PREFACE

The objective or main motive of this practical training is to getting a true practical knowledge about the industries, that how their industrial setups are held, and their communication techniques used in industry technologies to be made or used in the environment.This report is presented on the basis of practical training acquired in “SCADA/EMS” SLDC Section RRVPNL, Heerapura, Jaipur. This report is on with relevant diagrams & by their proper description & explanation.The term “SCADA(Supervisory control and data aquisition)/ EMS(Energy management system)” generally refers to an industrial control system : a computer system monitoring and controlling a process.The term “SCADA” usually refers to centralized systems which monitor and control entire sites,or cmplexes of system spread out over large area (anything between industrial plant and a country). In spite of all my best efforts some unintentional errors might have eluded, it is requested to abrogated them.

ACKNOLEDGEMENT

I am very grateful to Mr. M.P. Mathur (Assistant Engineer) & Mr. Dhiresh saini (Junior Engineer) for his very useful guidance, technical & much advantageous lectures . I would also like to express my sincere thanks towards SLDC Section, RRVPNL, Heerapura, Jaipur. for their co-ordination & support in problem solving . I am also thankful to Mr.Ashok sirohi (H.O.D.,Electronics & communication) because he encouraged me throughout the practical training and helped to understood correctly.

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CONTENTS

1. INTRODUCTION-THE NORTHERN REGION POWER

SYSTEM

1.1 Background

S.NO TOPIC PAGE NO.

1Introduction-The northern region power system

4

2Current institutional and operational problems in the northern region

8

3Operational & control philosophy

15

4Principle for Data Aquisition

21

5Data processing system of control centers

6DC system & AC auxillary power supply

7Total cost benefits of project

8 Conclusion

3

India has been divided into five Electricity Boards viz.,

southern, northern, western, eastern and north-eastern for the

purpose of power system planning and operation.

The Northern Regional Grid is composed of the generation,

transmission and distribution facilities of the following State

Electricity Boards and other national/regional agencies:

Himachal Pradesh Electricity Board (HPSEB)

Haryana State Electricity Board (HSEB)

Jammu & Kashmir (J&K) PDD

Punjab State Electricity Board (PSEB)

Rajasthan State Electricity Board (RSEB)

Uttar Pradesh Electricity Board (UPSEB)

Union Territory Of Chandigarh

Bhakra Beas Management Board (BBMB)

Delhi Electric Supply Undertaking (DESU)

Central Sector (CS), that is made up of:

Power Grid Corporation of India Limited (Powergrid)

National Thermal Power Corporation Limited (NTPC)

National Hydro-electric Power Corporation Limited (NHPC)

Nuclear Power Corporation (NPC)

Nathapa Jhakri Power Corporation (NJPC)

Tehri Hydro Development Corporation Limited (THDC)

Today, the Northern Regional Electricity Board (NREB) is

vested with the responsibility of coordinating smooth

4

integrated operation of the regional grid. The operation of

such a grid, spanning over such a large territory is technically

complex and all the more complicated as not less than 15

Boards or Agencies are involved in operation.

1.2 The Northern Regional Power System

1.2.1 The Constituents

The Northern Region comprises the power systems of

the constituents of Himachal Pradesh, Haryana, Punjab,

Rajasthan, Uttar Pradesh, Jammu & Kashmir plus the

Union Territories of Delhi and Chandigarh. While the

power systems of Haryana, Jammu & Kashmir, Punjab,

Rajasthan, and Uttar Pradesh have both hydro and

thermal power plants, Himachal Pradesh is purely a

hydro system. Besides the State power systems, in

1992 there were 5 Central Sector Power Agencies viz.

Powergrid, NTPC, NHPC, NPC and THDC.

1.2.2 Functions of NREB

The Northern Regional Electricity Board is today in

charge of co-ordinating the planning and operation of all

the constituents in the Northern Region, i.e., the five

State Electricity Boards, Jammu & Kashmir, Bhakra

Beas Management board, Delhi Electric Supply

Undertaking and Central Sector.

5

Central power stations are regional in character and

meant for the benefit of all the States of the Region.

Presently, power from a Central Power Station is

allocated to the various Constituents in accordance with

the following general agreed formula for sharing of

power:

1. 15% power is kept unallocated at the disposal of

Government of India to meet the urgent

requirement of the individual beneficiary States

from time to time.

2. 10% of the power is kept allocated to the State in

which the power station is located.

3. The remaining 75% power is distributed amongst

the beneficiary States (including the home State)

in accordance with the energy consumption of

these States and the Central Plan Assistance to

them.

One of its major duties of RSCC is to monitor the inter-

State Exchanges of power with reference to schedules

and control of net off-take of power and energy from

these Central projects.

1.2.3 The new role of the Power Grid Corporation of India

Limited

6

The government of India (GOI) recently agreed to

modify the scope of responsibilities for control facilities

and operation of the grid, which involves for the long

term: Powergrid as a developer, owner and operator of

transmission facilities and regional system co-ordination

and control systems; CEA as a regulator agency;

GOI agreed with a three-phase development for

Powergrid. During phase 1, CEA would continue to

operate the existing RSCCs (Regional Systems Control

Centres), while Powergrid takes over transmission

facilities from NTPC, NHPC, etc. and undertakes

projects to develop new RSCCs. Then Powergrid would

own and operate the project facilities and take over

related existing facilities from CEA not later than at the

completion of the project marking the commencement of

phase 2, viz. establishment/ augmentation of load

dispatch and communication facilities in various

Regions. During phase 1, Powergrid will need

immediate access to and use of the existing control

facilities at the Regional level (present RSCC), co-

operation with the various constituents of REBs and

CEA, to facilitate improved operation of its transmission

system, to help ensure a smooth transfer of old system

operational functions from CEA to Powergrid and to

facilitate the implementation of the new RSCC.

7

Powergrid will also undertake in co-operation with the

State Electricity Boards (SEBs) the projects to develop

new SEB load dispatch centers and to augment existing

facilities as a part of its regional co-ordination and

control system projects. SEBs will operate the facilities

in co-ordination with the concerned RSCC.

