POWER SYSTEM AUTOMATION B. E. SEMINAR

Submitted to North Maharashtra University, Jalgaon in Partial Fulfillment of the

Requirements for the Degree of BACHELOR OF ENGINEERING in

Electrical Engineering.

By

Dhiraj Machhindra Bhalerao

(Examination Number )

Guide

Prof. G. K. Andulkar

DEPARTMENT OF

ELECTRICAL ENGINEERING

GOVERNMENT COLLEGE OF ENGINEERING, JALGAON 425002

NOVEMBER 2015

GOVERNMENT COLLEGE OF ENGINEERING, JALGAON

DEPERTMENT OF ELECTRICAL ENGINEERING

CERTIFICATE

This is to certify that the seminar entitled “POWER SYSTEM AUTOMATION”, which is

being submitted herewith for the award of B.E in the result of the work completed by DHIRAJ

M. BHALERAO, under my supervision and guidance within the four walls of the institute and

the same has not been submitted elsewhere for the award of any degree.

(Prof. G. K. Andurkar) (Prof. G. K. Andurkar)

Seminar Guide Head of Electrical department

(Dr. R. P. Borkar) Examiner

Principle, GCOEJ

ii

DECLERATION

I hereby declare that the seminar entitled “POWER SYSTEM AUTOMATION” was carried out

and written by me under the guidance of Prof. Andurkar, professor of electrical department,

Government college of engineering jalgaon. This work has not been previously formed the basis

for the award of any degree or diploma or certificate not has been submitted as elsewhere for the

of award of any degree or diploma.

DHIRAJ M. BHALERAO

Place: Jalgaon

Date:

ACKNOWLEDGEMENT

The successful completion of any task would not be complete without expression of

gratitude to all those who helped in doing that task. I hereby take this opportunity to express our

heartfelt gratitude towards the people who help proved useful to complete my seminar on

“POWER SYSTEM AUTOMATION”

First I wish to express my gratitude sincere thanks to our principal Dr. R.P.Borkar, whose

guidance and suggestions have helped me in completing this seminar report. My special thanks to

Prof. Andurkar for his valuable suggestions in project work.

In particular, I am thankful to all our staff members of Electrical Engineering department

for their whole hearted co-operation. I am thankful to my parents for their blessing and their

valuable moral support. Without their supports I can’t do anything.

Last but not the least I am very much thankful to our friends for supporting me in presentation

of this seminar.

Dhiraj M. Bhalerao

(B.E Electrical)

ABSTRACT

Electrical power distribution system is an important part of electrical system

in delivery of electricity to consumers. Electric power utilities worldwide are

increasingly adopting the computer aided monitoring, control and management of

electric power distribution system to provide better services to consumers.

Therefore, research and development activities worldwide are being carried out to

automate the electric power distribution system utilizing recent advancements in

the area of Information Technology (IT) and data communication system.

In power system automation, data acquisition system plays a major role as a

base of the power system automation. From the recent trends and developments in

Power System Automation, Computerized system Automation is most efficient

compared to normal systems. Computerized Power Network for Data Acquisition

system helps the system and controller to meter and monitor the values for further

manipulations for full-scale power system automation and system controlling.

CHAPTER 1

INTRODUCTION

Power System Automation is one of the important aspects in an electrical power

network that needs careful investigation. In power system automation, data

acquisition system plays a major role as a base of the power system automation.

From the recent trends and developments in Power System Automation,

Computerized system Automation is most efficient compared to normal systems.

Computerized Power Network for Data Acquisition system helps the system and

controller to meter and monitor the values for further manipulations for full-scale

power system automation and system controlling.

The Computerized Data Acquisition for Metering and Monitoring of Power System

Automation can be divided into three general categories as Data collection,

Metering & Monitoring. The Data collection system collects the data from the

Power system Network using the Digital Power Monitors through the current

transformers and potential transformers. The collected data will be Metered by the

Digital Power Monitor where the Monitor consists of a Micro Controller with the

peripherals like memory, A/D converter and Sample and hold circuitry. According

to the programming done in the Microcontroller the Power Monitor will store the

parameters in the memory and it will do all the logical and arithmetic calculations

to manipulate the parameters and to calculate the different Power data’s like KWH,

KVAR, KVA, PF etc,. The collected parameters of the Power System and the

calculated power data can be monitored on the screen of the Digital Power Monitor.

