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Technical Sessions 

Contents 

I - Substation Automation and Integration 

1. IEC 61850: Role of Conformance Testing in Successful Integration 

Eric A. Udren, Willem Strabbing, Dave Dolezilek 

KEMA Consulting - USA KEMA Consulting Netherlands 

Schweitzer Engineering Laboratories - USA 

2. Requirements of Interoperability and Communication Redundancy In IEC 

61850 based SA Systems 

Rajiv Krishnan, ABB Limited, Bangalore 

3. IEC 61850 Standards in Substation Automation 

G Krishnamurthy Kerur, Easun Reyrolle Ltd, Bangalore 

4. Modular Concept For Protection & Substation Automation For lee 61850 

Based Ehv Substations 

Kuldeep Tickoo, Bhupendra Badiya, Siemens - India 

5. Advanced Substation Automation: An Overview 

Dr. R. P. Gupta, Distribution Automation Research Centre, CG Global R & 

D Centre, Crompton Greaves Ltd., Mumbai - 400 042, India 

6. Planning for the Successful Integration of Substation Communications 

J.M Shaw, Garret/Com, Inc. 

7. IEC 61850 Substation LAN - Issues to Consider when Designing and 

Deploying Ethernet 

Networks 

Roger Moore, and Rene Midence, RuggedCom 

II - Control Centre 

8. Control Center Design Today 

Dr. Michael Wolf, PSI CNI GmbH, Germany 

9. Human-Machine Interface for Large-Scale Distribution Management 

Systems 

Dr. Michael Wolf 

lOUse of Large Screen Displays in Automated Industries - 

Broader process views for improved abnormal situation management. 

Barco 

III- Economics of Automation 

11 Cost Justification of SCADA/DMS Due to Loss Reduction 

Albana 110, Roland Eichler and Vikram Gandotra, Siemens India 

12 The Cost of Network Control 

Dr. Michael Wolf, with PSI CNI GmbH, Germany 

13 Innovative Optical Sensor Technology - The Foundation of Cost Effective 

MVILV Distribution Network Monitoring 

James Northcote-Green, Martin Speiermann and Alfred Manohar 

Consultant, ABB and PowerSens, UK, PowerSense AlS , Amtech Automation 

, Bangalore, India

47 Implementation of SCADAIEMS System for Distribution System 

Automation 

P. V.Chopade, D. G.Bharadwaj, Bharati Vidyappeth University College of 

Engineering, Pune, INDIA 

48 NDPL Substation Automation Project: Step forward for Automation 

integration 

Sanjay kumar Banga and Ajay Prashant Biswas, NDPL, New Delhi 

49 Omniagate 

)

Paper for National Conference on Distribution Automation @CPRI Bangalore 

Implementation of SCADA/EMS System for 

Distribution System Automation 

P.V.Chopade Member IEEE, 

Abstract- Automation of power distribution systems has 

increasingly been adopted by power utilities worldwide in 

recent years. This is to provide a more reliable supply to its 

customers and to enhance operational efficiency. This can 

be used for the distribution network of about llKV to 25 

KV. 

SCADA system can be used as an important building block 

for automation of distribution network. The SCADA system 

was commissioned and became operational in mid 1988. 

Due to continuous network expansion & increasingly 

higher expectations of consumer demands for electrical 

energy are continuously increasing. So the distribution 

system needs continuous upgrading to incorporate more 

remote terminal units (RTUs) as well improved functional 

enhancements. 

In this paper implementation of SCADA system in 

distribution automation & the benefits through 

incorporating such system are presented; along with a case 

study for PECO energy company. 

Index Terms (Keywords) - seA DA/EMS, Distribution System, 

Automation. 

I. INTRODUCTION 

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 subtransmission 

network of normally 33kV (or sometimes 

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

substation, where the voltage is stepped-down to IlkV for 

power distribution to load points through a distribution 

network of lines at IlkV and lower. 

P.V.Chopade is with the Bharati Vidyappeth University College of 

Engineering ,Pune-43, M.S.,INDIA, Member IEEE. ( phone: 

+91- 020-24370991: fax +91 020- 24372998' 

e-mail: plavinchoml.!~ccl.:.org). ~ 

D.G.Bharadwaj is Professor of Electrical Engineering Department and 

Head of Research and Development Cell, Bharati Vidyappeth University 

College of Engineering ,Pune-43, M.S.,INDIA. 