2. CURRENT INSTITUTIONAL AND OPERATIONAL

PROBLEMS IN THE NORTHERN REGION

2.1 Current institutional arrangements

The task of regional grid management is vested with the

NREB and they have to co-ordinate the operation of

autonomous Central and State sector organizations in the

Region. Under this set up the NREB has to derive their power

from the constituents. Lack of proper communication and real

time load dispatch facilities is the biggest constraint in

effective operation and control of the grid. The NREB, as

association of the Constituents of the Northern Region, was

created to co-ordinate the integrated operation of the Northern

Regional Grid System. The GOI made the decision to form a

National Power Grid, along with necessary load dispatch and

communications facilities, in order to make best use of India’s

unevenly distributed energy resources and to transfer large

amounts of surplus power from the North and East to the

other regions.

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2.2 Operational guidelines and discipline

2.2.1 Operational discipline

It is necessary to have proper agreements spelling out

the operations regimes, obligation of suppliers as well as

the beneficially States in terms of maintaining the

system parameters, reliability criteria, penalties for

violation of agreed operating regimes, etc.

The operating norms should cover not only the normal

state of operation of the power system but also the alert,

emergency and restorative states.

At present there are no means to enforce the

operational discipline. In case of overdraws of power by

any State, the Regional Load Despatch Centre (RSCC)

can only request the erring State to regulate its demand.

The continual overdraws of power of some deficient

States at the peak time while the same are not backing

down during off-peak as the frequency becomes very

high is a testimony to this kind of problems.

There is a lack of load management in most of the

States. It is a basic tenet of integrated operation that

each state restricts its load to match with the availability

9

from its own sources of generation plus legitimate

shares from common/central generating sources, plus

eventually agreed by lateral power exchange

agreements.

2.2.2 Frequency maintenance problems

The grid management problems of the country are

compounded by continuing power shortages in the

different systems. While the demand for power has been

increasing at a rapid pace the generation availability has

not been keeping pace with it. The short fall in

availability is due to delays in commissioning for

generating units, lack of funds for construction, problems

in quality of coal and equipments, high level of forced

outages, etc. In most power systems in the world, the

system frequency is kept virtually constant and a

combination of generator governors and automatic

generation control systems constantly control the

generators so that:

The total generation is kept equal to the total load and,

Generators are operated at the levels at which the total

cost of the power generated is at the minimum

consistent with safe system operation.

The remaining matching of load to generation is

obtained by allowing the system frequency to vary up

10

and down; this in turn increases or decreases the power

consumption of motor operated loads such as pumps,

refrigerators and many similar devices, until either the

load is brought to match the power generated or the

system collapse when frequencies become so low that

the generating plants cannot operate.

During peak periods, many of the SEBs fail to shed their

loads in the quantities agreed at the NREB level. This

forces other SEBs to shed more lot than they were

required to do, or causes frequencies to drop lower than

it would have. The net result in either case is that the

SEB that fails to shed load as agreed receives more

energy than it is entitled to, and the other receives less.

During light load periods, those SEBs that should back

down on their more expensive units fail to do so. The

result is that central units with lower production cost

must be back down instead, resulting in uneconomical

operation of the regional system. In some cases, hydro

units with full reservoir are required to back down their

output resulting in wasteful spilling of water over the

dense.

2.2.3 Lack of flexibility in generation scheduling at present the

energy invoicing is based on a single tariff system with

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regards to the actual energy transfers metered under tie-

lines.

The world wide basic principle of invoicing the power

transfers with regards to the agreed commitments and

calculations of inadvertent deviations between this

program and the actual transfers for compensation, etc

payments, penalties and what so ever, has not yet been

considered in the Indian practice. As far as the hydro

scheduling is concerned, the REBs only recommended

to most of the hydro stations to supply their maximum of

the power at the peak period but the power scheduled of

each power unit remains the responsibility of the hydro

stations mainly with regards with the irrigation

requirements.

2.3 Deficiencies in power transmission system

2.3.1 Power transmission lines and sub stations

The transmission system is being planned on a regional

basis and optimized without regard to ownership under

the responsibility of CEA. The establishment of central

sector power plants has increased the complexity of the

regional network by super imposing a transmission

system to the transmission system of the SEBs.

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With a view to optimizing investment, the regional

transmission systems have been developed on the

assumptions that the shares of some state located far

away from the central stations would be delivered on the

principles of net inter states exchanges where ever

feasible without affecting the reliability and security of

the transmission system.

There is also a tendency on the part of all the states to

cover only the very minimum works under the scope of

these projects

In several systems, the transmission capacities are not

sufficient to evacuate power from the generating

stations. This restricts full use of generating plants.

A single central agency that will be in charge of the

complete regional inter connected grid would bring more

rationality in this regard. It will be possible to construct

many more missing links, which are neither associated

with the evacuation of power from any power plant nor

required for load management. The major problems

encountered in daily operation of the northern 400 kV

networks are very low voltage level at receiving end at

the peak, power swings involving cascade tripping

and /or systems isolations and collapses, massive loss

of generation, voltage collapses, partial and sometimes

total power supply failure. One of the numerous regions

13

for these mishaps is due to the particular weakness of

the 400kv network and its long radial structure that

should be strengthened and reinforced by more

intermediate step-down substations.

2.3.2 Compensation means

Reactive power management has not received the

attention it deserves. Bulk of the present reactive power

is being supplied by the generating plants thereby

resulting in large flows of reactive power all over the

transmission and distribution networks towards the load

points from the generating units that are most of them

located far away from the load .The very low voltage

levels indicate conditions close to Voltage collapse or

transmission instability .The power swings typical of

transient instability.

2.3.3 Transmission planning tools

Eliminating transmission constraints, which prevent full

use of generating capacity, should be a priority in

efficiency improvement programs. For this purpose the

various Regions involved may need adequate planning

and design tools to be able to define in a more efficient

way the reinforcement needs.

