents. Current transformers, together with voltage transformers (VT) (potential transformers (PT)), are known as instrument transformers. When current in a circuit is too high to directly apply to measuring instruments, a current transformer produces a reduced current accurately proportional to the current in the circuit, which can be conveniently connected to measuring and recording instruments. A current transformer also isolates the measuring instruments from what may be very high voltage in the monitored circuit. Current transformers are commonly used in metering and protective relays in the electrical power industry.

DESIGNLike any other transformer, a current transformer has a primary

winding, a magnetic core, and a secondary winding. The alternating current flowing in the primary produces a magnetic field in the core, which then induces current flow in the secondary winding circuit. A

primary objective of current transformer design is to ensure that the primary and secondary circuits are efficiently coupled, so that the secondary current bears an accurate relationship to the primary current.

The most common design of CT consists of a length of wire wrapped many times around a silicon steel ring passed over the circuit being measured. The CT's primary circuit therefore consists of a single 'turn' of conductor, with a secondary of many hundreds of turns.

The primary winding may be a permanent part of the current transformer, with a heavy

copper bar to carry current through the magnetic core. Window-type current transformers are also common, which can have circuit cables run through the middle of an opening in the core to provide a single-turn primary winding. When conductors passing through a CT are not centered in the circular (or oval) opening, slight inaccuracies may occur.

Current transformers used in metering equipment for three-phase 400 ampere electricity supply (in fig.)

Shapes and sizes can vary depending on the end user or switchgear manufacturer. Typical examples of low voltage single ratio metering current transformers are either ring type or plastic moulded case. High-voltage

current transformers are mounted on porcelain bushings to insulate them from ground. Some CT configurations slip around the bushing of a high-voltage transformer or circuit breaker, which automatically centers the conductor inside the CT window.

The primary circuit is largely unaffected by the insertion of the CT. The rated secondary current is commonly standardized at 1 or 5 amperes. For example, a 4000:5 CT would provide an output current of 5 amperes when the primary was passing 4000 amperes. The secondary winding can be single ratio or multi ratio, with five taps being common for multi ratio CTs. The load, or burden, of the CT should be of low resistance. If the voltage time integral area is higher than the core's design rating, the core goes intosaturation towards the end of each cycle, distorting the waveform and affecting accuracy.

USAGECurrent transformers are used extensively for measuring current and monitoring the

operation of the power grid. Along with voltage leads, revenue-grade CTs drive the electrical utility's watt-hour meter on virtually every building with three-phase service, and every residence with greater than 200 amp service.

The CT is typically described by its current ratio from primary to secondary. Often, multiple CTs are installed as a "stack" for various uses. For example, protection devices and revenue metering may use separate CTs; stacking them provides severability while consolidating the high voltage interface. Similarly, potential transformers such as the CVT are used for measuring voltage and monitoring the operation of the power grid.

SAFETY PRECAUTIONSCare must be taken that the secondary of a current transformer is not disconnected

from its load while current is flowing in the primary, as the transformer secondary will attempt to continue driving current across the effectively infinite impedance. This will produce a high voltage across the open secondary (into the range of several kilovolts in some cases), which may cause arcing. The high voltage produced will compromise operator and equipment safety and permanently affect the accuracy of the transformer.

ACCURACYThe accuracy of a CT is directly related to a number of factors including: Burden

Burden class/saturation class Rating factor Load External electromagnetic fields Temperature  and Physical configuration. The selected tap, for multi-ratio CTsFor the IEC standard, accuracy classes for various types of measurement are set out in

IEC 60044-1, Classes 0.1, 0.2s, 0.2, 0.5, 0.5s, 1, and 3. The class designation is an approximate measure of the CT's accuracy. The ratio (primary to secondary current) error of a Class 1 CT is 1% at rated current; the ratio error of a Class 0.5 CT is 0.5% or less. Errors in phase are also important especially in power measuring circuits, and each class has an allowable maximum phase error for a specified load impedance. Current transformers used for protective relaying also have accuracy requirements at overload currents in excess of the normal rating to ensure accurate performance of relays during system faults.

BURDENThe load, or burden, in a CT metering circuit is the (largely resistive) impedance presented to its secondary winding. Typical burden ratings for IEC CTs are 1.5 VA, 3 VA, 5 VA, 10 VA, 15 VA, 20 VA, 30 VA, 45 VA & 60 VA with ANSI/IEEE B-0.1, B-0.2, B-0.5, B-1.0, B-2.0 and B-4.0. This means a CT with a burden rating of B-0.2 can tolerate up to 0.2 Ω of impedance in the metering circuit before its output current is no longer a fixed ratio to the primary current. Items that contribute to the burden of a current measurement circuit are switch-blocks, meters and intermediate conductors. The most common source of excess burden in a current measurement circuit is the conductor between the meter and the CT. Often, substation meters are located significant distances from the meter cabinets and the excessive length of small gauge conductor creates a large resistance. This problem can be solved by using CT with 1 ampere secondaries which will produce less voltage drop between a CT and its metering devices (used for remote measurement).