(e-rnail: dattatra\.Mveth.net). 

D.G.Bharadwaj 

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 DA system is 

beneficial in day-to-day operation and maintenance of 

distribution network. The other benefits of the distribution 

automation are: reduced technical and commercial losses, 

improved cash flow, lower electric service restoration time, 

reduction in equipment damage, better availability of system 

information, improved operational planning, remote load 

control and shedding, and enhanced power quality and 

reliability 

I!. NEED OF DISTRIBUTION SYSTEM 

AUTOMATION [I ][2] 

To minimize Distribution Losses: 

The demand for electrical energy is ever increasing. Today 

over 21% (theft apart!!) of the total electrical energy 

generated in India is lost in transmission (4-6%) and 

distribution (15-18%). The electrical power deficit in the 

country is currently about 18%. Clearly, reduction in 

distribution losses can reduce this deficit significantly. It is 

possible to bring down the distribution losses to a 6-8 % 

level in India with the help of newer technological options 

(including new technology) in the electrical power 

distribution sector which will enable better monitoring and 

control. 

To minimize voltage sags & interrupts: 

In general, medium voltage (MV) power distribution 

networks are operated radially, with different levels 

distribution automation. Investment in distribution 

automation is a technical and an economic optimizations 

issue to considered in distribution network design. The 

purpose is minimize long term total costs including costs of 

investments, losses, outages and poor power quality within 

relevant constraints. 

Power quality is of increased concern. Previously, long 

interruptions have been of major interest but nowadays 

focus is on shorter interruptions. From the customer point 

view, short interruptions and voltage sags affect customer 

equipment in the same way. Distribution automation caused 

to control the influence of interruptions and voltage sags.


Novel solutions of distribution automation include, example, 

modern, intelligent systems and equipment for fault 

isolation and optimized operation and control of the 

network. From the customers' point of view interruptions 

and voltage sags have an equally harmful influence on the 

operation of equipment and processes. An interruption is 

defined as the complete loss of voltage « 0.1 p.u) and a 

voltage sag as a voltage drop to between 0.1 and 0.9 p.u. in 

rms voltage [I). Voltage sags can be characterized by 

magnitude, duration, and number [2]. The lower the sag 

magnitude and/or the longer the sag duration, the higher is 

the probability of disoperation of the customer's equipment. 

In radially operated MV networks having circuit breakers 

only at the substation, a customer experiences sags caused 

by faults in the neighboring MV feeders, while customers 

supplied by the faulted feeder will face an interruption. In a 

construction with downstream circuit breakers along the 

feeders, customers will also experience sags caused by faults 

in the neighboring feeders. In this situation, depending on 

the relative location of the customer and the fault, customers 

may also experience interruptions and sags caused by faults 

occurring in the same feeder as the customers themselves. 

Thus distribution automation is essential to 

improve the overall efficiency of distribution system by 

remotely monitoring the distribution system & facilitating 

supervisory control of devices and provides decision 

support tools to improve the system performance. 

111. SCADA {EMS SYSTEM [3] [5] 

SCADA system: 

The term refers to a large ..scale, distributed measurement 

(and control) system. SCADA systems are used to monitor 

or to control chemical or transport processes, in municipal 

water supply systems, to control electric power generation, 

transmission and distribution, gas and oil pipelines, and 

other distributed processes. 

Basically it includes 

I. Data Acquisition (collection) equipment 

2. Data transmission telemetric equipment 

3. Data monitoring equipment 

4. HMI (Human machine interface) 

5. Networks ,communication database & software's etc. 

Communication Between Master Control Station & 

Remote Control Station in SCADA system: 

SCADA equipments are located in master control centre , 

zonal regional control centers, district control centers , 

control rooms of generating stations & large sub-stations. 

SCADA requires two way communication channels between 

master control centers & remote control centers as shown in 

the following diagrams i.e. in figure I & figure 2. 

Traditional power communication system is established 

mainly for intra-company information exchange. Low 

bandwidth and communication isolation hinders large 

infonnation exchange and inter-operation. Deregulation 

results in horizontal merger and consolidation of many 

existing utilities. Inter-company communication and 

integration of data from various control centers, power 

plants. and substations. is required. 