The values will be sent to the Computer System using the Communication system

like Serial Communication RS485 and RS 232 for n no of Power Monitors using

the Data Converter.

This section describes power system automation protection and control which is

aimed at the improvement of the management of power networks is being adopted

by increasing by number of supply authorities. Automation, Protection, Local

control, Operator interfaces, Communication, Remote control and Monitoring

functions, most of which were previously utilized with relays or modules for each

function, are now integrated into multi-function PLC (programmable logic

Controller) based units and interconnected on various types of local area networks.

The components of the system will have a better communication with each other

sharing information through the local area network and systems work similarly

because one sensor is enough to collect one network information and transferred

the information throughout the network using LAN and communication mediums

instead of one sensor per each component as before. To achieve we need a better

system apart from different systems like protection, Communication, RTU’s, IED’s

etc. called as Data acquisition system without the perfect data communication

system the components of the total system can’t perform the right tasks at right time

because of the disturbance in the collected. To overcome this problem we have

designed a better Data Acquisition system with the efficient technology and with

the perfect communication systems to transfer the data. The system is named as

“Computerized Power Network Data Acquisition and Monitoring for Power System

Automation”. The system acquires the data from the power network (data

acquisition) for monitoring. The software was developed to do all the manipulations

and the parameters and data of the system can be viewed in different forms (analog,

digital, graphical). The software developed will be used to view the captured data’s

from the Power Monitor in different forms like Analog Metering, Digital data and

in graphical form. The software will generate the reports for all the different types

of manipulations like power fail, CT or PT fail Low PF etc, the software will save

the data 6 times per day in form of reports.

CHAPTER 2

LITERATURE SURVEY

2.1 Operation system interaction-

The Substation-automation is processed in three parts mainly. First one is Input

signal characterization based on Analog signal (continuous electrical signals such

as active power, reactive power, frequency, Voltage etc.) or Digital signal

(switching signals high or low, isolator open or brake etc.). The second one is

processing the data like analog signal conversion to digital signal via fiber optics.

This is to be carried out by a protocol sequence with a real time operating system

(RTO) and lastly the output analyzing. The results are to be expressed in user

friendly environment like displays. The data communication is done to substation

via telephone lines, fiber optic cables, satellite, power lines. The Open Systems

Interconnection model (OSI) is a conceptual model that characterizes and

standardizes the internal functions of a communication system by partitioning it

into abstraction layers. The OSI model works analogous to letter from sender to

receiver. In the first level the sender written a letter, put it on envelope and drop it

in letter box. In the second level of process the letter is carried out from mailbox to

post-office. Later it was delivered to a carrier from the post office. It was travelled

by certain transmission system and delivered to destination post office, reached to

receiver via carrier, the receiver opens the envelope and reads the information.

2.2 Need of power system automation-

Demand of electricity is increase day by day that’s why transmission lines are

getting to much complex. As the number of consumers and industrial load increase

proper metering is required for exact measurement of power consumption.

Transmission line equivalent circuit parameters are often 25% to 30% in error as

compared to values measured by the SCADA system. These errors cause the

economic dispatch to be wrong, and lead to increased costs or incorrect billing. The

parameter errors also affect contingency analysis, short circuit analysis, distance

relaying, machine stability calculations, transmission planning, and state estimator

analysis. An economic example is used to demonstrate the affect of transmission

line errors. SCADA measurements from several utilities are used to compute the

'real world' value of the transmission line parameters. State estimation with the

estimated parameters is compared to the computations using the theoretical

Electric utilities must meet increasing demand for reliable power distribution while

coping with decreasing tolerance for disruptions and outages. More than ever,

utilities are squeezed to do more with less, and recognize the need to improve the

efficiency of their power generation and distribution systems.

Fortunately, many areas of the existing electrical distribution system can be

improved through automation. Furthermore, by automating the distribution system

now, utilities will be ready to meet the challenges of integrating intermittent supply

sources like solar, wind and other distributed energy resources (DERs).

Automating electrical distributions systems by implementing a supervisory control

and data acquisition (SCADA) system is the one of the most cost-effective solutions

for improving reliability, increasing utilization and cutting costs.