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3. OPERATIONAL AND CONTROL PHILOSOPHY

3.1 Basic operational and functional requirements

The basic operational requirements of the Northern Regional

Grid are as follows:

Scheduling in advance a healthy mode of operation Constant

surveillance of the system’s conditions with the help of a well-

knit communication network so as to ensure the security of the

system at all times and at all points restoration of the system

to normalcy as early as possible in case of abnormalities by

taking corrective measures. These operational requirements

entail that the finicalities be implemented at the various levels

of control hierarchy both for operation planning activities and

real-time control activities.

During the operation planning stage, the basic tasks to be

carried out are:

State wise generation scheduling and load prediction for

a complete day, week, month and year

Determining of the share of each State in Centrally

owned generation on given day

Scheduling of inter-State and inter-Regional exchanges

for a given day

15

Updating maintenance schedule for generators,

transformers, transmission and/or distribution lines

Spinning reserve assistance

Co-ordination with National Load Dispatch Centre in the

future

Collection of data regarding weather forecasts

Analysis of system performance under disturbances and

devising remedial actions to minimize their effects

System operations statistics

Computing of tariffs for inter-system exchanges based

on pre-defined guidelines.

For the real-time control stage, the tasks to be performed may

be classified into two categories:

(1) On-line Real-Time Operation Control

(2) On-line Real-Time emergency and Reliability

Control

3.2 Outline of the overall control organization

It is clear that operation of such a large system requires one to

set up a control hierarchy, which will also match the power

system organization in the Region. With this end in mind, a 3-

tier hierarchical network has already been defined , complying

with the load dispatch facilities policy established by Central

Electricity Authority (CEA) for all India.

16

The following load dispatch centers are proposed to be

implemented at the different hierarchical levels:

Hierarchy level 1:

Regional System Control Centre at Delhi covering the region

power systems of Himachal Pradesh, Haryana, Jammu and

Kashmir, Punjab, Rajasthan, Uttar Pradesh, BBMB, DESU,

Chandigarh.

Hierarchy level 2:

Comprising State Load Dispatch Centres (SLDCs) and

Central Project Control Centres as below:

SLDC for Himachal Pradesh at Shimla;

SLDC for Haryana at Panipat;

SLDC for Jammu & Kashmir at Udhampur;

SLDC for Punjab at Patiala;

SLDC for Rajasthan at Heerapura;

SLDC for Uttar Pradesh at Lucknow;

CPCC at Moga for Central Sector Stations in the northern

area of the Region;

CPCC at Kanpur for Central Sector Stations in the south-

eastern area of the Region;

CPCC at Ballabhgarh for Central Sector Stations in the

central area of the region.

Hierarchy level 3:

Sub-load Dispatch Centres (Sub-LDCs) as below:

17

Sub LDCs at Kunihar and Hamirpur controlled by SLDC at

Shimla (Jutogh)

Sub LDCs at Dadri, Panipat TPS and Narwana controlled

by SLDC at Panipat;

Sub LDCs at Pampore and Udampur controlled by SLDC at

Udampur (NB: Udhampur Sub LDC is located in the same

control room as the SLDC);

Sub LDCs at Jallandhar, Lalton Kalan and Patiala

controlled by SLDC at Patiala.

Sub-LDCs at Ratangarh, Kota, Bhilwara and Heerapura

controlled by SLDC at Heerapura.

Sub-LDCs at Rishikesh, Moradabad, Panki, Varanasi and

Sultanpur controlled by SLDC Lucknow.

3.3 Functions of the Control Centres and sharing out of

responsibilities

GOI has agreed that Power Grid shall develop into a national

service oriented transmission company. The performance of

these activities requires a transmission network with adequate

capacity going well beyond the basic requirements of

evacuating power produced by specific plants and a minimal

connection to the load centre.

Powergrid will be organized primarily for impartial service to all

parts of the power sector. The SEBs will retain the basic

responsibilities of operating and dispatching their plants.

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3.4 Responsibilities of the RSCC

The RSCC shall be responsible for the following:

Data acquisition and monitoring of all the transmission

system at 220 kV and above, plus the 132 kV interstate

lines and all the generating stations of 50 MW and above.

Supervisory control of the power system operation

pertaining to inter-State/ Regional grid and control of

central sector sub-station under its direct jurisdiction.

Management and supervisory control of the centrally

owned generating unit. Load frequency control for the

entire region and sending corrective area control error

messages to all the constituents.

Monitoring inter-state exchanges of power with references

to schedule and AGC orders.

Supervision of generation/ load balance in the various

states with respect to the power exchange schedule, the

frequency requirements and the generation management

according to the merit order list prepared on a regional

basis.

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3.5 Responsibilities of SLDCs

The SLDC shall be responsible of the following:

Acquisition of information from central sector and some

part of the neighboring state systems from RSCC.

Generation load management according to economic

generation

Optimization carried out at state level and according to

RSCC request for inter-state power transfers and

frequency regulation.

Transmission of orders directly to state owned power

stations from the state requirements.

Voltage and reactive power control.

3.6 Responsibilities of the Sub-LDCs

The Sub-LDCs will be responsible of the following:

Switching of equipments at 220 and 400 kV as per direction

SLDC

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Voltage and reactive power control with in their area of

responsibility, according to SLDC’s requirements and

guidelines

Security assessment of the sub transmission network in

their area

4. PRINCIPLES FOR DATA ACQUISITION

4.1 General

The tele information plan corresponds to the requirements for

data collection that will enable the various levels of the power

system control hierarchy to fulfill their role. That means in

particular that apparatus status like bus selector disconnect or

position, and alarms like loss of voltage are considered and

some circuit breakers remote control facilities are planned.

4.2 Data Transmission Principles

The circuit breakers positions are collected under the

shape of double signals (DS) as this is necessary for

remote control functions, also these are more reliable.

The isolators positions are given single signal as these

are not needed for remote control.

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For all apparatus positions, the information will be

transmitted when change of status occurs.

All possible alarms are collected under single signals.

4.3 Principles for Data Acquisition

4.3.1 Busbar section

a) Voltage:

400, 220 & 132 kV: one value per main busbar.