Figure I : SCADA Communication Unit 

2 

Figure 2: Remote Control Station in SCADA system 

El'iGJNHl(L"I(; . 

WOIU\!>,ATlON I 

The possibility and inevitability to perform this integration 

process will drive all utilities toward the standardization of 

data models and communication ·protocols. Existing 

communication tools must be modified or replaced to 

accommodate extensive information exchange. Internet 

based communication network enables information sharing 

and various network applications and provide an ideal 

infrastructure for the next generation of power 

communication network. Various Internet/Intranet 

applications are replacing, upgrading, and extending the 

existing power communication establishment. Open access 

same-time information system (OASIS) is a good example. 

Functions of SCAD A in Electrical power distribution 

system: 

Certain functions are basic to electric utility SCADA 

systems. The more common functions include:. 

I Data Acquisition 

2 Information Display 

3 Supervisory Control 

4 Alarm Processing


5 Information Storage and Reports 

6 Sequence of Events Acquisition 

7 Data Calculations 

8 Special RTU Processing/Control 

IV. OPERATION OF SCADA IN DISTRIBUTION 

SYSTEM AUTOMA nON [7] [ 8] [ 10] 

Levels of Automation:- 

I. Substation Level Automation 

2. Feeder level automation 

3. Customer level automation. 

The distribution system implementing SCADA system It is 

shown in figure 3 

mv feeders 

(DistrituOOn net....nj 

Figure 3: SCADA in Distribution System 

Polling Schemes: 

SCADA systems intended for electric system operations 

almost universally use a polling scheme between the central 

master and individual RTUs. In communications 

engineering parlance the method is known as "Demand 

Assignmentffime Division Multiple Access (DArrDMA)." 

The master station controls all activity and RTUs respond 

only to polling requests. 

Figure 4 illustrates the most common communication 

arrangement. 

Multiple two- or four-wire telephone-grade circuits radiate 

from the master. These communication circuits each operate 

MASTER STATION L 

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Figure 4. Typical multidrop communication system [7 ] 

. in half duplex mode and each operates independently of 

others. One circuit may be dedicated to single RTU, but the 

common and economical approach is to multi-drop or partyline 

several RTUs from a common communication circuit. 

The media for these circuits may be leased telephone 

circuits from a common carrier, private microwave. fiber 

optic cable systems, two-way cable TV, power line carrier, 

or even satellite. Polling and command requests and RTU 

responses are time-multiplexed on each circuit. Each circuit 

terminating at the master station is independently serviced 

on an asynchronous basis by the master station. Information 

rates per channel may range from 300 to 9600 bit& and are 

largely influenced by the measurement point count 

serviced by all RTUs sharing a common circuit. The most 

commonly used information rate is 1200 bit& using 

asynchronous byte-oriented message formats. The polling 

periodicity is established by the necessary response of using 

application functions and by human factor considerations. 

Where acquired data support closed control loops, such as 

automatic generation control (AGC), the data sampling rate 

must be sufficient to maintain desired control loop response. 

For AGC this periodicity generally ranges between 2 and 6 

s. For general operator monitoring of most system 

variables, an update period of about 10 s is generally 

acknowledged to be sufficient. Rapidly changing least 

significant numerals on CRT displays tend to be distracting 

to operators. Not all variables need to be acquired at the 

same period and, in fact, usually are not. The factor which 

usually establishes the basic RTU polling period is the 

desired response to unscheduled events or alarms. 

For electric system operations this period is on the order of 

2-3s. Other information may be selectively acquired at each 

poll period or at multiples of the poll period 

A variation to fixed period polling is the round robin 

approach used by some European systems. Here, each RTUto-master 

message contains an end of message (EOM). 