2.3 Status of automation in the India-

Electric utilities, all around the world, have realized the problems associated with

vertically integrated electric power systems and therefore they are moving towards

unbundled model of generation companies(GENCOs), transmission companies

(TRANSCOs), distribution companies (DISCOs), and energy service companies

(ESCOs). In the past, all electric power distribution-related functions could be

transparently coordinated along the complete supply chain. In the future, many

distribution companies will manage third-party contacts by delivering bulk power

from GENCOs and TRANSCOs to meters owned by ESCOs. At the same time,

many state regulatory commissions are considering the viability of retail wheeling

(small generators connected to the distribution system selling electricity directly to

consumers). In addition to planning and operating difficulties, retail wheeling asks

distribution systems to perform the functions for which they were not designed. In

view of the above, on-line information, remote control and efficient management

system are required for power distribution utilities. Considering the extensive size

of the network, these tasks can be efficiently achieved through the intervention of

information technology utilizing the available high- speed computer and

communication technology. This system of monitoring and control of electric

power distribution networks is also called as “Distribution Automation (DA)”

system. The Institute of Electrical and Electronic Engineers (IEEE) has defined

Distribution Automation System (DAS) as a system that enables an electric utility

to remotely monitor, coordinate and operate distribution components, in a real-time

mode from remote locations. The distribution automation system is based on an

integrated technology, which involves collecting data and analyzing information to

make control decisions, implementing the appropriate control decisions in the field,

and also verifying that the desired result is achieved. The location, from where

control decisions are initiated, is generally called Distribution Control Centre

(DCC).

At present, power utilities have realized the need for full scale distribution

automation to achieve on-line system information and remote control system. This

is required in order to fully accomplish the restricting (GENCOs, TRANSCOs,

DISCOs, and ESCOs) of the power system to the level of retail wheeling [1, 5]. On

the other hand, the main motivation for accepting the distribution automation in

developing countries such as India is to improve operating efficiency of distribution

system. This indicates worldwide interest for distribution automation at present.

Looking at the interest of power utilities for distribution automation, academic

institutions are now taking interest to introduce courses and R& D activities in the

field of DA in the regular academic curriculum. A list of possible research areas

and activities for future is also proposed for power distribution automation.[2]

CHAPTER 3

POWER SYSTEM & AUTOMATION

3.1 Power system-

An electric power system is a network of electrical components used to supply,

transmit and use electric power. An example of an electric power system is the

network that supplies a region's homes and industry with power—for sizable

regions, this power system is known as the grid and can be broadly divided into

the generators that supply the power, the transmission system that carries the power

from the generating centres to the load centres and the distribution system that feeds

the power to nearby homes and industries. Smaller power systems are also found in

industry, hospitals, commercial buildings and homes. The majority of these systems

rely upon three-phase AC power—the standard for large-scale power transmission

and distribution across the modern world.

Generating stations, transmission lines and distribution system are the main component

of an electrical system. Generating station and distributed substation are connected

through transmission lines, which also connects one power system to another. A

distribution system connects all the loads in a particular area to the transmission line.[1]

3.2 How does Power reach us?-

Electric power is normally generated at 11-25kV in a power station. To transmit over long

distances, it is then stepped-up to 400kV, 220kV or 132kV as necessary. Power is carried

through a transmission network of high voltage lines. Usually, these lines run into

hundreds of kilometers and deliver the power into a common power pool called the grid.

The grid is connected to load centers (cities) through a sub- transmission network of

normally 33kV (or sometimes 66kV) lines. These lines terminate into a 33kV (or 66kV)

substation, where the voltage is stepped-down to 11kV for power distribution to load

points through a distribution network of lines at 11kV and lower. The power network,

which generally concerns the common man, is the distribution network of 11kV lines or

feeders downstream of the 33kV substation. Each 11kV feeder which emanates from the

33kV substation branches further into several subsidiary 11kV feeders to carry power

close to the load points (localities, industrial areas, villages, etc.,). At these load points, a

transformer further reduces the voltage from 11kV to 415V to provide the last-mile

connection through 415V feeders (also called as Low Tension (LT) feeders) to individual

customers, either at 240V (as single-phase supply) or at 415V (as three- phase supply). A

feeder could be either an overhead line or an underground cable. In urban areas, owing

to the density of customers, the length of an 11kV feeder is generally up to 3 km. On the

other hand, in rural areas, the feeder length is much larger (up to 20 km). A 415V feeder

should normally be restricted to about 0.5-1.0 km. duly long feeder’s lead to low voltage

at the consumer end.