66 kV: one value per station.

33 kV: no value.

b) Frequency:

400 kV: one value per busbar.

220 kV: one unit per station except for stations

where power units are connected to or having

inter-state feeders (2 values: one per main

busbar).

132, 66 kV: one value per station where power

units are connected.

33 kV: no value.

c) SS:

1 SS for loss of voltage per busbar.

4.3.2 Busbar coupler and bus section breaker

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DS: 1 DS per circuit breaker.

SS: 1 SS for only one out of the 2 disconnectors.

4.3.3 Bus transfer

DS: 1 DS per circuit breaker.

SS: 1 SS for each disconnector on both sides of the

C.B.

4.3.4 Busbar disconnector

SS: 1 SS for each busbar disconnector (whatever the

voltage level & including busbar transfer).

4.3.5 Capacitor

DS: 1 DS per circuit breaker.

SS: 1 SS for each bus selector disconnector.

4.3.6 Reactor connected to busbar & synchronous

compensator

a) Reactive power: 1 value.

b) D S: 1 DS per circuit breaker.

c) SS:

1 SS for each bus selector disconnector in case

of single breaker arrangement.

23

1 SS for each disconnector in case of one-

hand-half breaker arrangement.

4.3.7 Gas generator and Hydroelectric Generator (substation

side)

a) Active power:1 value.

b) Reactive power:1 value.

c) DS:

- 1 DS per substation circuit-breaker

- 1 DS per generator bus coupler

d) SS:

- 1 SS for each bus selector disconnector in case

of single breaker arrangement.

- 1 SS for each disconnector in the case of one-

and-half breaker arrangement.

- 1 SS for each by-pass disconnector in the case

of single breaker +by-pass arrangement.

e) Reservoir level: 1 ATM per hydro station when it is

already available on site.

4.3.8 Thermal generator (substation side)

One value of P for gross active output,

One value of Q for gross reactive output.

4.3.9 Remote generator

In case of power plant needs its own RTU because of

the distance to the substation, connections in the

24

corresponding substation are to be described as

overhead line connections and remote generators as

follows:

- 1 DS per circuit-breaker(if existing for outgoing

feeder),

- 1 DS per generator bus coupler,

- one value of P for gross active output of a

thermal generator,

- one value of Q for gross reactive output of a

thermal generator.

4.3.10 Overhead line

a) Active power and reactive power

- 400, 220 and 132 kV: one value of P and Q for

each outgoing line .

- 66 kV as a secondary part of Regional interest

substation: one value of P and Q only for

outgoing inter-system tie-line.

- 33 kV : no value.

b) DS

For each 400, 220 and 132 kV outgoing line and

66 kV outgoing tie-line:

- 1 DS per substation circuit-breaker

- 1 DS per reactor disconnector(or circuit-breaker

in the future) connecting it to the 400 kV line.

c) SS

25

For each 400, 220 and 132 kV outgoing line and

66 kV outgoing tie-line:

- 1 SS for each bus selector disconnector in case

of single breaker arrangement

- 1 SS for each disconnector in case of one-and-

half breaker arrangement

- 1 SS for each by-pass disconnector in case of

single breaker+by-pass arrangnment

d) DC

- 1 DC for each 132 kV outgoing line.

The choice consisting in the implementation of remote

control only for 132kv feeders and below can be justified

by the needs of quick switching operation requirements

for load shedding and emergency action.

In some particular cases, some remote control facilities

may be interesting also for 220 kV or 400 kV

components of the grid. These specific requirements

shall be precisely defined at technical specification

drafting.

4.3.11 Transformers

a) Active power and reactive power

26

One value of p and one value of q measured on

the secondary level for the 400/220 kV or 220/132

kV transformers, or on the primary level for the

132/66, 132/33 or 132/11 kV transformers. If the

secondary level does not belong to the same

constituent as the primary level, p and q are

measured on the primary level.

b) Current

One current value (I) measured on primary level

for the 66/33 kV, 66/22 kV, 66/11 kV or 33/11 kV

transformers whenever the load supplied by the

transformers is significant.

c) OLTC

The position of each On Load Tap Changer is

indicated with a digital or analog tele measuring.

This shall be specified for each individual case at

specification drafting.

d) DS:

1 DS per circuit breaker. If the secondary level

doesn’t belong to same network, 1 DS shall also

be collected for the secondary circuit breaker.

e) S S:

27

1 SS for each bus selector disconnector

in case of single breaker arrangement.

1 SS for each disconnector in case of

one & half breaker arrangement.

1 SS for each by-pass disconnector in

case of single breaker arrangement.

f) D C:

One DC on the secondary level for the 132/33 kV,

132/22 kV 132/11 kV, 66/33 kV, 66/22 kV, 66/11

kV, 33/11 kV transformer whenever the load

supplied by the transformers is significant.

5 DATA PROCESSING SYSTEMS OF CONTROL

CENTRES

5.1 RSCC Scope of supply

The following list details the requirements as regard hardware

& software for the RSCC computer system.

One dual computer system for SCADA, PAS & MMI

functions including at least:

System CRTs console,

Disks strage units,

28

Magnetic tape storage devices or equivalent

equipment,

Failover system,

Line printer,

Software package,

One time & frequency system,

One receiver for time synchronization

signals.

Man machine interface

Control room:

Two dispatcher consoles with two VDUs each,

Two hard copy units linked to any console,

Two loggers and one plotter,

One line printer,

One frequency recorder,

One mimic board, along with its driver,

One audible alarm.

Computer section:

One dispatcher console equipped with two VDUs,

Two programming terminals,

One hard copy unit,

One line printer.

SCADA and MMI software.

29

Power application software:

Network topology,

Reduced equivalent network,

Logical controls,

State estimation,

Contingency analysis,

Load flow,

LFC,

One local RTU.

5.2 SLDCs scope of supply

Two categories of SLDCs have been considered in the

northern region, depending on the size of the constituent:

1st category (large sized SLDC): Lucknow,

Heerapura.