RATING FACTORRating factor is a factor by which the nominal full load current of a CT can be

multiplied to determine its absolute maximum measurable primary current. Conversely, the minimum primary current a CT can accurately measure is "light load," or 10% of the nominal current (there are, however, special CTs designed to measure accurately currents as small as 2% of the nominal current). The rating factor of a CT is largely dependent upon ambient temperature. Most CTs have rating factors for 35 degrees Celsius and 55 degrees Celsius. It is important to be mindful of ambient temperatures and resultant rating factors when CTs are installed inside pad-mounted transformers or poorly ventilated mechanical rooms. Recently, manufacturers have been moving towards lower nominal primary currents with greater rating factors. This is made possible by the development of more efficient ferrites and their corresponding hysteresis curves. This is a distinct advantage over previous CTs because it increases their range of accuracy, since the CTs are most accurate between their rated current and rating factor.

SPECIAL DESIGNSSpecially constructed wideband current transformers are also used (usually with

an oscilloscope) to measure waveforms of high frequency or pulsed currents within pulsed powersystems. One type of specially constructed wideband transformer provides a voltage output that is proportional to the measured current. Another type (called a Rogowski coil) requires an external integrator in order to provide a voltage output that is proportional to the measured current. Unlike CTs used for power circuitry, wideband CTs are rated in output volts per ampere of primary current.

STANDARDSDepending on the ultimate clients requirement, there are two main standards to which

current transformers are designed. IEC 60044-1 (BSEN 60044-1) & IEEE C57.13 (ANSI), although the Canadian & Australian standards are also recognised.

BUSBAR1500 ampere busbars within a power

distribution rack for a large building (in fig)In electrical power distribution, a busbar is a

thick strip of copper or aluminium that conducts electricity within a switchboard, distribution board, substation or other electrical apparatus. Busbars are used to carry very large currents, or to distribute current to multiple devices within switchgear or equipment. For example, a household circuit breaker panel board will have bus bars at the back, arranged for the connection of multiple branch circuit breakers. An aluminum smelter will have very large bus bars used to carry tens of thousands of amperes to the electrochemical cells that produce aluminum from molten salts.

The size of the busbar is important in determining the maximum amount of current that can be safely carried. Busbars can have a cross-sectional area of as little as 10 mm² but electrical substations may use metal tubes of 50 mm in diameter (1,963 mm²) or more as busbars.

DESIGN AND PLACEMENTBusbars are typically either flat strips or hollow tubes as these shapes allow heat to

dissipate more efficiently due to their high surface area to cross-sectional area ratio. The skin effect makes 50–60 Hz AC busbars more than about 8 mm (1/3 in) thick inefficient, so hollow or flat shapes are prevalent in higher current applications. A hollow section has higher stiffness than a solid rod of equivalent current-carrying capacity, which allows a greater span between busbar supports in outdoor switchyards.

A busbar may either be supported on insulators, or else insulation may completely surround it. Busbars are protected from accidental contact either by a metal enclosure or by elevation out of normal reach. Neutral busbars may also be insulated. Earth busbars are typically bolted directly onto any metal chassis of their enclosure. Busbars may be enclosed in a metal housing, in the form of bus duct or busway, segregated-phase bus, or isolated-phase bus.

Busbars may be connected to each other and to electrical apparatus by bolted or clamp connections. Often joints between high-current bus sections have matching surfaces that are silver-plated to reduce the contact resistance. At extra-high voltages (more than 300 kV) in outdoor buses, corona around the connections becomes a source of radio-frequency interference and power loss, so connection fittings designed for these voltages are used.

Bus duct penetration, awaiting firestop.

Electrical conduit and bus duct in abuilding at Texaco Nanticoke refinery inNanticoke, Ontario, 1980s.

Bus duct section subsequently used infire test of a firestop system, achieving a 2 hour fire-resistance rating.

VOLTAGE TRANSFORMERSVoltage transformers (VT) or potential transformers (PT) are another type of

instrument transformer, used for metering and protection in high-voltage circuits. They are designed to present negligible load to the supply being measured and to have a precise voltage ratio to accurately step down high voltages so that metering and protective relay equipment can be operated at a lower potential. Typically the secondary of a voltage transformer is rated for 69 V or 120 V at rated primary voltage, to match the input ratings of protection relays.

The transformer winding high-voltage connection points are typically labeled as H1, H2 (sometimes H0 if it is internally grounded) and X1, X2 and sometimes an X3 tap may be present. Sometimes a second isolated winding (Y1, Y2, Y3) may also be available on the same

voltage transformer. The high side (primary) may be connected phase to ground or phase to phase. The low side (secondary) is usually phase to ground.

The terminal identifications (H1, X1, Y1, etc.) are often referred to as polarity. This applies to current transformers as well. At any instant terminals with the same suffix numeral have the same polarity and phase. Correct identification of terminals and wiring is essential for proper operation of metering and protection relays.

Some meters operate directly on the secondary service voltages at or below 600 V. VTs are typically used for higher voltages (for example, 765 kV for power transmission), or where isolation is desired between the meter and the measured circuit.