3.3 Automation-

The word ‘Automation’ is derived from greek words “Auto” (self) and “Matos”

(moving). Automation therefore is the mechanism for systems that “move by itself”.

However, apart from this original sense of the word, automated systems also

achieve significantly superior performance than what is possible with manual

systems, in terms of power, precision and speed of operation.

Automation is a set of technologies that results in operation of machines and

systems without significant human intervention and achieves performance superior

to manual operation

The application of machines to tasks once performed by human beings or,

increasingly, to tasks that would otherwise be impossible. Although the term

mechanization is often used to refer to the simple replacement of human labour by

machines, automation generally implies the integration of machines into a self-

governing system

Fig 3.2 Automation system

3.4 Power system Automation-

Power System Automation is a system for managing, controlling and protecting the

various components connected to the power network. It obtains the real time

information from the system, local and remote control applications with advanced

electrical system protection. The core of power system automation stands on local

intelligence, data communications with supervisory control and monitoring.

Electrical Protection

Control

Measurement

Monitoring

Data communication

Electrical Protection- Electrical Protection is the most important concept of the

Power system Automation, to protect the equipment and personnel and to limit the

damage at fault. It is a local function and it has the capability to function

independently from the Automation if necessary, although it is a part of Power

system Automation the function of electrical protection never restricted in Power

system Automation.

Control- Control application of a Power system Automation includes local and

remote control. Local control consists of actions the control device can logically

take by itself (Bay interlocking, switching sequences, and synchronizing check).

Human intervention is limited and the risk was greatly reduced. Remote control

functions to control Substations remotely from the SCADA. Commands can be

given directly to the remote control devices (open and close of circuit breakers,

relay settings, requests for information from the SCADA station). This eliminates

the personnel performance switching operations, actions can be performed faster.

A safe working environment is created for personnel and the operator or engineer

at the SCADA has a complete over view of the entire Power network.

Measurement- Measurement is one of important concept in Power system

Automation. The real time information about a substation or equipment is collected

and displayed in the control center and stored in a data base for further

manipulations, It erases the personnel to go to substation or switching area collect

the information cutting down workloads. The information collected can assist in

doing network studies like load flow analysis, planning ahead and preventing

disturbances in the Power network. Previously the word ‘Measurement’ refer to

voltage, current and frequency, and the word ‘Metering’ refer to power, reactive

power and energy (KWh). The different terms used because different instruments

were used for these applications, now the two functions are integrated in modern

devices hence the terms are used interchangeably in the text.

Monitoring- Monitoring is specified for the maintenance of the Power system

Automation. It monitors sequence of records, status and condition of the system,

maintenance information and relay settings etc. The information can help in fault

analysis, what where when why it happened. It is used to improve the efficiency of

the system. Data Communication Normally Communication forms a core for any

system, in Power system Automation Data communication forms core of the power

system Automation. Without communication the local device and protection tasks

can be performed individually. But without data communication there is no mean

to say Power system Automation.[5]

CHAPTER 4

SUPERVISORY CONTROL AND DATA ACQUISITION

(SCADA)

4.1 What is SCADA-

SCADA is an acronym for Supervisory Control and Data Acquisition. SCADA

systems are used to monitor and control a plant or equipment in industries such as

telecommunications, water and waste control, energy, oil and gas refining and

transportation. These systems encompass the transfer of data between a SCADA

central host computer and a number of Remote Terminal Units (RTUs) and/or

Programmable Logic Controllers (PLCs), and the central host and the operator

terminals. A SCADA system gathers information (such as where a leak on a

pipeline has occurred), transfers the information back to a central site, then alerts

the home station that a 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. These systems can be relatively simple, such as one

that monitors environmental conditions of a small office building, or very complex,

such as a system that monitors all the activity in a nuclear power plant or the activity

of a municipal water system. Traditionally, SCADA systems have made use of the

Public Switched Network (PSN) for monitoring purposes. Today many systems are

monitored using the infrastructure of the corporate Local Area Network

(LAN)/Wide Area Network (WAN). Wireless technologies are now being widely

deployed for purposes of monitoring.