2nd category (standred sized SLDC): Shimla,

Panipat, Patiala, Udhampur.

One normal dual configuration is provided for the first category

and a medium dual configuration is provided for the second

category.

One dual computer configuration for SCADA, PAS and

MMI functions including at least:

30

System CRTs console,

Disks storage units,

Magnetic tape storage devices or equivalent

equipments,

Fail over system,

Line printer,

Software package,

One time and frequency system,

One receiver for time synchronization signals.

Man Machine Interface

Control Room:

Dispatcher consoles:

- For SLDCs: 2 dispatcher consoles each with two

VDUs,

- For large mixed SLDC/sub-LDC: 3 dispatcher

consoles each with two VDUs.

Two hard copy units linked to any console,

Two loggers and one plotter,

One line printer,

One frequency recorder,

One mimic board along with its driver,

One audible alarm.

Computer section:

31

One dispatcher console equipped with two VDUs,

Two programming terminals,

One hard copy unit,

One line printer,

One local RTU.

SCADA and MMI software.

Power application software:

Network topology,

Reduced equivalent network,

Logical controls,

State estimation,

Contingency analysis,

Load flow,

LFC.

Option two for EMS:

One computer,

At least two disk storage units with controllers,

One streamer or magnetic tape storage device,

One line printer,

Two programming terminals,

One software package.

5.3 CPCC’s scope of supply

32

Two categories of CPCC have been considered in the

NorthernRegion depending on the quantity of RTUs

controlled:

1st category: more than or equal to 15 RTUs(large sized

CPCC )

2nd category : less than 15 RTUs(standard sized CPCC)

one medium dual cofiguration is provided for the 1st category

and the PC dual configuration is provided for the 2nd category.

The following list details the requirements as regards

hardware and

MMI functions including at least -One dual computer

configuration for SCADAand MMIfunctions including at least:

system CRTs console ,

disks storage units,

magnetic tape storage devices or equivalent equipment,

failover system,

line printer,

software pakage:

one time and frequency system,

one receiver for time synchronization signals

-Main Machine interface

-Control Room:

3 PC workstations,

two hard copy units linked to any console,

two loggers,

one line printer ,

one plotter,

one frequency recorder,

33

one mimic board along with its driver,

one audible alarm.

-computer section:

one dispatcher console equipped with its driver,

two programming terminals,

one hard copy unit,

one line printer,

-SCADA and MMI software,

5.4. Sub-LDCs scope of supply

Two categories of Sub-LDCs have been considered in the

Northern Region, depending on the quantity of RTUs

controlled:

1 St category:more than or equal to 15 RTUs-2nd category:

less than 15 RTUs

5.5 Control Centres communication

The hierarchy of the Control Centre is a three tiers hierarchy.

These are :

RTU(substation level )

Sub-LDC, 3rd tier

SLDC or CPCC, 2nd tier

RSCC, 1st tier.

All the state owned RTUs are only linked to Sub-LDCs. Thus a

data communication protocol and procedure shall be provided

for this first layer.

The data transferred on these links are:

Either real-time data

Or files

34

Or data related to remote logging procedures.

In order to enable all these data transfers between computers,

it is mandatory to have in each control center a

communication software which implements the seven layer of

Open System Interconnection(OSI) ISO Recommendation.

The OSImodel in seven layers is the following one:

Layer 1: physical,

Layer 2:link,

Layer3:network,

Layer4:transport,

Layer5:session,

Layer6:presentation,

Layer7:application.

5.6. GENERAL

Telecontrol systems serve for monitoring and control of

processes which are geographically widespread.They include

all equipment and functions for acquisition,processing,

transmission and display of the necessary process

information. The performance of a telecontrol system is

determind basically by:

The data integrity of information transfer, from a

source to its destination , and ,

The speed with which information is transferred to its

destination.

35

Since telecontrol systems have to operate in real-time mode,

limitations imposed by the telecommunication channels may

heavily impair the overall system efficiency.The implicatin is

restricted bandwidth and hence restricted bit rates to be

transmitted under noisy environment conditions, which cause

distortion of transmitted signals elements. The data

transmission system has to be considered in the sense as an

integrated part of the telecontrol system.

Basic requirements of the data transmission system

Data transmission should fulfill the following

requirements:High data integrity and data consistencyUnder

these conditions, it is necessary to provide efficient protection

of messages against :

undetected bit errors,

Undetected frame errors caused by synchronization

errors,

Undetected loss of information ,

Gain of unintended information ,

Separation of perterbation of coherent information.

Short telecontrol transferred time

Provision of short information transmission by application of

efficient frame transmission protocols, particularly for event

intiated messages over transmission paths with limited

bandwidth and with uncertain noise characteristic has to be

ensured.Support of bit oriented (code transparent ) data

transmissionNo code restrictions on user data required.The

36

data link protocol accepts and transmits arbitrary bit sequence

structures from the data source.

Transmission software and protocol specifications

Transmission software arrangment

For standardization reasons and easy future upgrading of the

Data Transmission Network(DTN) to packet switching,

communication software is based over the latest ISO(CCITT)

standards in force implementing the ISO’s OSI model.This

subdivision into modular layers is a useful theoretical model

for difining standards. Each layer is essentially independent of

the layers below and above it. It treats the layer below as a

“service” function and the layer above as a “master” with witch

it exchanges data and to which it reports errors.

The independent of the layers gives a modularity to the

system. It ispossible to alter one layer without altering others,

in the some layers may be omitted.Telecontrol system

functions will be divided into the following layers:

Application functions:

Cover the special needs of the process to which a telecontrol

system is applied, thus dealing with the types of information

emanating from the process or from the operator.This

information is transferred to the telecontrol system by signals

and is handled with in this system in the form of data.

Operational processing functions including presentation

functions:Conversion of information into signals and in the

37

operational equipment.Data transport, network, link and

physical transmission functions.