CIRCUIT BREAKERA circuit breaker is an automatically-

operated electrical switch designed to protect an electrical circuit from damage caused by overload or short circuit. Its basic function is to detect a fault condition and, by interrupting continuity, to immediately discontinue electrical flow. Unlike a fuse, which operates once and then has to be replaced, a circuit breaker can be reset (either manually or automatically) to resume normal operation. Circuit breakers are made in varying sizes, from small devices that protect an individual household appliance up to large switchgear designed to protect high voltage circuits feeding an entire city.

Circuit breaker switchgear (in fig)

ORIGINSAn early form of circuit breaker was described by Thomas Edison in an 1879 patent

application, although his commercial power distribution system used fuses.[1] Its purpose was to protect lighting circuit wiring from accidental short-circuits and overloads.

OPERATIONAll circuit breakers have common features in their operation, although details vary

substantially depending on the voltage class, current rating and type of the circuit breaker.The circuit breaker must detect a fault condition; in low-voltage circuit breakers this is usually done within the breaker enclosure. Circuit breakers for large currents or high voltages are usually arranged with pilot devices to sense a fault current and to operate the trip opening mechanism. The trip solenoid that releases the latch is usually energized by a separate battery, although some high-voltage circuit breakers are self-contained with current transformers, protection relays, and an internal control power source.

Once a fault is detected, contacts within the circuit breaker must open to interrupt the circuit; some mechanically-stored energy (using something such as springs or compressed air) contained within the breaker is used to separate the contacts, although some of the energy

required may be obtained from the fault current itself. Small circuit breakers may be manually operated; larger units have solenoids to trip the mechanism, and electric motors to restore energy to the springs.

The circuit breaker contacts must carry the load current without excessive heating, and must also withstand the heat of the arc produced when interrupting the circuit. Contacts are made of copper or copper alloys, silver alloys, and other materials. Service life of the contacts is limited by the erosion due to interrupting the arc. Miniature and molded case circuit breakers are usually discarded when the contacts are worn, but power circuit breakers and high-voltage circuit breakers have replaceable contacts.

When a current is interrupted, an arc is generated. This arc must be contained, cooled, and extinguished in a controlled way, so that the gap between the contacts can again withstand the voltage in the circuit. Different circuit breakers use vacuum, air, insulating gas, or oil as the medium in which the arc forms. Different techniques are used to extinguish the arc including:

Lengthening of the arc

Intensive cooling (in jet chambers)

Division into partial arcs

Zero point quenching (Contacts open at the zero current time crossing of the AC waveform, effectively breaking no load current at the time of opening. The zero crossing occures at twice the line frequency i.e. 100 times per second for 50Hz ac and 120 times per second for 60Hz ac )

Connecting capacitors in parallel with contacts in DC circuits

Finally, once the fault condition has been cleared, the contacts must again be closed to restore power to the interrupted circuit.

ARC INTERRUPTIONMiniature low-voltage circuit breakers use air alone to extinguish the arc. Larger

ratings will have metal plates or non-metallic arc chutes to divide and cool the arc.  Magnetic blowout coils deflect the arc into the arc chute. In larger ratings, oil circuit breakers rely upon vaporization of some of the oil to blast a jet

of oil through the arc. Gas (usually sulfur hexafluoride) circuit breakers sometimes stretch the arc using a

magnetic field, and then rely upon the dielectric strength of the sulfur hexafluoride (SF6) to quench the stretched arc.

Vacuum  circuit breakers have minimal arcing (as there is nothing to ionize other than the contact material), so the arc quenches when it is stretched a very small amount (<2–3 mm). Vacuum circuit breakers are frequently used in modern medium-voltage switchgear to 35,000 volts.

Air circuit breakers may use compressed air to blow out the arc, or alternatively, the contacts are rapidly swung into a small sealed chamber, the escaping of the displaced air thus blowing out the arc.

Circuit breakers are usually able to terminate all current very quickly: typically the arc is extinguished between 30 ms and 150 ms after the mechanism has been tripped, depending upon age and construction of the device.

SHORT CIRCUIT CURRENTCircuit breakers are rated both by the normal current that are expected to carry, and

the maximum short-circuit current that they can safely interrupt.

Under short-circuit conditions, a current many times greater than normal can exist (see maximum prospective short circuit current). When electrical contacts open to interrupt a large current, there is a tendency for an arc to form between the opened contacts, which would allow the current to continue. This condition can create conductive ionized gasses and molten or vaporized metal which can cause further continuation of the arc, or creation of additional short circuits, potentially resulting in the explosion of the circuit breaker and the equipment that it is installed in. Therefore, circuit breakers must incorporate various features to divide and extinguish the arc.

In air-insulated and miniature breakers an arc chute structure consisting (often) of metal plates or ceramic ridges cools the arc, and magnetic blowout coils deflect the arc into the arc chute. Larger circuit breakers such as those used in electrical power distribution may use vacuum, an inert gas such as sulphur hexafluoride or have contacts immersed in oil to suppress the arc.

The maximum short-circuit current that a breaker can interrupt is determined by testing. Application of a breaker in a circuit with a prospective short-circuit current higher than the breaker's interrupting capacity rating may result in failure of the breaker to safely interrupt a fault. In a worst-case scenario the breaker may successfully interrupt the fault, only to explode when reset.