4.2 Components of SCADA-

SCADA systems consist of:

• One or more field data interface devices, usually RTUs, or PLCs, which interface to field sensing devices and local control switchboxes and valve actuators

• A communications system used to transfer data between field data interface devices and control units and the computers in the SCADA central host. The system can be radio, telephone, cable, satellite, etc., or any combination of these.

• A central host computer server or servers (sometimes called a SCADA Center, master station, or Master Terminal Unit (MTU)

• A collection of standard and/or custom software [sometimes called Human Machine Interface (HMI) software or Man Machine Interface (MMI) software] systems used to provide the SCADA central host and operator terminal application, support the communications system, and monitor and control remotely located field data interface devices

Figure 4.1 shows a very basic SCADA system, while Figure 4.2 shows a typical

SCADA system. Each of the above system components will be discussed in detail

in the next sections.

Fig 4.1 Basic SCADA system

Fig 4.2 Typical SCADA system

1) Field Data Interface Devices-

Field data interface devices form the "eyes and ears" of a SCADA system. Devices

such as reservoir level meters, water flow meters, valve position transmitters,

temperature transmitters, power consumption meters, and pressure meters all

provide information that can tell an experienced operator how well a water

distribution system is performing. In addition, equipment such as electric valve

actuators, motor control switchboards, and electronic chemical dosing facilities can

be used to form the "hands" of the SCADA system and assist in automating the

process of distributing water.

However, before any automation or remote monitoring can be achieved, the

information that is passed to and from the field data interface devices must be

converted to a form that is compatible with the language of the SCADA system. To

achieve this, some form of electronic field data interface is required. RTUs, also

known as Remote Telemetry Units, provide this interface. They are primarily used

to convert electronic signals received from field interface devices into the language

(known as the communication protocol) used to transmit the data over a

communication channel.

The instructions for the automation of field data interface devices, such as pump

control logic, are usually stored locally. This is largely due to the limited bandwidth

typical of communications links between the SCADA central host computer and

the field data interface devices. Such instructions are traditionally held within the

PLCs, which have in the past been physically separate from RTUs. A PLC is a

device used to automate monitoring and control of industrial facilities. It can be

used as a stand-alone or in conjunction with a SCADA or other system. PLCs

connect directly to field data interface devices and incorporate programmed

intelligence in the form of logical procedures that will be executed in the event of

certain field conditions.

PLCs have their origins in the automation industry and therefore are often used in

manufacturing and process plant applications. The need for PLCs to connect to

communication channels was not great in these applications, as they often were only

required to replace traditional relay logic systems or pneumatic controllers. SCADA

systems, on the other hand, have origins in early telemetry applications, where it

was only necessary to know basic information from a remote source. The RTUs

connected to these systems had no need for control programming because the local

control algorithm was held in the relay switching logic.

As PLCs were used more often to replace relay switching logic control systems,

telemetry was used more and more with PLCs at the remote sites. It became

desirable to influence the program within the PLC through the use of a remote

signal. This is in effect the "Supervisory Control" part of the acronym SCADA.

Where only a simple local control program was required, it became possible to store

this program within the RTU and perform the control within that device. At the

same time, traditional PLCs included communications modules that would allow

PLCs to report the state of the control program to a computer plugged into the PLC

or to a remote computer via a telephone line. PLC and RTU manufacturers therefore

compete for the same market.

As a result of these developments, the line between PLCs and RTUs has blurred

and the terminology is virtually interchangeable. For the sake of simplicity, the term

RTU will be used to refer to a remote field data interface device; however, such a

device could include automation programming that traditionally would have been

classified as a PLC.

2) Communications Network-

The communications network is intended to provide the means by which data can

be transferred between the central host computer servers and the field-based RTUs.

The Communication Network refers to the equipment needed to transfer data to and

from different sites. The medium used can either be cable, telephone or radio.

The use of cable is usually implemented in a factory. This is not practical for

systems covering large geographical areas because of the high cost of the cables,

conduits and the extensive labor in installing them. The use of telephone lines (i.e.,

leased or dial-up) is a more economical solution for systems with large coverage.