Tansmission protocol

The protocol to be used for RTU-sub-LDC links and for direct

RTU-RSCC links will be one of the following by order of

decreasing preferences:

- X.25(up to layer 2), -IEC 870-5-1, -Manufactrur’s

specific.If one of the first 2 solutions is proposed, it must not

induce additional cost with respect to the manufcturer’s

specific solutions.

The protocol to be used for inter –LDClinks will be the X.25

with the option and particulars alredy applied by department of

science and technology in consulation with CEA.

5.7. Physical structure of the protocol system

5.7.1. General

The structure of the data communication network which

is thus a sub-set of the telecommunication system is

mainly determined by the operational philosophy, i.e.:

National Control Centre,

Regional Control Centre,

State Control Centre,

Sub-state Control centre,

Substations,

And the real-time character of the requirements .

The solution of designing a complete Packet switching Data

Network(PSDN) has also been examined.

5.7.2. Geographical configuration of telecontrol channels

38

For RTUs a combination of multipoint-party line

configuration and multiple point-to-point configuration

will be used. The first type involves serial polling, i.e.

several RTUs share the same telecontrol channel, while

the second type involves parallel polling from the sub-

LDC.

Transmission link redundancyIn order to maintain a high

quality of service with strategic sites, the physical

communication links arriving on the latter will be

duplicated. This will be the case atleast for:

The links arriving on 400/200kv substation and power

station RTUs,

All the links interconnecting contral centers.

5.8. Transmission modes

5.8.1. Transmission initiation modes

In the case if RTU/sub-LDC links, two basic

transmission initiating modes will be used for telecontrol

data transmission:

Event initiated transmission(spontaneous transmission,

also called master-master),

Transmission on demand(interrogative or polling mode,

also called master-slave).

Types of traffic in transmission channelsFull duplex

traffic will be used,

39

Independent transmission channels exist for the

incoming and outgoing directions .

5.9. Transmission speed

5.9.1.Basic requirements

Total control system refresh time for indications must not

exceed 2s under normal operating conditions.

For analog measurenments, the age of a displayed

values must not exceed 10s.

5.9.2. Final results

The following is required:

For sub-LDC/SLDC links:1200 Bds(1200 bits/s), FSK,

CCITT V-23, 4-wire.

For higher hierarchical rank inter-computer links:4800

Bds(4800 bits/s), phase modulation, CCITT V.29.

For RTUs:

All RTUs would be configured to work at 200 bauds on

FSK channels located above the 300 to 2.4 kHz speech

sub-bands of 4 kHz VFTs.

5.10. Modems

5.10.1. Basic requirement of RTUs modems

Frequency shift channel modems are to be used to

convert a binary signal into two distinct frecuencies.The

rack modem of RTU will contain 2 single-card modem

boards.The modem will accept CCITT V.24 serial

40

signals and communicates at the standardized data

rates from 50 to 1200 bauds.

basic requirement of modems for control centre

computerThe communication speed will be settable from

50 to 9600 bits/s.

5.11. Remote terminal unit

5.11.1. General

The typical RTU will perform two functions:

The basic RTU function:Processes and

transmits:Indication signal change messages,

Telemeasuring value messages andTelemetering value

messagesPicked-up on the RTU location site devices to

a control centreReceives and processes digital or

analogue command messages coming from a control

centre so as to feed them to the relevant devices located

at the RTU location site.

Sequential Event recording :

TTY will be provided only at 400kv, 220kv substation

and power station sites.

5.11.2. Charateristics of RTU I/O circuits

RTU will be capable of accepting :Single point

information indication signals, double point information

indication signals, telemetering signals, under the form

of potential free contacts.

RTU will be capable of issuing:Single point digital

controls,

41

Double point digital controls,

Under the form of potential free contacts .

RTU basic functional processing requirements

The RTU will be capable of time-tagging the status

changes with a 10ms resolution for transmission to the

control centre as well as local editing on a TTY

terminal(sequential event recording)RTUs bills of

quantitiesAn RTU will equip each side that will be

under supervisory. For power station and the control

room of which is farther than 1km from the substation

control room, a separate RTU will be

installed.Subsequently, the following quantities of

RTUs have to be supplied :

HIMACHAL PRADESH : 14(14 stations)

HARYANA : 32(31 stations+SLDC)

JAMMU & KASHMIR : 14(14 stations)

PUNJAB : 47(47 stations)

RAJASTHAN : 53(53 stations)

UTTAR PRADESH : 98(97 stations+SLDC)

CENTRAL SECTOR : 44(43 station + RSCC)

TOTAL : 302

6. DC SYSTEM AND AC AUXILIARY POWER SUPPLIES

6.1 General

42

For the purpose of a control and telecommunication scheme , the

auxiliary power supplies are usually categorized as under .

Power supplies for supply of :New RTU an interface cubicle ,

new communication equipment , Data processing equipment in

the various control centers,Airconditioning and security lighting in

Control Centres .

They are one of thefollowing types:

Uninterruptible DC source (or DC power system)

Uninterruptible AC source

Standby power supply.

In the scope of this project , it was generally decided by

Powergrid and the constituents that the DC power supply in the

sub stations will not be included.Thus , only the AC and DC

power supplies for the sub-LDCs , CPCCs, SLDCs and RLCC

will be considered .

6.2. AC auxiliary power supplies in Control Centres

6.2.1. Making–up of 415/240V AC uninterruptible power supply

in Control Centres

Two 415V, 3 phase AC supply together with an

emergency diesel generator will ensure a secure supply

to the essential services which can support a power

failure for a short period of time , i.e. : stand-by power

supply .An uninterruptible power supply consisting of DC

supply chargers , batteries and invertors will provide 3

phase 50Hz power supplies to the computers ,

peripherals, etc….

6.2.2. 415/240V stand-by and UPS power sizing.The

minimum sizing will be:125KVA for the diesel generator

43

and 2*50kVA for the AC UPS of RSCC and large sized

SLDCs , 25kVA for the diesel generator and 2*25kVA for

the AC UPS of large sized sub-LDCs and small sized

SLDC , 45kVA for the diesel generator and 2*15 kVA for

the AC UPS of a small sized Sub-LDCs and CPCC.