Miniature circuit breakers used to protect control circuits or small appliances may not have sufficient interrupting capacity to use at a panelboard; these circuit breakers are called "supplemental circuit protectors" to distinguish them from distribution-type circuit breakers.

STANDARD CURRENT RATINGSInternational Standard IEC 60898-1 and European Standard EN 60898-1 define

the rated current In of a circuit breaker for low voltage distribution applications as the current that the breaker is designed to carry continuously (at an ambient air temperature of 30 °C). The commonly-available preferred values for the rated current are 6 A, 10 A, 13 A, 16 A, 20 A, 25 A, 32 A, 40 A, 50 A, 63 A, 80 A and 100 A [3] (Renard series, slightly modified to include current limit of British BS 1363 sockets). The circuit breaker is labeled with the rated current inamperes, but without the unit symbol "A". Instead, the ampere figure is preceded by a letter "B", "C" or "D" that indicates the instantaneous tripping current, that is the minimum value of current that causes the circuit-breaker to trip without intentional time delay (i.e., in less than 100 ms), expressed in terms of In:

Type Instantaneous tripping current

B above 3 In up to and including 5 In

C above 5 In up to and including 10 In

D above 10 In up to and including 20 In

Kabove 8 In up to and including 12 In

For the protection of loads that cause frequent short duration (approximately 400 ms to 2 s) current peaks in normal operation.

Zabove 2 In up to and including 3 In for periods in the order of tens of seconds.For the protection of loads such as semiconductor devices or measuring circuits using current transformers.

TYPES OF CIRCUIT BREAKER

Front panel of a 1250 A air circuit breaker manufactured by ABB. This low voltage power circuit breaker can be withdrawn from its housing for servicing. Trip characteristics are configurable via DIP switches on the front panel. ( in fig)

Many different classifications of circuit breakers can be made, based on their features such as voltage class, construction type, interrupting type, and structural features.

Low voltage circuit breakers

Low voltage (less than 1000 VAC) types are common in domestic, commercial and industrial application, include:

MCB (Miniature Circuit Breaker)—rated current not more than 100 A. Trip characteristics normally not adjustable. Thermal or thermal-magnetic operation. Breakers illustrated above are in this category.

MCCB (Molded Case Circuit Breaker)—rated current up to 2500 A. Thermal or thermal-magnetic operation. Trip current may be adjustable in larger ratings.

Low voltage power circuit breakers can be mounted in multi-tiers in LV switchboards or switchgear cabinets.

The characteristics of LV circuit breakers are given by international standards such as IEC 947. These circuit breakers are often installed in draw-out enclosures that allow removal and interchange without dismantling the switchgear.

Large low-voltage molded case and power circuit breakers may have electrical motor operators, allowing them to be tripped (opened) and closed under remote control. These may form part of an automatic transfer switch system for standby power.

Low-voltage circuit breakers are also made for direct-current (DC) applications, for example DC supplied for subway lines. Special breakers are required for direct current because the arc does not have a natural tendency to go out on each half cycle as for alternating current. A

direct current circuit breaker will have blow-out coils which generate a magnetic field that rapidly stretches the arc when interrupting direct current.

Small circuit breakers are either installed directly in equipment, or are arranged in a breaker panel.Photo of inside of a circuit breaker (in fig)

MEDIUM-VOLTAGE CIRCUIT BREAKERSMedium-voltage circuit breakers rated between 1 and 72 kV may be assembled into

metal-enclosed switchgear line ups for indoor use, or may be individual components installed outdoors in a substation. Air-break circuit breakers replaced oil-filled units for indoor applications, but are now themselves being replaced by vacuum circuit breakers (up to about 35 kV). Like the high voltage circuit breakers described below, these are also operated by current sensing protective relays operated through current transformers. The characteristics of MV breakers are given by international standards such as IEC 62271. Medium-voltage circuit breakers nearly always use separate current sensors and protection relays, instead of relying on built-in thermal or magnetic overcurrent sensors.

Medium-voltage circuit breakers can be classified by the medium used to extinguish the arc: Vacuum circuit breaker—With rated current up to 3000 A, these breakers interrupt the

current by creating and extinguishing the arc in a vacuum container. These are generally applied for voltages up to about 35,000 V,[4] which corresponds roughly to the medium-voltage range of power systems. Vacuum circuit breakers tend to have longer life expectancies between overhaul than do air circuit breakers.

Air circuit breaker—Rated current up to 10,000 A. Trip characteristics are often fully adjustable including configurable trip thresholds and delays. Usually electronically controlled, though some models are microprocessor controlled via an integral electronic trip unit. Often used for main power distribution in large industrial plant, where the breakers are arranged in draw-out enclosures for ease of maintenance.

SF6 circuit breakers extinguish the arc in a chamber filled with sulfur hexafluoride gas.

Medium-voltage circuit breakers may be connected into the circuit by bolted connections to bus bars or wires, especially in outdoor switchyards. Medium-voltage circuit breakers in switchgear line-ups are often built with draw-out construction, allowing the breaker to be

removed without disturbing the power circuit connections, using a motor-operated or hand-cranked mechanism to separate the breaker from its enclosure.

