DECLARATION

I, hereby, solemnly declare that all documents and details of the firm from which I have

done my training, are correct and true to the best of my knowledge and belief. I fully

understand that in the event of any information being found false or incorrect, action can be

taken against me.

Place : Jaipur Signature of student

Date : /07/11

ABSTRACT

SCADA stands for Supervisory Control And Data Acquisition. As the name indicates, it is

not full control system but rather focuses on the supervisory level. It is a computer system

for gathering and analyzing real time data.SCADA system are used to monitor and control a

plant or equipment such as telecommunication , water and waste control ,energy ,oil and

gas refining and transportation electricity distribution control .

A SCADA system gathers information, such as where a leak of signal has occurred,

transfers the information back to a central site, alerting the home station that the leak has

occurred carrying out necessary analysis and control, such as determining if the leak is

critical, and displaying the information in a logical and organized fashion. SCADA system

can be relatively simple, such as one that monitors environmental condition of a small

office building, or incredibly complex, such as a system that monitors all the activity in a

nuclear power plant or the activity of a municipal water system.

Here we have learnt the application of SCADA system in monitoring the power

distribution in the Rajasthan. Here the all necessary and required data (electrical

parameters) are being analyzed by computer system with the help of SCADA.

ACKNOWLEDGEMENT

I am very glad to take this opportunity to express my deep sense of gratitude and respect

towards Mr. M.P. Mathur (AEN) fro allowing me to do training at the SLDC unit,

R.R.V.P.N.L., jaipur. I am also thankful to my training guide Mr. Dhiresh Saini (JEN) for

enlighten our path towards the horizon of practical happenings. I am very much indebted to

him for the generosity, expertise, and excellent guidance through out the training and fro

being a source of inspiration and encouragement to us.

I finally thank all those personalities who have helped me directly or indirectly in

completing this training, without whom; the work could not have been brought into the

light of educational horizons.

I thank them all profusely.

LOKESH KUMAR

B.Tech. III Year

(E&C Engg.)

PREFACE

Difference in the academic life and practical life is revealed when one enters the real life

and competitive world of industries where there is a cut throat competition and one has to

forcefully follow the theory of Charles Darwin “Survival Of The Fittest” in order to exist in

the competitive world one has to be fully aware of all aspects of industrial life. Theoretical

knowledge which we gain from books is not of much useful without knowing its practical

implementation. It has been experienced that theoretical knowledge is volatile in nature. To

accomplish this aspect the Rajasthan Technical University has included Industrial training.

To meet this requirement in our engineering curriculum, provision of industrial training of

30 days program is provided.

Industrial training is one of the most important parts of the engineering studies. During the

industrial training as student we had learn to co-relate the practical problem to the possible

theoretical knowledge or solution. We have undergone our industrial training from the

SLDC, RRVPNL, heerapura, Jaipur Rajasthan in the field of SCADA systems

CHAPTER 1

INTRODUCTION

1.1 BASIC SCADA SYSTEM

SCADA stands for supervisory control and data acquisition. It generally refers to industrial

control systems: computer systems that monitor and control industrial, infrastructure, or

facility-based processes

A 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.

The term SCADA usually refers to centralized systems which monitor and control entire

sites, or complexes of systems spread out over large areas (anything from an industrial plant

to a nation). 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.

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.

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. This practice has been ongoing for many years

with no known data breach incidents to date. Cellular network data is fully encrypted, using

sophisticated encryption standards, before transmission and internet data transmission, over

an "https" site, is highly secure.

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.

CHAPTER 2

BACKGROUND OF FIRM

2.1 INTRODUCTION-THE NORTHERN REGION POWER SYSTEM

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:

o Power Grid Corporation of India Limited (Power grid)

o National Thermal Power Corporation Limited (NTPC)

o National Hydro-electric Power Corporation Limited (NHPC)

o Nuclear Power Corporation (NPC)

o Nathapa Jhakri Power Corporation (NJPC)

o Tehri Hydro Development Corporation Limited (THDC)

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.

2.2 CURRENT INSTITUTIONAL AND OPERATIONAL PROBLEMS IN THE

NORTHERN REGION

2.2.1 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.

2.2.2 Operational guidelines and discipline

2.2.2.1 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.