When the master station detects the EOM the next RTU 

sharing the same communication line is then immediately 

polled. This results in continuous activity on the line with no 

gaps of time. The individual point sampling rate is then 

influenced by the number of RTUs sharing the same line 

and the number of points per RTU and whether or not 

exception reporting is being used. Modern RTUs actually 

scan the connected points at a high rate compared to the 

master station poll period. When a master station poll 

request is received by the RTU, the current values or status 

stored in the RTU memory are fetched on a selective basis 

3


and transmitted to the master station. Polling requests may 

also contain various command and control requests. The 

RTU must distinguish these from information requests and 

respond accordingly.' A command sequence for circuit 

breaker operation is typical. Some form of select-checkoperate 

sequence is almost always used to avoid 

disoperation. SCADA systems intended for distributed data 

acquisition and control within a large substation or power 

plant may utilize a different polling strategy. Where all 

RTUs can be physically located within one or two thousand 

feet of each other, they may be connected to each other, the 

man-machine interface, and a host processor via local area 

network. Such arrangements permit great flexibility in 

communication between system elements or nodes. Instead 

of conventional sequential polling under the complete 

direction of the master station, local area network connected 

systems generally permit exchange of information directly 

between any two nodes on a random basis. Carrier Sense 

Multiple Access (CSMA),Token Ring ,or other schemes 

may be used. Figure 5 shows a simplified block diagram of 

a distributed system where communication can occur 

between any nodes at random basis. Network connected 

local SCADA. system where communications can occur 

between any nodes on a random basis. 

POSSIBLE 

HOST 

PROCESSOR 

DATA 

NETWORK 

j 

I R7U I 

Figure 5 : Network Connected to local SCADA 

Data Inputs 

SCADA systems intended for electric system operations are 

most frequently called on to monitor the following 

information from substations and power plants: 

Substations 

bus voltages line flows (MW, MYAR, A) transformer tap 

positions circuit breaker, switch, other device status alarms 

MW sequence-of events. unit generation MW and MY AR 

auxiliaries MW and MY AR unit MWh auxiliaries MWh 

station net MW, M'YAR unit maximum and control limits 

unit performance information gate position and limits 

(hydro) forcbay and tail-water levels (hydro). 

Power Plants 

Most magnitude inputs such as bus volts, MW, and MY AR 

originate in analog form. US. electric utilities have a de 

faCIO standard of 0 f l-mA input to the RTU representing the 

full 

scale span. The sign indicates the direction of flow since 

electric flow, in many instances, is bidirectional. Process 

Control applications, including water and gas utilities, are 

more likely to standardize on 4-2&mA input ranges. Status 

inputs are usually represented by a simple binary on-off 

state. In cases where mechanical devices change state 

slowly, for example, a motor-operated disconnect switch, 

three states are necessary: open-in transit-closed. This is 

accomplished with two limit switches which have four 

possible states: 

I) A open, B closed-switch open 

2) A open, B open-switch in transit 

3) A closed, B open-switch closed 

4) A closed, 6 closed-invalid combination. 

Certain devices, such as circuit breakers with automatic 

reclosing activated, may operate and return to the original 

state in less time than one RTU poll or scan period. 

Operationally, it is important that such action be detected 

and reported to the master station. This is accomplished by 

change detection logic in the RTU which senses high-speed 

changes in status occurring between scans and conveys this 

fact by setting a change bit. Some SCADAs actually count 

and report the number of changes; detection of up to three 

changes is standard. 

Energy quantities, such as MWh, are derived from watt hour 

meters in the form of pulses-each pulse representing a 

specified number of MWh. The RTU counts the pulses in a 

register and reports the count to the master at designated 

intervals. In order to minimize overall electric system 

energy balance errors, a kwh register "freeze" command, is 

often broadcast simultaneously to all RTUs. The register 

counts are then requested by the master and saved in the 

master station historical files. Special RTU inputs or 

interfaces are occasionally required. These can take on many 

forms but the more common forms include binary coded 

decimal, pulse duration modulation, and serial ASCII 

character streams via an RS-232 port. Since RTUs must 

operate in the high-voltage electric sub-station/power plant 

environment, special design features must be included to 

prevent damage to the RTU, false data reporting, or 

disoperation. These features may include photo -optical 

isolation, varistors, and switched-capacitor inputs. The 

various schemes are tested against the IEEE Surge 

Withstand Capability (SWC) Standard 472-1974 for 

compliance. 

4 

Control Outputs 

SCADA systems intended for electric system operations are 

most frequently called on to provide control outputs to 

substations and power plants as follows: 

• Substations 

• circuit breaker operation 

• motorized switch control 

• tap changer transformer control 

• protective relay or scheme mode control 

• RTU internal register freeze control. 