6.3. 48V DC system in control center

6.3.1. 48V DC power supply make-up in control center

A control center 48V DC power supply system will

comprise in fact two traditional 48V DC system chains ,

each including:2 rectifiers simulteneusly operating in

parallel ,

1 lead-acid stationary type battery ,

1 distribution board,

An inter-connection between the 48V DC power supply

system distribution boards which will be left normally

opened under normal operating conditions.7.3.2. Sizing

the 48V DC system in Control Centre

The minimum sizing for each DC system chain will be one

800Ah battery and two 160A rectifires .

6.4. 48V DC system in sub-station

6.4.1. General

Communication and telecontrol means of sub-stations are

power supplied under a mean voltage of 48V DC with

possible link of the positive polarity end to the earth.For

this purpose, we must have DC systems suited to the new

equipment.

The following operational figures are usually used for the

48V DC systems plus 20 degree Centigrade:

44

End- of-discharge voltage per lead-acid cell:1.90V

Floating battery mode voltage per lead-acid cell :2.20V

Equalisation mode voltage per lead-acid cell :2.30V

Manual commissioning boost mode per lead-acid :2.70V

Elementry lead-acid stationary type cell quantity: 24

6.4.2. 48V DC system making-up in sub-station

A sub-station 48V DC system compries2 rectifires

simultaneously operating in parallel and sharing the total

current demand

1 lead-acid battery

1 distribution board

6.4.3. 48V DC system sizing and BOQs in sub-stations

Adequately sized batteries and rectifires will be provided

by some SEBs/boards/central Sectors themselves as a

part of the sub-station power/plant components.

7. TOTAL COST BENEFITS OF THE PROJECT

7.1 General

As a matter of the fact , once a utility’s network has reached a

certain level of development a modern control system becomes

and absolute necessity, and the question of its profitability is

almost secondary .However , even though a precise economic

analysis is not possible , in view of the system’s nature , it is

usual practice to evaluate such a project by advantages that it

offers to the utility .These advantages fall into the following two

categories:

Economically quantifiable benefits Intangible benefits

45

7.2 Economically quantifiable benefits

The economically quantifiable benefits may be classified into four

main categories:

Improvement of system reliability and reduction of undelivered

energy.

Saving in operating costs.

Capital investment savings.

Reduction of personnel costs.

These benefits have been evaluated on the basis of field data

related to disturbances and on some figures recommended by

international agencies.Improvement of system reliability and

reduction of undelivered energy

The benefits expected in this area are mainly based on two

aspects : System security will be considerably improved by

providing the operater with real-time information and also by the

various EMS functions.They will avoid numerous cascade

trippings both at an area level and at the Region level.For the

trippings and disturbances which will occur anyway, the

restoration to normalcy will be significantly speeded up. A

savings of 20 to 30 minutes in restoration time is more than

plausible.To estimate the reduction of undelivered energy we

may consider that the control scheme will make it possible to

avoid one tripping per year of the entire Northern grid and that

restoration time will be

halved. Assuming that a general collapes lasts one hour , in

1995:Avoidance of one tripping during one hour :

E=110841 MkWh/8760*1= 12.65 MkWh

Reduction of restoration time:

46

110841 MkWh / 8760 * 0.5 = 6.33 MkWh

i.e.: 19 MkWh /year.

Assuming that the cost of undelivered energy is 20 times the cost

of generation which is also a standard value and that the cost of

generation in Northern Region is Rs 12 lakhs / MkWh, then

theyearly benefit in this area expected from the control scheme is

:

19 * 12 * 20 = Rs 4560 lakhs per year

i.e. Rs 45.6 Crores per year.

Operating costs savings

The reduction of operation costs is mainly expected from a

reduction

in fuel expenditures

The control schemes enables a reduction of fuel outlays for three

reasons:

an integrated management of all generation facilities in Northern

Region during the operation planning stage will enable a better

use of the thermo-hydroelectric generation pattern in real-

time .This benefit is expected to be at least 0.5 % of fuel

costs .inter-State exchange possibilities in real-time will be

enhanced.Therelated benefit is expected to be 0.2% of fuel costs

.The total energy saved can be estimated at 0.7%.The yearly

benefit will be , in 1995 , assuming a Rs 12 lakhs /MkWh

generation cost:

110841 * 0.7 % * 12 = Rs 9310 lakhs /year

i.e.: Rs 93.1 Crores per year.

47

Capital investment savings

Capital investment savings are expected both for generation

facilities and for transmission networks facilities .For generation

facilities and due to peak power storage for the Northern grid ,

these savings are quite real in so far as there is a correlation

between the energy saved and the additional capacity installed to

supply this lost energy .

It may be anticipated that 0.35 % of additional installed capacity

could be saved for an equivalent quality of service if 0.7% of

energy is saved by the implementation of the control

scheme .With a 12, 258 MW additional installed capacity planned

for 1995 , the saving is 43 MW.

Assuming a hydro-thermal mix of 35/65 in installed capacity and

Rs 3.5 crores /MW of hydel capacity and Rs 3crores /MW of

thermal capacity , the capital investmentSaving for generation

facilities is :

43 * 0.35 * 3.5 + 43 * 0.65 * 3 = Rs 137 Crores

Reduction of personnel costs

The following considerations are also valid.

A measure benefit due to SCADA is the increased effectiveness

of theLoad Despatch personnel which can be achieved .Load

dispatch personnel spend an inordinate amount of time on paper

work . Automated logging and reporting software can drastically

reduced this tedious tasks.

It is extremely important that load dispatch personnel be relieved

of manual report preparation task and equipped to concentrate

on operating the system with complete and accurate information.

48

It would have been possible to quantify the reduction of

personnel costs.

7.3 Intangible Benefits

The intangible benefits expected from a control scheme are

numerous

.The following considerations are extracted from the CIGRE

paper mentioned before :

Better management information

SCADA systems contain facilities to retrieve data required for

preparation of reports and “time tagging” of events for post

mortem analysis.These reports and data are useful to operational

staff in verifying that protection equipment operated correctly in

response to a fault.System statistics suitable for generation and

transmission planning studies may be store.This has influence in

optimizing the hydro operation . It is important if the amount of

the water for power generation is less than volume available in

an average year .