The leased line is used for systems requiring on-line connection with the remote

stations. This is expensive since one telephone line will be needed per site. Dial-up

lines can be used on systems requiring updates at regular intervals (e.g., hourly

updates). Here ordinary telephone lines can be used. The host can dial a particular

number of a remote site to get the readings and send commands.

Remote sites are usually not accessible by telephone lines. The use of radio offers

an economical solution. Radio modems are used to connect the remote sites to the

host. An on-line operation can also be implemented on the radio system. For

locations where a direct radio link cannot be established, a radio repeater is used to

link these sites.

Historically, SCADA networks have been dedicated networks; however, with the

increased deployment of office LANs and WANs as a solution for interoffice

computer networking, there exists the possibility to integrate SCADA LANs into

everyday office computer networks.

The foremost advantage of this arrangement is that there is no need to invest in a

separate computer network for SCADA operator terminals. In addition, there is an

easy path to integrating SCADA data with existing office applications, such as

spreadsheets, work management systems, data history databases, Geographic

Information System (GIS) systems, and water distribution modeling systems.

3) Central Host Computer -

The central host computer or master station is most often a single computer or a

network of computer servers that provide a man-machine operator interface to the

SCADA system. The computers process the information received from and sent to

the RTU sites and present it to human operators in a form that the operators can

work with. Operator terminals are connected to the central host computer by a

LAN/WAN so that the viewing screens and associated data can be displayed for the

operators. Recent SCADA systems are able to offer high resolution computer

graphics to display a graphical user interface or mimic screen of the site or water

supply network in question. Historically, SCADA vendors offered proprietary

hardware, operating systems, and software that was largely incompatible with other

vendors' SCADA systems. Expanding the system required a further contract with

the original SCADA vendor. Host computer platforms characteristically employed

UNIX-based architecture, and the host computer network was physically removed

from any office-computing domain.

However, with the increased use of the personal computer, computer networking

has become commonplace in the office and as a result, SCADA systems are now

available that can network with office-based personal computers. Indeed, many of

today's SCADA systems can reside on computer servers that are identical to those

servers and computers used for traditional office applications. This has opened a

range of possibilities for the linking of SCADA systems to office-based applications

such as GIS systems, hydraulic modeling software, drawing management systems,

work scheduling systems, and information databases.

4) Operator Workstations and Software Components-

Operator workstations are most often computer terminals that are networked with

the SCADA central host computer. The central host computer acts as a server for

the SCADA application, and the operator terminals are clients that request and send

information to the central host computer based on the request and action of the

operators.

An important aspect of every SCADA system is the computer software used within

the system. The most obvious software component is the operator interface or Man

Machine Interface/Human Machine Interface (MMI/HMI) package; however,

software of some form pervades all levels of a SCADA system. Depending on the

size and nature of the SCADA application, software can be a significant cost item

when developing, maintaining, and expanding a SCADA system. When software is

well defined, designed, written, checked, and tested, a successful SCADA system

will likely be produced. Poor performances in any of these project phases will very

easily cause a SCADA project to fail.

Many SCADA systems employ commercial proprietary software upon which the

SCADA system is developed. The proprietary software often is configured for a

specific hardware platform and may not interface with the software or hardware

produced by competing vendors. A wide range of commercial off-the-shelf (COTS)

software products also are available, some of which may suit the required

application. COTS software usually is more flexible, and will interface with

different types of hardware and software. Generally, the focus of proprietary

software is on processes and control functionality, while COTS software

emphasizes compatibility with a variety of equipment and instrumentation. It is

therefore important to ensure that adequate planning is undertaken to select the

software systems appropriate to any new SCADA system.

Software products typically used within a SCADA system are as follows:

• Central host computer operating system: Software used to control the central host computer hardware. The software can be based on UNIX or other popular operating systems.

• Operator terminal operating system: Software used to control the central host computer hardware. The software is usually the same as the central host computer operating system. This software, along with that for the central host computer, usually contributes to the networking of the central host and the operator terminals.

• Central host computer application: Software that handles the transmittal and reception of data to and from the RTUs and the central host. The software also

provides the graphical user interface which offers site mimic screens, alarm pages, trend pages, and control functions.