Power Plants:-turbine-generator remote start-stop (hydro, 

gas turbine limit set (hydro) turbine-generator MW 

raise/lower turbine-generator MW set-point generator 

voltage NAR control. Discrete control outputs generally 

occur from interposing relays which momentarily close for a 

specific control action such as Circuit Breaker "trip:" The 

relay contact rating must be carefully sized to carry and

.- 


interrupt the load which, most often, is another relay in a de 

control circuit. If ac control circuits are used the RTU 

interpose relay may be replaced with a TRIAC~ Generator 

MW is. r~motel.y set or adjusted in one of two ways: I ) by 

transmitting raise or lower pulses of variable duration and 

frequency of ?ccurrence to the turbine governor motor; 

these pulses adjust the governor s pee d setting and thus the 

generator output MW or 2) by transmission of a desired 

MW set point which results in an analog output from the 

RTU proportional to the desired MW. An external control 

loop, usually in the governor, then automatically adjusts the 

speed setting until the desired MW is achieved. 

Database 

Older SCADA systems tended to have fixed-format 

?atabase~ where user programs required very explicit 

information about the database and its structure. This 

philosop.hy v:as easier for the database designer but 

substantially increased the complexity of maintaining the 

system as points were changed and new application 

programs added. 

With the advent of lower cost memories it has become 

easier and more attractive to incorporate various database 

management features into SCADA systems. These newer 

SCADA databases permit considerable independence 

betw~en the data acquisition function which updates the 

teal-time part of the database and the user programs which 

retrieve data from the database and save computed results 

back i~to t~e database. The newer databases are not rigidly 

fixed in size but can easily be expanded providing the 

physical memory is available. Design tradeoffs always exist 

between the degree of generalization in the database and 

speed of operation. Highly generalized database concepts as 

used in business applications, frequently have excessive 

compute overhead which makes them unsuitable for time 

critical real-rime use. Information contained in SCADA 

databa~es may be categorized into several distinct types: 

Real-Time: Measurement and status information which is 

periodically acquired via RTUs or entered by operators. On 

each update the old values are overwritten. The periodicity 

of update may vary from a few seconds to hours. 

Parametric: Parameter information is semi-fixed data which 

contain various attributes necessary to interpret real- time 

data. I.neluded .are high, low, and rate limits, scaling and 

offset information; areas of responsibility codes, scan rates, 

normal status, and many more. 

Calculated: Pseudo-points which are calculated from other 

points and then treated the same as real-rime data. An 

example of a calculated value would be the summation of 

two real-time values occurring at specified intervals. 

App~ica~ion: Information which is unique to specific 

applications. There may be constants, normal status, limits, 

stored messages, and more. An example would be stored 

message elements for an alarm processing function. 

It is important that system operators be made aware of 

data in ~vhich validity may be suspect. This is frequently 

accomplished by appending a quality code or flag to each 

data point .in the database. These codes can appear as 

symbols adjacent to displayed data or color changes to the 

displayed value which denote the "quality" of the data. 

Normal data are the default state where no quality code is 

usua Ilydisplayed.A point which is out of scan and not beina 

updated, for example, would carry a code indicating that 

condition. 

Man-Machine Interface: 

A Human-Machine Interface or HMI is the apparatus which 

presents process data to a human operator, and through 

which the human operator controls the process. 

The HMI industry was essentially born out of a need for a 

standardized way to monitor and to control multiple remote 

controllers, PLCs and other control devices. While a PLC 

does provide automated, pre-programmed control over a 

process, they are usually distributed across a plant, making it 

difficult to gather data from them manually. Historically 

PLCs had no standardized way to present information to an 

operator. The SCADA system gathers information from the 

PLCs and other controllers via some form of network, and 

combines and formats the information. An HMI may also be 

linked to a database, to provide trending, diagnostic data, 

and management information such as scheduled 

maintenance procedures, logistic information, detailed 

schematics for a particular sensor or machine, and .expertsystem 

troubleshooting guides. Since about 1998, virtually 

all major PLC manufacturers have offered integrated 

HMIISCADA systems, many of them using open and nonproprietary 

communications protocols. Numerous 

specialized third-party HMIISCADA packages, offering 

built-in compatibility with most major PLCs, have also 

entered the market, allowing mechanical engineers, 

electrical engineers and technicians to configure HMls 

themselves, without the need for a custom-made program 

written by a software developer 

5 

Logs and Reports 

Log printing generally refers to the chronological print-ing 

of events as they occur. These events may be electric system 

alarms, internal SCADA system alarms, or operator-initiated 

actions. The format of log printouts is generally identical to 

alarm and event CRT summaries. Reports are pre-formatted 

documents that are produced at periodic intervals or by 

operator demand. Most often they are produced daily and 

show the results of system operations an hourly basis. The 

information source for reports is usually the stored historv 

file. • 

External Interfaces 

Increasingly the need arises to establish some form of 

information transfer between SCADA systems and other 

external systems. Examples of external interfaces include 

information exchange with: 