HIGH-VOLTAGE CIRCUIT BREAKERS400 kV SF6 live tank circuit breakers (in fig)

Electrical power transmission networks are protected and controlled by high-voltage breakers. The definition of high voltage varies but in power transmission work is usually thought to be 72.5 kV or

higher, according to a recent definition by the International Electro-technical Commission (IEC).

High-voltage breakers are nearly always solenoid-operated, with current sensing protective relays operated through current transformers.

In substations the protection relay scheme can be complex, protecting equipment and busses from various types of overload or ground/earth fault.High-voltage breakers are broadly classified by the medium used to extinguish the arc.

Bulk oil

Minimum oil

Air blast

Vacuum SF 6

115 kV bulk oil circuit breaker (in fig)Some of the manufacturers are ABB, GE

(General Electric) , AREVA, Mitsubishi Electric, Pennsylvania Breaker, Siemens, Toshiba, Končar HVS, BHEL, CGL.Due to environmental and cost concerns over insulating oil spills, most new breakers use SF6 gas to quench the arc.

Circuit breakers can be classified as live tank, where the enclosure that contains the breaking mechanism is at line potential, or dead tankwith the enclosure at earth potential. High-voltage AC circuit breakers are routinely available with ratings up to 765 kV. 1200KV breakers are likely to come into market very soon.High-voltage circuit breakers used on transmission systems may be arranged to allow a single pole of a three-phase line to trip, instead of tripping all three poles; for some classes of faults this improves the system stability and availability.SULFUR HEXAFLUORIDE (SF6) HIGH-VOLTAGE CIRCUIT-BREAKERS

A sulfur hexafluoride circuit breaker uses contacts surrounded by sulfur hexafluoride gas to quench the arc. They are most often used for transmission-level voltages and may be incorporated into compact gas-insulated switchgear. In cold climates, supplemental heating or de-rating of the circuit breakers may be required due to liquefaction of the SF6 gas.

OTHER BREAKERS Breakers for protections against earth faults too small to trip an over-current device: Residual-current device  (RCD, formerly known as a residual current circuit breaker)

— detects current imbalance, but does not provide over-current protection. Residual current breaker with over-current protection  (RCBO) — combines the

functions of an RCD and an MCB in one package. In the United States and Canada, panel-mounted devices that combine ground (earth) fault detection and over-current

protection are called Ground Fault Circuit Interrupter (GFCI) breakers; a wall mounted outlet device providing ground fault detection only is called a GFI.

Earth leakage circuit breaker  (ELCB) — This detects earth current directly rather than detecting imbalance. They are no longer seen in new installations for various reasons.

Autorecloser  — A type of circuit breaker which closes again after a delay. These are used on overhead power distribution systems, to prevent short duration faults from causing sustained outages.

Polyswitch  (polyfuse) — A small device commonly described as an automatically resetting fuse rather than a circuit breaker.

LAST 2 WEEKS (28/06/2010 TO 13/07/2010)

RTU & SCADA AT SHAKTI BHAWAN

REMOTE TERMINAL UNITAn RTU, or Remote Terminal Unit is a microprocessor controlled electronic device

which interfaces objects in the physical world to a distributed control system or SCADA system by transmitting telemetry data to the system and/or altering the state of connected objects based on control messages received from the system.

ARCHITECTURE AND COMMUNICATIONSAn RTU monitors the field digital and analog parameters and transmits all the data to

the Central Monitoring Station. An RTU can be interfaced with the Central Station with different communication media (usually serial (RS232, RS485, RS422) or Ethernet). RTU can support standard protocols (Modbus, IEC 60870-5-101/103/104, DNP3, ICCP, etc.) to interface any third party software. In some control application RTU drives high current capacity relays to a digital output (or "DO") board to switch power on and off to devices in the field. The DO board switches voltage to the coil in the relay, which closes the high current contacts, which completes the power circuit to the device. An RTU can monitor analog inputs of different types including 4 to 20 milliamperes (4-20 mA), 0 to 10 V., -2.5V to 2.5V, 1 to 5V etc.; the RTU or host system then translates this raw data into the appropriate units such as gallons of water left or temperature before presenting the data to the user via the HMI or MMI.

RTUs differ from Programmable Logic Controllers (PLCs) in that RTUs are more suitable for wide geographical telemetry, often using wireless communications, while PLCs are more suitable for local area control (plants, production lines, etc.) where the system utilizes physical media for control. The IEC 61131 programming tool is more popular for use with PLCs, while RTUs often use proprietary programming tools....

SOFTWARE AND LOGIC CONTROLModern RTUs are usually capable of executing simple programs autonomously

without involving the host computers of the DCS or SCADA system to simplify deployment, and to provide redundancy for safety reasons. An RTU in a modern water management system will typically have code to modify its behavior when physical override switches on the RTU are toggled during maintenance by maintenance personnel. This is done for safety reasons; a miscommunication between the system operators and the maintenance personnel could cause system operators to mistakenly enable power to a water pump when it is being replaced, for example.

COMPARISON WITH OTHER CONTROL SYSTEMSRTUs, PLCs and DCS are increasingly beginning to overlap in responsibilities, and

many vendors sell RTUs with PLC-like features and vice versa. The industry has standardized on theIEC 61131-3 functional block language for creating programs to run on

RTUs and PLCs, although nearly all vendors also offer proprietary alternatives and associated development environments.