Quick adoption of new operating philosophips according to the

development of the power system requires flexibility , which can

be reached in a Control Centre .Improved Reliability Procedures

It is normal practice to switch capacitors , reactors and cables at

different times during the day for voltage control purposes. Circuit

–breakers in the transmission network may be opened or closed

to limit short circuit levels .

Improved Operator Training

Operator training simulators are available today . The opening /

closing of breakers , tap changing of transformers , etc. can be

simulated without affecting the status /security of the actual

49

power system . Network analysis training will also guarantee

higher level of understanding the features of a power network .

Organization Improvent

Establishment of a control centre means that during the

implementation phase most operations , planning and monitoring

functions are critically reviewed . This often means a complete

reorganization of the entire organization which in the long run will

result in more efficient power system operations.Technology

transfer will assist the Utility in future attempts to rationalize and

improve operations by using computer technology.

Other Non-technical Factors

Most Utilities in developing countries are linked closely to Central

Government . The Utility are urged for political reasons to

increase their operating reliability . Some of the reasons for this

are :Governments are concerned about the substantial lost

revenues that industries suffer when power interruptions

occur ;Governments are usually interested in attracting foreign

companies and other investments to their countries . High

operating reliability of a country’s power supply is a major factor

in encouraging foreign investment ;

Governments are concerned about security problems during

blackouts . Police force and damage costs due to social “unrest”

can be high . Loss of faith in the ability of the country to handle

social problems can be even higher ;Governments are

concerned about their image . Blackouts and unreliable electric

supply are embarrassing.Most of these considerations apply in

the case of the control scheme for the Northern Regional grid.

8. CONCLUSION

50

The various economically quantifiable benefits expected from the

implementation of the Northern Regional Control scheme are summarized

below :

Yearly recurrent benefits :

Improvement of system security and reduction of undelivered

energy

: Rs 45.6 Crores per year.

Operating cost savings: Rs 93.1 Crores per year.

Totalling Rs. 137.7 Crores per year.

Capital investments savings :

Generation facilities : Rs. 137 Crores.

Transmission facilities : Rs. 21 Crores.

With a 447 Crores Project would be paid off in :

( 447 – 158) / 137.7 = 2.1 years

51

Control Hierarchy – NR

JALLANDHAR IISub-L.D.C. of

P.S.E.B.

LALTONKALANSub-L.D.C. of

P.S.E.B.

MOGA *Sub-L.D.C. of

P.S.E.B.

PATIALAS.L.D.C. of

P.S.E.B.

SHIMLAS.L.D.C. ofH.P.S.E.B.

KUNIHARSub-L.D.C. of

H.P.S.E.B.

HAMIRPURSub-L.D.C. of

H.P.S.E.B.

PANIPATS.L.D.C. ofH.S.E.B.

NARWANASub-L.D.C. of

H.S.E.B.

DADRISub-L.D.C. of

H.S.E.B.

HEERAPURAS.L.D.C. of

R.S.E.B.

RATANGARHSub-L.D.C. of

R.S.E.B.

KOTASub-L.D.C. of

R.S.E.B.

BHILWARASub-L.D.C. of

R.S.E.B.

LUCKNOWS.L.D.C. ofU.P.S.E.B.

RISHIKESHSub-L.D.C. of

U.P.S.E.B.

VARANASISub-L.D.C. of

U.P.S.E.B.

MORADABADSub-L.D.C. of

U.P.S.E.B.

SULTANPURSub-L.D.C. of

U.P.S.E.B.

PANKISub-L.D.C. of

U.P.S.E.B.

MINTO ROADS.L.D.C. ofD.E.S.U.

BAWANASub-L.D.C. of

D.E.S.U.

GOPALPURSub-L.D.C. of

D.E.S.U.

GAZIPURSub-L.D.C. of

D.E.S.U.

BAMNAULISub-L.D.C. of

D.E.S.U.

CHANDIGARHS.L.D.C. ofB.B.M.B.

DADRISub-L.D.C. of

B.B.M.B.

PANIPATSub-L.D.C. of

B.B.M.B.

JAMALPURSub-L.D.C. of

B.B.M.B.

GANGUWALSub-L.D.C. of

B.B.M.B.

GLADNIS.L.D.C. of

J & K

BENIMASub-L.D.C. of

J & K

KANPUR

C.P.C.C.

R.S.C.C.DELHI

53

Control Hierarchy – NR

RSCC

SLDCJ&K

(GLADNI)

SLDCBBMB

(CHANDIGARH)

SLDCHPSEB

(SIMLA)

SLDCDVB

(DELHI)

SLDCHVPNL

(PANIPAT)

SLDCPSEB

(PATIALA)

SLDCRSEB

(HEERAPURA)

SLDCUPSEB

(LUCKNOW)

SUBLDC(5)

SUBLDC(1)

SUBLDC(4)

SUBLDC(2)

SUBLDC(4)

SUBLDC(2)

SUBLDC(2)

SUBLDC(3)

CPCC

RTUs RTUs RTUs RTUs RTUs RTUs RTUs RTUs

RTUs

Control Hierarchy – NR

RSCC

SLDCJ&K

(GLADNI)

SLDCBBMB

(CHANDIGARH)

SLDCHPSEB

(SIMLA)

SLDCDVB

(DELHI)

SLDCHVPNL

(PANIPAT)

SLDCPSEB

(PATIALA)

SLDCRSEB

(HEERAPURA)

SLDCUPSEB

(LUCKNOW)

SUBLDC(5)

SUBLDC(1)

SUBLDC(4)

SUBLDC(2)

SUBLDC(4)

SUBLDC(2)

SUBLDC(2)

SUBLDC(3)

CPCC

RTUs RTUs RTUs RTUs RTUs RTUs RTUs RTUs

RTUs

54