I) other systems arranged in a hierarchical order within 

the same utility, 

2) adjacent utility SCADA or EMS systems, 

3) pool control centers, 

4) power brokering arrangements, 

5) separate load management systems, 

6) local PCs or PC networks, 

7) corporate computers, 

8) departmental computers such as system planning. 

The complexity of such interfaces varies widely. An 

elementary, but often practical approach, is to have one 

of the terminals simply emulate a serial printer and 

unidirectionally transfer information in a standard 

report format. At the other extreme is a multi-layer 

--~----------- 

~~~~~~ ---


packet communication protocol based on well 

recognized standards. The CCITT 

X.2S standard, or variations of it, are gaining favor for 

this application. For those situations where the other 

interfacing computer is local, the Ethernet standard is 

useful. 

Message Protocols and Error Detection 

Communications between the SCADA master and 

RTUs for most conventional systems must be bit-serial 

using polling methods previously described. All 

communications, whether master to RTU or RTU to 

master, occur in the form of messages where each 

message is composed of three parts: I) the header, 2) 

information, and 3) the trailer. The header and trailer 

are normally fixed in length but the information is 

usually of variable length with an upper bound before a 

new message is created. 

The outgoing header contains synchronizing bits, the 

RTU address. and some form of function code. The 

function code informs the RTU of the type of 

information which is to follow and is frequently 8 bits 

in length. The trailer ordinarily contains a security code 

for the detection of transmission-induced errors and is 

frequently a Bose-Chaudhuri-Hocquenghern (BCH) 

code or a Cyclic Redundancy Check (CRC). A security 

code design objective is to ensure the probability of 

acceptance of a message received in error is less than I 

in 10 10 for a maximum received bit-error rate of I in 

10 4 • The information part of the message is often byte 

oriented and variable in length. 

V. SCADA IN DISTRIBUTION SYSTEM: CASESTUDY 

[ 10 J 

Case Study Of PECO Energy Co. 

Here case study of a project consisting of implementation of 

SCADA for distribution Automation within a substation is 

considered. This project is renovated for PECO energy co. 

which provides automation for distribution of electric 

power. 

PECO Energy Co. is an electric utility that serves the 

metropolitan Philadelphia area. Like many other utilities 

today. PECO needed a better way, both locally and 

remotely. to monitor, control, diagnose, and maintain 

cquipment in the substation to reduce operating costs and 

provide improved customer service. These demands to 

increase productivity and reduce costs translated into the 

need to collect and act on decision-making information. 

In addition, this scheme would minimize maintenance cost 

through the use of self-checking and relay setting 

veriJication. The new economical, streamlined design allows 

for primary and backup redundancy for all single 

contingency fault conditions, while intuitively replicating 

existing electromechanical protection philosophies. The 

microprocessor relays' new digital communications 

capabilities, incorporated into a substation integration (SI) 

system. allow exceptionally fast and reliable SCADA 

control. status and metering for all interrupting devices, 

lockout relays, and motor operated disconnects (MOD)s. 

REALIZE MANY KEY ADVANTAGES TO PECO 

Distributed Topology 

• Number of relays reduced by 75% 

• Analog wiring reduced by 30% 

• Control wiring reduced by 50% 

• Failures detected within seconds vs. at next 

maintenance interval 

• Breaker isolation and system restoration reduced 

from hours to minutes 

Enhanced System Topology 

• Automatic fault data 

• Remote access to detailed event reports 

• View oscillography and digitals for timing details 

and operation analysis 

• Make system improvement recommendations 

based on data 

• Verify auxiliary equipment (trip coil) 

• Automated system operation supervision for 

breaker closing 

• Reduced maintenance 

• Increased personnel safety 

• "Fast Trip" scheme provides instantaneous tripping 

during hot-line maintenance 

• Flashover detection for open switches 

6 

VI. DISTRIBUTION AUTOMATION: GROWTH AND 

CHALLENGES IN DEVELOPED COUNTRIES 

[ 4][6) 

The idea of distribution automation began in I970s. The 

motivation at that time was to use the evolving computer 

and communications technology to improve operating 

performance of distribution systems. Since then, the growth 

of distribution automation has been dictated by the level of 