In addition, some vendors now supply RTUs with comprehensive functionality pre-defined, sometimes with PLC extensions and/or interfaces for configuration. See the MultiSmart pump station manager for a water/wastewater example.

Some suppliers of RTUs have created simple Graphical User Interfaces GUI to enable customers to configure their RTUs easily. Some examples are MoxGRAF from MOX Products for their MX602 Field Controller and PC-Link from Promosys Technology for their RTU-1, RTU-3 and RTU-8.

In some applications Dataloggers are used in similar applications.A Programmable automation controller (PAC) is a compact controller that combines

the features and capabilities of a PC-based control system with that of a typical PLC. PACs are deployed in SCADA systems to provide RTU and PLC functions. In many electrical substation SCADA applications, "distributed RTUs" use information processors or station computers to communicate with protective relays, PACS, and other devices for I/O, and communicate with the SCADA master in lieu of a traditional RTU.

APPLICATIONS

Oil and Gas remote instrumentation monitoring, (offshore platforms, onshore

oilwells). Networks of remote pump stations (wastewater collection, or for water supply). Hydro-graphic monitoring and control, (water supply, reservoirs, sewerage systems). Environmental monitoring  systems (pollution, air quality, emissions monitoring). Minesite monitoring applications. Protection supervision and data logging of Power transmission network Air traffic equipment such as navigation aids (DVOR, DME, ILS and GP) Outdoor warning sirens, in both controlling them, and sending back data for

verification of activation, anything broken, etc. American Signal offers this as CompuLert, and Federal Signal offers it, but isn't trademarked. Both can be setup to use DTMF or FSK for the data transport layer.

SCADASCADA stands for supervisory control and data acquisition. It generally refers to an

industrial control system: a computer system monitoring and controlling a process. The process can be industrial, infrastructure or facility-based as described below: Industrial processes  include those of manufacturing, production, power

generation, fabrication, and refining, and may run in continuous, batch, repetitive, or discrete modes.

Infrastructure processes may be public or private, and include water treatment and distribution, wastewater collection and treatment, oil and gas pipelines, electrical power transmission and distribution, Wind Farms, civil defense siren systems, and large communication systems.

Facility processes occur both in public facilities and private ones, including buildings, airports, ships, and space stations. They monitor and control HVAC, access, and energy consumption.

COMMON SYSTEM COMPONENTSA SCADA System usually consists of the following subsystems: A Human-Machine Interface or HMI is the apparatus which presents process data to a

human operator, and through this, the human operator monitors and controls the process. A supervisory (computer) system, gathering (acquiring) data on the process and sending

commands (control) to the process. Remote Terminal Units  (RTUs) connecting to sensors in the process, converting sensor

signals to digital data and sending digital data to the supervisory system. Programmable Logic Controller  (PLCs) used as field devices because they are more

economical, versatile, flexible, and configurable than special-purpose RTUs. Communication  infrastructure connecting the supervisory system to the Remote Terminal

Units.

SUPERVISION v/s CONTROLThere is, in several industries, considerable confusion over the differences between

SCADA systems and distributed control systems (DCS). Generally speaking, a SCADA system usually refers to a system that coordinates, but does not control processes in real time. The discussion on real-time control is muddied somewhat by newer telecommunications technology, enabling reliable, low latency, high speed communications over wide areas. Most differences between SCADA and DCS are culturally determined and can usually be ignored. As communication infrastructures with higher capacity become available, the difference between SCADA and DCS will fade.

SYSTEMS CONCEPTSThe term SCADA usually refers to centralized systems which monitor and control

entire sites, or complexes of systems spread out over large areas (anything between an industrial plant and a country). Most control actions are performed automatically by Remote Terminal Units ("RTUs") or by programmable logic controllers ("PLCs"). Host control functions are usually restricted to basic overriding or supervisory level intervention. For

example, a PLC may control the flow of cooling water through part of an industrial process, but the SCADA system may allow operators to change the set points for the flow, and enable alarm conditions, such as loss of flow and high temperature, to be displayed and recorded. The feedback control loop passes through the RTU or PLC, while the SCADA system monitors the overall performance of the loop.

Data acquisition begins at the RTU or PLC level and includes meter readings and equipment status reports that are communicated to SCADA as required. Data is then compiled and formatted in such a way that a control room operator using the HMI can make supervisory decisions to adjust or override normal RTU (PLC) controls. Data may also be fed to a Historian, often built on a

commodity Database Management System, to allow trending and other analytical auditing.SCADA systems typically implement a distributed database, commonly referred to as

a tag database, which contains data elements called tags or points. A point represents a single input or output value monitored or controlled by the system. Points can be either "hard" or "soft". A hard point represents an actual input or output within the system, while a soft point results from logic and math operations applied to other points. (Most implementations conceptually remove the distinction by making every property a "soft" point expression, which may, in the simplest case, equal a single hard point.) Points are normally stored as value-timestamp pairs: a value, and the timestamp when it was recorded or calculated. A series of value-timestamp pairs gives the history of that point. It's also common to store additional metadata with tags, such as the path to a field device or PLC register, design time comments, and alarm information.