At present there are no means to enforce the operational discipline. In case of overdraws of

power by any State, the Regional Load Dispatch Centre (RLDC) can only request the erring

State to regulate its demand. 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 from its own sources of generation plus legitimate shares from common/central

generating sources, plus eventually agreed by lateral power exchange agreements.

2.2.2.2 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.

The remaining matching of load to generation is obtained by allowing the system frequency

to vary up 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

fails to shed their loads in the quantities agreed at the NREB level.. 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.

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. 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.

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.

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.

2.4. OPERATIONAL AND CONTROL PHILOSOPHY

2.4.1 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

• 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:

o On-line Real-Time Operation Control

o On-line Real-Time emergency and Reliability Control

2.4.2 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.

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:

o Sub LDCs at Kunihar and Hamirpur controlled by SLDC at Shimla (Jutogh)

o Sub LDCs at Dadri, Panipat TPS and Narwana controlled by SLDC at

Panipat;

o 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);

o Sub LDCs at Jallandhar, Lalton Kalan and Patiala controlled by SLDC at

Patiala.

o Sub-LDCs at Ratangarh, Kota, Bhilwara and Heerapura controlled by SLDC

at Heerapura.

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

controlled by SLDC Lucknow.

2.4.3 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.

2.4.4 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.

2.4.5 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

• 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

2.5. PRINCIPLES FOR DATA ACQUISITION

2.5.1 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.

2.5.2 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 isolator’s positions are given single signal as these are not needed for remote

control.

• For all apparatus positions, the information will be transmitted when change of

status occurs.

• All possible alarms are collected under single signals.

2.5.3 Principles for Data Acquisition

2.5.3.1 Bus bar section

Voltage:

• 400, 220 & 132 kV: one value per main bus bar.

• 66 kV: one value per station.

• 33 kV: no value.

Frequency:

• 400 kV: one value per bus bar.

• 220 kV: one unit per station except for stations where power units are

2 Connected to or having inter-state feeders one per main bus bar).

• 132, 66 kV: one value per station where power units are connected.

• 33 kV: no value.

2.5.3.2 Thermal generator (substation side)

• One value of P for gross active output,

• One value of Q for gross reactive output.

2.5.3.3 Overhead line

• Active power and reactive power

o 400, 220 and 132 kV: one value of P and Q for each outgoing line .

o 66 kV as a secondary part of Regional interest substation: one value of P and

Q only for outgoing inter-system tie-line.

o 33 kV: no value.

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.

2.5.3.4 Transformers

• Active power and reactive power: 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.

• 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.

• DC: 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.

CHAPTER 3

TRAINING EXPERIENCES

Industrial training is one of the most important parts of the engineering studies essential for

individual from technical knowledge point of view as well as it is also comes into the marks

category system given by RTU. Hence to fulfill that criterion I have doen my industrial

training from RRVPNL (SLDC unit) during the industrial training as being a student we

had learn to co-relate the practical problem to the possible theoretical knowledge which we

are given as per our syllabus books, and to get the solution of that problem. We have

undergone our industrial training from the SLDC, RRVPNL, heerapura, Jaipur Rajasthan in

the field of SCADA systems, which is very new concept but due to great applicability it is

becoming widely used at all industrial level for software (DCS) as well as hardware

operation (PLC)

The whole training was full of knowledge regarding the live environment of companies as

well as knowledge of core industry. This training also provided the me to inculcate the

students with a little something extra in a manner of enjoyment too

CHAPTER 4

SYSTEMS/ PROJECT DEVELOPMENT

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.

2.6. DATA PROCESSING SYSTEMS OF CONTROL CENTRES

2.6.1. 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:

o System CRTs console,

o Disks storage units,

o Magnetic tape storage devices or equivalent equipment,

o Failover system,

o Line printer,

o Software package,

o One time & frequency system,

o One receiver for time synchronization signals.

• Man machine interface

• Control room:

o Two dispatcher consoles with two VDUs each,

o Two hard copy units linked to any console,

o Two loggers and one plotter,

o One line printer,

o One frequency recorder,

o One mimic board, along with its driver,

o One audible alarm.

• Computer section:

o One dispatcher console equipped with two VDUs,

o Two programming terminals,

o One hard copy unit,

o One line printer.

• SCADA and MMI software.

• Power application software:

o Network topology,

o Reduced equivalent network,

o Logical controls,

o State estimation,

o Contingency analysis,

o Load flow,

o LFC,

• One local RTU.