sophistication of existing monitoring. control, and 

communication technologies; and performance and cost of 

available equipment. Although distribution systems are a 

significant part of power systems, advances in distribution 

control technology have lagged considerably behind 

advances in generation and transmission control . Small 

pilot projects were implemented by a few utilities to test the 

concept of distribution automation in the I970s. In the 

I980s. there were several major pilot projects. By the 1990s. 

the DA technology had matured and that resulted in several 

large and many small projects at various utilities. 

Automation allows utilities to implement flexible control of 

distribution systems, which can be used to enhance 

efficiency, reliability, and quality of electric service. 

Flexible control also results in more effective utilization and 

life-extension of the existing distribution system 

infrastructure. Many utilities are contemplating providing 

performance-based rates to their customers. They would be 

willing to pay compensation to the customers if the 

performance falls below a minimum level. Such actions will 

allow utilities to brace for the upcoming competition from 

other parties interested in supplying power to the.customers. 

Although higher reliability and quality are the goals of the 

utilities, they would like to accomplish this while optimizing 

the resources. Another goal for a utility should be

" 

r 


improvement in system efficiency by reducing system 

losses. The functions that can be automated in distribution 

systems can be classified into two categories, namely, 

monitoring functions and control functions. Monitoring 

functions are those needed to record meter readings at 

different locations in the system, the system status at 

different locations in the system, and events of abnormal 

conditions. The data monitored at the system level are not 

only useful for day-to-day operations but also for system 

planning. Distribution supervisory control and data 

acquisition (DSCADA) systems perform some of these 

monitoring functions. The control functions are related to 

switching operations, such as switching a capacitor, or 

reconfiguring feeders. The function that is the most popular 

among the utilities is fault location and service restoration or 

outage management. This function directly impacts the 

customers as well as the system reliability. 

Presently, worldwide research and development efforts are 

focused in following areas to make distribution automation 

more intelligent and cost effective in order to accomplish the 

objective of full-scale unbundling of power systems. 

• Power system communication protocol to achieve 

interoperability 

• Communication system to make it commercially 

viable 

o Switchgears and transformers to make them self 

intelligent through IEDs 

o Intelligent Remote Terminal Units (RTUs) 

• Intelligent instrumentation system 

• Power system algorithm to provide quick and 

accurate control decision 

Research and development efforts are being carried out 

worldwide for full integration of AM/FM, AMR, GIS, and 

IT with distribution automation to realize overall 

Distribution Management System (DMS). Looking the 

future needs, few universities in the world have already 

introduced courses on distribution automation and related 

areas. 

DISTRIBUTION AUTOMATION: GROWTH AND 

CHALLENGES IN DEVELOPING COUNTRIES 

India is one of the developing countries. In India, the 

generation and transmission networks have been expanded 

in a planned manner using modern technology and software 

tools. However, the distribution systems have grown in an 

unplanned manner resulting in high system losses in 

addition to poor quality of supply. Efficient operation and 

maintenance of distribution system in India is hampered by 

non-availability of system topological information, current 

health information of the distribution components like 

distribution transformers and feeders, historical data etc. The 

other reasons are the lack of use of efficient tools for 

operational planning and advanced methodology for quick 

detection of fault, isolation of the faulty section and service 

restoration etc. Currently, fault detection, isolation and 

service restoration takes a long time causing the interruption 

of supply for a longer duration. Manual meter reading, delay 

in billing, faulty and inaccurate metering, tampering of 

meters and pilferage of electricity are some of the main 

reasons for poor return of revenue to electricity utilities in 

India. 

VII. DISTRIBUTION AUTOMATION: RESEARCH 

WORK IN FUTURE [9] 

Across the world, vendors have brought out Distribution 