• Operator terminal application: Application that enables users to access information available on the central host computer application. It is usually a subset of the software used on the central host computers.

• Communications protocol drivers: Software that is usually based within the central host and the RTUs, and is required to control the translation and interpretation of the data between ends of the communications links in the system. The protocol drivers prepare the data for use either at the field devices or the central host end of the system.

• Communications network management software: Software required to control the communications network and to allow the communications networks themselves to be monitored for performance and failures.

• RTU automation software: Software that allows engineering staff to configure and maintain the application housed within the RTUs (or PLCs). Most often this includes the local automation application and any data processing tasks that are performed within the RTU.

The preceding software products provide the building blocks for the application-

specific software, which must be defined, designed, written, tested, and deployed

for each SCADA system.[3]

4.3 Classification & Working of SCADA in Power system automation-

Power system automation is classified into 2 types-

a) Substation Automation

b) Distribution Automation

a) Substation Automation- Substation automation is not a new concept. Substations

have been equipped to perform automatic re closing, bus sectionalizing, load

transfers, capacitor switching, etc. for many years. In the past, these and other

functions were implemented using a combination of control panels, auxiliary relays,

switches, lights, meters, transducers and extensive wiring and cabling. In many

applications today, this perception is probably because developments in substation

equipment have expanded the potential capabilities of substation. Automation far

beyond that which could previously be reasonably accomplished. The principal

development is generically defined as an Intelligent Electronic Device (IED) which

typically consists of one or more Programmable Logic Controllers and

communications ports; with the ability to transmit data and execute control

commands, and frequently provide a local user interface. Typical examples are

relays, meters, and specialized sensors. Prior to the introduction of Numerical

relays, the protection and control of a very small substation consisting of one

incoming line, one transformer and two feeders would require four large panels

filled with relays, switches and lights. Only one panel is required when Numerical

relays are used. Interestingly, at the same time the space requirements are reduced

by a factor of four, so the installed cost.

Advances in communications technology are used to tie everything together into a

useful network. Within the substation, a single high-speed Local Area Network

(LAN) is used to transmit data and control commands, replacing the extensive and

costly cables that had been required. At the present time, a number of different LAN

techniques and protocols are in use. The industry is actively working on

development of a new standard LAN definition that will be based on the use of

Ethernet and Manufacturing Messaging Specification (MMS) and will be

compatible with the Utility Communications Architecture (UCA). There are already

many techniques for moving data out of the substation to a master station or to other

substations. These include the use of leased or dedicated telephone lines, dial-up

phone lines, cellular telemetry techniques, satellite transmissions, various flavors

of radio techniques and fiber-optic networks. Basically, this variety of

communications methods results in the ability to transmit large amounts of

information at a rapidly declining cost per bit. The combination of PLC based

devices and communications technology creates the ability to obtain more

information about the power system and the equipment being used. Power system

variables include magnitude and angle of voltages and currents, real and reactive

power, frequency, power factors etc. Information is available regarding the

initiating event for relay operation, the location of faults, and fault analysis.

Specialized sensors and transducers are used to build a database relating to

equipment condition and use; so that analysis techniques can be used to determine

equipment condition and base maintenance activities on actual condition rather than

time schedules. Within the substation, the use of Programmable Logic Controllers

or other types of computers opens up a vast array of automation possibilities.

Complex schemes for dead bus and dead line re-closing can be implemented, with

the sequence being based on actual power system conditions that exist at the time.

Re-closing of circuits can be modified based on cold load pickup requirements.

Load transfers between busses and transformers can be made to protect against

transformer overloads. Bus voltages and power factors can be tightly controlled to

minimize losses or voltage variations. Supplementary measurements and inputs can

be used to initiate automatic equipment reenergizing after a transformer or bus

differential.

Distribution Automation-

The above figure has shown the single line diagram of SCADA system in

load dispatch centre. Its consist of different elements like Transducer, RTU

(Remote terminal unit), PLCC (power line carrier communication), MMI (Man

machine interface),Telecontrol interface.