HUMAN MACHINE INTERFACE

A Human-Machine Interface or HMI is the apparatus which presents process data to a human operator, and through which the human operator controls the process.

Typical Basic SCADA Animations (in fig)

An HMI is usually linked to the SCADA system's databases and software programs, to provide trending, diagnostic data, and management information such as scheduled maintenance procedures, logistic information, detailed schematics for a particular sensor or machine, and expert-system troubleshooting guides.The HMI system usually presents the information to the operating personnel graphically, in the form of a mimic diagram. This means that the operator can see a schematic representation of the plant being controlled. For example, a picture of a pump connected to a pipe can show the operator that the pump is running and how much fluid it is pumping through the pipe at the moment. The operator can then switch the pump off. The HMI software will show the flow rate of the fluid in the pipe decrease in real time. Mimic diagrams may consist of line graphics and schematic symbols to represent process elements, or may consist of digital photographs of the process equipment overlain with animated symbols.

The HMI package for the SCADA system typically includes a drawing program that the operators or system maintenance personnel use to change the way these points are represented in the interface. These representations can be as simple as an on-screen traffic light, which represents the state of an actual traffic light in the field, or as complex as a multi-projector display representing the position of all of the elevators in a skyscraper or all of the trains on a railway.

An important part of most SCADA implementations is alarm handling. The system monitors whether certain alarm conditions are satisfied, to determine when an alarm event has occurred. Once an alarm event has been detected, one or more actions are taken (such as the activation of one or more alarm indicators, and perhaps the generation of email or text messages so that management or remote SCADA operators are informed). In many cases, a SCADA operator may have to acknowledge the alarm event; this may deactivate some alarm indicators, whereas other indicators remain active until the alarm conditions are cleared. Alarm conditions can be explicit - for example, an alarm point is a digital status point that has either the value NORMAL or ALARM that is calculated by a formula based on the values in other analogue and digital points - or implicit: the SCADA system might automatically monitor whether the value in an analogue point lies outside high and low limit values associated with that point. Examples of alarm indicators include a siren, a pop-up box on a screen, or a coloured or flashing area on a screen (that might act in a similar way to the "fuel tank empty" light in a car); in each case, the role of the alarm indicator is to draw the operator's attention to the part of the system 'in alarm' so that appropriate action can be taken. In designing SCADA systems, care is needed in coping with a cascade of alarm events occurring in a short time, otherwise the underlying cause (which might not be the earliest event detected) may get lost in the noise. Unfortunately, when used as a noun, the word

'alarm' is used rather loosely in the industry; thus, depending on context it might mean an alarm point, an alarm indicator, or an alarm event.

HARDWARE SOLUTIONSSCADA solutions often have Distributed Control System (DCS) components. Use of

"smart" RTUs or PLCs, which are capable of autonomously executing simple logic processes without involving the master computer, is increasing. A functional block programming language, IEC 61131-3 (Ladder Logic), is frequently used to create programs which run on these RTUs and PLCs. Unlike a procedural language such as the C programming language or FORTRAN, IEC 61131-3 has minimal training requirements by virtue of resembling historic physical control arrays. This allows SCADA system engineers to perform both the design and implementation of a program to be executed on an RTU or PLC. A Programmable automation controller(PAC) is a compact controller that combines the features and capabilities of a PC-based control system with that of a typical PLC. PACs are deployed in SCADA systems to provide RTU and PLC functions. In many electrical substation SCADA applications, "distributed RTUs" use information processors or station computers to communicate with protective relays, PACS, and other devices for I/O, and communicate with the SCADA master in lieu of a traditional RTU.

Since about 1998, virtually all major PLC manufacturers have offered integrated HMI/SCADA systems, many of them using open and non-proprietary communications protocols. Numerous specialized third-party HMI/SCADA packages, offering built-in compatibility with most major PLCs, have also entered the market, allowing mechanical engineers, electrical engineers and technicians to configure HMIs themselves, without the need for a custom-made program written by a software developer.

Remote Terminal Unit (RTU)The RTU connects to physical equipment. Typically, an RTU converts the electrical

signals from the equipment to digital values such as the open/closed status from a switch or a valve, or measurements such as pressure, flow, voltage or current. By converting and sending these electrical signals out to equipment the RTU can control equipment, such as opening or closing a switch or a valve, or setting the speed of a pump.

Supervisory StationThe term "Supervisory Station" refers to the servers and software responsible for

communicating with the field equipment (RTUs, PLCs, etc), and then to the HMI software running on workstations in the control room, or elsewhere. In smaller SCADA systems, the master station may be composed of a single PC. In larger SCADA systems, the master station may include multiple servers, distributed software applications, and disaster recovery sites. To increase the integrity of the system the multiple servers will often be configured in a dual-redundant or hot-standby formation providing continuous control and monitoring in the event of a server failure.