Automation (DA) technology in a fragmented manner. No 

indigenous effort appears to be made in offering complete 

so\.ution of the Distribution Automation system starting from 

development of various components tilI the integration of 

the complete distribution automation systems. The future 

research work should be aimed at developing indigenous 

know-how of full scale Distribution Automation system, 

which can cover from primary substations to consumer level 

intelIigent automation. The future research work for power 

distribution automation is expected into following broad 

areas. 

• Customer level intelligent automation system 

• Computer aided monitoring and control of 

Distribution Transformers 

• 'Substation and feeder level automation 

• Data communication system for Distribution 

Automation 

•• Distribution Control Centre (DCC) software 

• Pilot level demonstration projects 

VIII. CONCLUSION 

The SCADA system has evolved from a pure SCADA 

application to a Distribution Management System for the 22 

kV and 6.6 kV network, supporting the roles of network 

operation and planning by minimizing transmission losses 

and also by improving the power quality by minimizing 

voltage sags. It has helped to bring about a dramatic drop 

in the number of blackouts caused by 22 kV outages 

because of the network ring configurations, and to slash the 

average outage time of a 22 kV power failure to a fraction of 

what it used to be. Its latest development phase will be the 

incorporation of probably the world's first real-rime Expert 

System for its disturbance analysis, network restoration, 

load transfer and switching check functions. 

7 

REFERENCES 

[1] "The Implementation And Evolution of SCADA System For A 

Large Distribution 

Network & substation." IEEE technical paper 

[2) S.S. Rao. " Switchgear & Protection" 

[3) Horst Ebenhoh, "Evolutionary Architectures for SCADA and EMS 

Systems" Technical Papers of the IEEE Conference. 

[4) IEEE Tutorial Course-Fundamentals of Supervisory Control Systems. 

IEEE Power Society, PuM. 81 EHO 1883 PWR 

[5) Mini S. Thomas, Senior Member, IEEE, Parmod Kumar, and Vinny 

K. Chandna:' "Design, Development, and Commissioning of a 

Supervisory Control and Data Acquisition (SCADA) Laboratory for 

Research and Training" 

[6] N.D. Sarma, " Supervisory Control & Data Acquisition Systems" 

IEEE technical paper. 

[7] P. Kumar, V. K. Chandna, and M. S. Thomas, "Intelligent algorithm 

forpre-processing multiple data at RTU," IEEE Trans. Power Syst., 

vol. 18,pp. 1566-1572, Nov. 2003. 

[8] S.-1. Huang and Chih-Chieh, "Application of ATM -BASED network 

for an integrated distribution SCADA-GIS system," IEEE Trans. 

Power Syst., vol. 17, pp. 8Q,,86,Feb. 2002 

[9] W. Chainey and M. R. Block, "Recent Advances in Master Station 

Architecture". IEEE SCADA Applications in Power, Vol. 7, No.'2, 

2004, pp. 25-27. 

[10] David Dolezilek, "Case Study Of A Large Transmission And 

Distribution Substation Automation Project"


BIOGRAPHIES 

.- 

P.V.chopade (M'2003) born in Maharashtra on 18"Decb 1980,completed 

his Bachelors Degree in Electrical Engg from Govt.college of Engineering 

Amravati in July 1998 and Masters Degree in Electrical Engg from 

Govt.college of Engineering Pune, Pune University with firs! Rank in 

University in December 1999. He is presently working as lecturer in 

Electrical Engineering in Bharati Vidyapeeth University College of 

Engineering Pune. He had 4 years of teaching experience. His major field 

of interest is SCADA and Computer Applications in Power system and 

Power Electronics. As a IEEE member he worked as organizing committee 

member for ACE·2003 IEEE Conference held at Pune, he is IEEE student 

branch mentor of BVUCOE Pune and he is also Life Member ISTE. He 

presented research papers at various national and international conferences 

in India and abroad in Australia. 

D.G.Bharadwaj (M'1978) born in Maharashtra on 3"'Feb 1941,compleled 

his Bachelors Degree in Electrical Engg from V.R.C.E.,Nagpur University 

in 1964, Masters Degree and Ph.D in Electrical Engg from University of 

Roorkee (India) now 1.1.T. Roorkee .He retired as Principal Govt.college of 

Engineering Auraganbad. He also worked as Principal at Atharva college of 

Engg. Mumbai. He is presently working as Professor of Electrical 

Engineering and Director of Research and Development Cell in Bharati 

Vidyapeeth University College of Engineering Pune. He has 40 years of 

teaching experience. His major field of interest is Computer Applications in 

Power system and Advanced Electrical Machines. He published more than 

75 research papers at different national and international conferences and 

journals 

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