Initially the data sense by Transducer, the Transducer is device which sense

the changes in power system parameter like voltage, load current, reactive power,

real power and status of circuit breaker, isolator and when converted in suitable

form ,which is useful for further process. The Transducer is connected at an

auxiliary terminal of current transformer and potential transformer. The

Transducers are two types, first is Analog Transducer and second is Digital

Transducer. The Analog current Transducer is used for measuring the current,

Similarly the Analog voltage Transducer used for measuring the voltage. If we

required measuring the Reactive power and real power of the line, at this instant

both current and potential transducers are used. The Digital Transducer is used for

observing the status of the circuit breaker and isolator. The digital transducer is

transfer the signal in binary form or 0and 1.If the circuit breaker and isolator is

open, then the value of signal is zero and vice- versa .the signal is transmitted from

transducer to RTU.

The output +/- 10mA is indicates that the SCADA system is bidirectional. The RTU

send a massage to the master unit, after receiving a massage the master unit is send

the acknowledgement signal to the RTU.If due to any reason a massage is not

display in proper manner then this instant the master unit is send the request signal

to RTU. The RTU consist of three unit 1) AE (analog input card), 2) DE (digital

input card) and 3) FWP (frequency width pulse).

The analog input card is collected the analog data like Load current, Voltage,

Reactive power, Real power and Frequency. The digital input card is collected the

digital data like status of circuit breaker and isolator .In RTU this analog and digital

signal is converted into a digital form by protocol.

The width of the pulse is maintained or control by FWP, the frequency width pulse

maintains the pulse at 0 to250 binary value. This binary value is transferred to the

variable frequency telemetry is increases the frequency level from 2.5KHz to

4KHz.It transfer the signal at 4KHz and received a signal at 2.4KHz.This signal is

transferred to the power line carrier communication. The PLCC is a communication

media; its depending on frequency range and the distance between RTU and master

unit. The data is transferred through the protection line of the power system.

The signal is received by PLCC and VFT in Load Dispatch Center after this unit, a

signal is received by Tele control interface, the Tele control interface is converted

the signal in spectrum form. The MMI (man machine interference) is continuously

data on the monitor, which is helpful for the dispatcher to take the decision as per

system requirement.[7]

Fig 4.3 Single line diagram used in SCADA system

F

MW TRANSDUCER

800 - 0 - 800 O/P +/ -

10 mA A.E.

D.E.

FWP to 0 250

Binary value

VFT 2.4

– 4 KHz PLCC

50 –

KHZ 500

VFT 2.4 – 4 KHz

PLCC

50 – 500 KHZ Tele

Control Interface

MMI 220

RTU

CHAPTER 5

CONCLUSION

1. Improved quality of service and reduced manpower requirements

2. Improved reliability with reduced system implementation costs

3. Maintenance/expansion of customer base and Reduced operating costs

4. High value service provider and reduced maintenance costs

5. Added value services with the ability to defer capacity addition projects

6. Improved customer access to information and also improved information for

engineering decisions

7. Enterprise information accessibility along with improved information for

planning decisions

8. Flexible Billing Options and reduced customer outage minutes

The SCADA system plays an important role in power system automation. A rich

functionality, extensive control and supervision facilities. Reliability and

robustness. These systems are used for mission critical industrial process where

reliability and performances paramount. In addition, specific development is

performed within a well-established control center that enhances reliability and

robustness. Technical support and maintenance are made easy in any power system

process. The application of SCADA in electrical engineering results in reduction of

complexity for the operators to handle the electrical components.

REFERENCES

1. J. B. Gupta, Electrical power system, SK publications, pg no. part II 1 to 10, 2005

2. Gaur & Gaur, Automation in power distribution system: Present status,

E-ISSN0976-7916, Page no. 1-3, 2012

3. Jason stamp & Michel Berg, Reference Model for Control and Automation

Systems in Electrical Power, vol. 1.2 ,8-16, 10 oct. 2005

4. National communication system, Supervisory Control And Data Acquisition

(SCADA) systems, Tech. info. Bulletin, Vol. NCS TIB 04-1, Oct 2004

5. Power system automation, NPTEL, Dept. of elect engg., page no. 1-16, Sept.

2015

6. Shabnam Rukhsar, SCADA in Transmission Line, IOSR Journal of Electrical

and Electronics Engineering, e-ISSN: 2278-1676, p-ISSN: 2320-3331,Page no. 67

to 71,2014

7. http://www.iosrjournals.org