2.6.2 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 (standard sized SLDC): Shimla, Panipat, Patiala, Udhampur.

• One dual computer configuration for SCADA, PAS and MMI functions

including at least:

o System CRTs console,

o Disks storage units,

o Magnetic tape storage devices or equivalent equipments,

o Fail over system,

o Line printer,

o Software package,

o One time and frequency system,

o One receiver for time synchronization signals.

• Man Machine Interface

• Control Room:

o Dispatcher consoles:

1. For SLDCs: 2 dispatcher consoles each with two VDUs,

2. For large mixed SLDC/sub-LDC: 3 dispatcher consoles

each with two VDUs.

o Two hard copy units linked to any console,

o Two loggers and one plotter,

o One line printer,

o One frequency recorder,

o One mimic board along with its driver,

o One audible alarm.

• Computer section:

o One dispatcher console equipped with two VDUs,

o Two programming terminals,

o One hard copy unit,

o One line printer,

• One local RTU.

• SCADA and MMI software.

• Power application software:

o Network topology,

o Reduced equivalent network,

o Logical controls,

o State estimation,

o Contingency analysis,

o Load flow,

o LFC.

• Option two for EMS:

o One computer,

o At least two disk storage units with controllers,

o One streamer or magnetic tape storage device,

o One line printer,

o Two programming terminals,

o One software package.

2.6.3 CPCC’s scope of supply:

Two categories of CPCC have been considered in the Northern Region depending on the

quantity of RTUs controlled:

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

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

one medium dual configuration 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 SCADA and MMI functions including at

least:

o system CRTs console ,

o disks storage units,

o magnetic tape storage devices or equivalent equipment,

o failover system,

o line printer,

o software package:

o one time and frequency system,

o one receiver for time synchronization signals

• Main Machine interface

• Control Room:

o 3 PC workstations,

o two hard copy units linked to any console,

o two loggers,

o one line printer ,

o one plotter,

o one frequency recorder,

o one mimic board along with its driver,

o one audible alarm.

• computer section:

o one dispatcher console equipped with its driver,

o two programming terminals,

o one hard copy unit,

o one line printer,

• SCADA and MMI software,

5.5 Control Centers 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

• 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 communication software which implements the seven layer of Open

System Interconnection (OSI) ISO Recommendation. The OSI model in seven layers is the

following one:

• Layer 1: physical,

• Layer 2:link,

• Layer3:network,

• Layer4:transport,

• Layer5:session,

• Layer6:presentation,

• Layer7: application.

2.6.6. 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.

Since telecontrol systems have to operate in real-time mode, limitations imposed by the

telecommunication channels may heavily impair the overall system efficiency. The

implicating 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.

2.6..6.1 Basic requirements of the data transmission system

Data transmission should fulfill the following requirements: High data integrity and data

consistency under 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 perturbation of coherent information.

Provision of short information transmission by application of efficient frame transmission

protocols, particularly for event initiated messages over transmission paths with limited

bandwidth and with uncertain noise characteristic has to be ensured. Support of bit oriented

(code transparent) data transmission No code restrictions on user data required. The data

link protocol accepts and transmits arbitrary bit sequence structures from the data source.

2.7. Physical structure of the protocol system

2.7.1. 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.:

o National Control Centre,

o Regional Control Centre,

o State Control Centre,

o Sub-state Control centre,

o Substations,

o And the real-time character of the requirements .

The solution of designing a complete Packet switching Data Network (PSDN) has also been

examined.

2.7.2. Geographical configuration of telecontrol channels

For RTUs a combination of multipoint-party line configuration and multiple point-to-point

configurations 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 redundancy In 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 control centers.

2.8. Transmission modes

2.8.1. 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 channels Full duplex traffic will be used,

• Independent transmission channels exist for the incoming and outgoing directions .

2.9. Transmission speed

2.9.1. 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.

2.9.2. 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.

2.10. Modems

2.10.1. 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 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.

2.11. Remote terminal unit

2.11.1. General

The typical RTU will perform two functions:

The basic RTU function: Processes and transmits: Indication signal change messages,

• Telemeasuring value messages and Telemetering value messages Picked-up on the

RTU location site devices to a control centre Receives 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.