Operational philosophyFor some installations, the costs that would result from the control system failing are

extremely high. Possibly even lives could be lost. Hardware for some SCADA systems is

ruggedized to withstand temperature, vibration, and voltage extremes, but in most critical installations reliability is enhanced by having redundant hardware and communications channels, up to the point of having multiple fully equipped control centres. A failing part can be quickly identified and its functionality automatically taken over by backup hardware. A failed part can often be replaced without interrupting the process. The reliability of such systems can be calculated statistically and is stated as the mean time to failure, which is a variant of mean time between failures. The calculated mean time to failure of such high reliability systems can be on the order of centuries.

Communication infrastructure and methodsSCADA systems have traditionally used combinations of radio and direct serial or

modem connections to meet communication requirements, although Ethernet and IP over SONET / SDH is also frequently used at large sites such as railways and power stations. The remote management or monitoring function of a SCADA system is often referred to as telemetry.

This has also come under threat with some customers wanting SCADA data to travel over their pre-established corporate networks or to share the network with other applications. The legacy of the early low-bandwidth protocols remains, though. SCADA protocols are designed to be very compact and many are designed to send information to the master station only when the master station polls the RTU. Typical legacy SCADA protocols include Modbus RTU, RP-570, Profibus and Conitel. These communication protocols are all SCADA-vendor specific but are widely adopted and used. Standard protocols are IEC 60870-5-101 or 104, IEC 61850 and DNP3. These communication protocols are standardized and recognized by all major SCADA vendors. Many of these protocols now contain extensions to operate over TCP/IP. It is good security engineering practice to avoid connecting SCADA systems to theInternet so the attack surface is reduced.

RTUs and other automatic controller devices were being developed before the advent of industry wide standards for interoperability. The result is that developers and their management created a multitude of control protocols. Among the larger vendors, there was also the incentive to create their own protocol to "lock in" their customer base. A list of automation protocols is being compiled here.

Recently, OLE for Process Control (OPC) has become a widely accepted solution for intercommunicating different hardware and software, allowing communication even between devices originally not intended to be part of an industrial network.

ENCHANCEMENT SCOPE OF INDUSTRY

POWER FOR ALL BY 2012

The Ministry of Power has set a goal - Mission 2012: Power for All. A comprehensive Blueprint for Power Sector development has been prepared

encompassing an integrated strategy for the sector development with following objectives:-

- Sufficient power to achieve GDP growth rate of 8% - Reliable of power - Quality power - Optimum power cost - Commercial viability of power industry - Power for all

Strategies to achieve the objectives:

Power Generation Strategy with focus on low cost generation, optimization of capacity utilization, controlling the input cost, optimisation of fuel mix, Technology upgradation and utilization of Non Conventional energy sources

Transmission Strategy with focus on development of National Grid including Interstate connections, Technology upgradation & optimization of transmission cost.

Distribution strategy to achieve Distribution Reforms with focus on System upgradation, loss reduction, theft control, consumer service orientation, quality power supply commercialization, Decentralized distributed generation and supply for rural areas.

Regulation Strategy aimed at protecting Consumer interests and making the sector commercially viable.

Financing Strategy to generate resources for required growth of the power sector.

Conservation Strategy to optimise the utilization of electricity with focus on Demand Side management, Load management and Technology upgradation to provide energy efficient equipment / gadgets.

Communication Strategy for political consensus with media support to enhance the genera; public awareness.

SUGGESTIONSDespite of such good performance and an all round development of the

Indian Power Sector, it has some drawbacks which are needed to be removed.I suggest the following methods which are needed to be analyzed and

sorted:

Right to equality should be followed- there should be no discrimination between the areas and societies under observation.

Routine checkups and proper servicing to the instruments are required to save from any big mishap.

Protective instruments should be replaced as per recommendations to ensure safety

Power line poles and wires should be regularly monitored to avoid electricity theft and accidents.

Rather sticking to the orthodox techniques, technologies should be updated.

CONCLUSION

The Uttar Pradesh Government has declared UP Power Corporation Limited (UPPCL) as State Transmission Utility (STU) under section 27-B of Indian Electricity Act, 1910. As per the Indian Electricity Act, 1910 following are the functions of State Transmission Utility to-

a) Undertake transmission of energy through intra-State transmission system;b) Discharge all functions of planning and coordination relating to intra-State transmission

system with -• Central Transmission Utility;• State Governments;• Generating companies;• Regional Electricity Boards;• Authority;• Licensees;• Transmission licensees;• Any other person notified by the State Government in this behalf.

c) The State Transmission utility shall exercise supervision and control over the intra-State transmission system.

d) The State Transmission Utility shall comply with and ensure compliance by others in that State of the directions which the Central Transmission Utility may give from time to time in connection with the integrated grid operations and operation of the power system or otherwise in regard to matters which affect the operation of the inter-State transmission system.

On the basis of preventive maintenance schedule and “perfect register” records, a committed work plan is prepared 24hrs ahead on the basis of priority of work and availability of manpower. Preventive maintenance of complicated nature is planned in general shift under the direct supervision of executive engineer. All annual overhaul works are pre planed to ensure the availability of spares and resources for the sub station. So, 400 K V sub – station at Sarojini Nagar is good and efficient sub – station as per my study and knowledge.

References

1. SCADA Manuals Of Shakti Bhawan2. RTU Manuals Of Shakti Bhawan3. www.wikipedia.com 4. www.uppcl.org 5. www.ministryof power.org