2.11.2. Characteristics 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,

• 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 quantities An 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. TELEPHONE,TELEX AND TELECOMMUNICATION NETWORK

6.1. General

The power Systems is rapidly getting more complex with its integration into Regional and

National Grid. This has brought with it the need for an efficient, reliable and modern

communication system for the Power authorities. So the Government of India has

recommended an independent dedicated communication system to be owned and operated

by the Power Utilities up to the STATE LOAD DISPATCH CENTRE level from remote

power stations and substations.

6.2. Telecommunication systems requirements

The telecommunication part of the project will cater for the requirements of the load

dispatch computerized scheme in respect of the following: Speech and data transmission for

system operation and control, Transmission of operational data for generation of reports

and statistical information. The hierarchy of communication network will start from

Remote Terminal Units at remote substations/power stations participating significantly in

the intrigrated operation of the Northern grid and terminate at Sub –Load dispatch centers .

The communication system will support the following applications

• Speech communication on express /dialing basis ,

• Data transmission

• Teleprinting

• Facsimile transmission.

6.2. Structure of The Express telephone and teleprinter network

The express telephone network is a hot line system that shall be fully independent from the

switched PABX network. It shall provide direct connections between substations or power

and LDCs .In small LDCs, teleprinters shall be connected directly on the same EPAX than

telephone sets. In important LDCs, dedicated EPAX can be used for connecting

teleprinters. In order to ease the operation of express telephone calls, specific consoles shall

be installed at LDCs for supervision and establishment of hot line connections.

6.2.2 Planning Philosophy

For communication between RTUs and sub-LDC , PLCC has been recommended by the

constants , as their requirement is generally not more than 4 channels which can be

accommodated by PLCC .A 200 baud channel , required for RTU communication , can

readily be accommodated above the 300 Hz to 2.4 KHz speech band in a 4 KHz wide PLC

channel . The speed of composite data transmission beyond sub-LDC is about 1200 baud.

7. DC SYSTEM AND AC AUXILIARY POWER SUPPLIES

7.1 General

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

equipment , Data processing equipment in the various control centers, Air conditioning and

security lighting in Control Centers .

They are one of the following 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 Power grid 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.

7.2. AC auxiliary power supplies in Control Centers

7.2.1. Making–up of 415/240V AC uninterruptible power supply in Control Centers

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….

7.3. 48V DC system in control center

7.3.1. 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 simultaneously operating in parallel ,

• 1 lead-acid stationary type battery ,

• 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 rectifiers.

7.4. 48V DC system in sub-station

7.4.1. 48V DC system making-up in sub-station:

A sub-station 48V DC system compries2 rectifiers simultaneously operating in parallel and

sharing the total current demand

• 1 lead-acid battery

• 1 distribution board

7.4.2. 48V DC system sizing and BOQs in sub-stations

Adequately sized batteries and rectifiers will be provided by some SEBs/boards/central

Sectors themselves as a part of the sub-station power/plant components.

8. TOTAL COST BENEFITS OF THE PROJECT

8.1 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. 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

8.2 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

8.3 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

• Improved Reliability Procedures

• Improved Operator Training

• Organization Improvement

CHAPTER 5

CONCLUSION

The whole training was full of knowledge regarding the live environment of

companies as well as knowledge of core industry. This tour also provided the students to

inculcate the students with a little something extra in a manner of enjoyment too.

Such industrial training are not just for fun and enjoyment but are useful in developing a

corporate attitude and mindset of the individual and to become more aware and focused

towards the outlook of the professional world. These training are really helpful to get

practical knowledge and to know about the implementation of recent trends of technologies

to increase the efficiency of system.

Here by doing the training from the SLDC (State Load Dispatch Center) unit of

R.R.V.P.N.L. (Rajasthan Rajya Vidhyut Prasaran Nigam) ,heerapura, jaipur, we came to

know about the present electrical system of the India and the government organization that

are responsible for that. And the technologies going to use for distribution of the electrical

signals as well as the automatic control system. The practical application of SCADA

system are also came into our mind library that how the whole electrical system efficiency

could be maintained by the closed loop system providing the feedback signals that are

electronics signal and those signal are analyzed by the computer system of monitored by

system regularly that system is called the SCADA system.

Hence the every moment of the training was fruitful in not only technical sense but also for

the general industrial approach wise too.