A Report on Distribution Automation

CERTIFICATE This is to certify that Mr. HONEY TIWARI has undergone six weeks summer training under

ACKNOWLEDGEMENT We sincerely attorn the guidance and supporting steer provided by our training mentors to make this whole Byzantine GSAS/DMS project look simpler, which allowed us to accomplish our training fruitfully. Our special thanks to

Index 1. Introduction 2. System Architecture 3. Station Equipments 4. Control & Relay Panels 5. SCADA/EMS/DMS 6. Geographical Information Systems 7. Spectrum Data Requirements 8. MicroSCADA Training 9. Time ripe for automation…. a. …but there are hurdles b. The future

1. INTRODUCTION North Delhi Power Limited is Major power Distribution Company with its distribution territory spread across 550sq. kms. To meet the ever increasing power demands, NDPL imports 15% power from Local Generation Utilities and Balance from the Northern Grid. NDPL is on a drive to procure an Energy Management System (EMS/DMS) for its Master Control Center (MCC) facility. This system will support NDPL operations. The EMS/DMS system will collect field data from Data Concentrator Units, Remote Terminal Units, IED’s, F-RTU’s etc. and will provide a user interactive operator Interface. The grid station Automation [GSAS] is to be carried out to ensure integration of the grid stations with the proposed Central SCADA System. NDPL’s Grid Station Automation System has following attributes: The system is based on the open communication protocols The completion of the grid station automation will enable the control of the station from a remote location on a peer to peer basis over a NDPL’s own IP Network (NDPL NET). However, this System will remain as a data acquisition facility after commissioning of MCC & BCC Masters is complete. The system will provide functionality for integration with the proposed CENTRAL SCADA. System will integrate the existing automation implemented at the 11kV level. System will be scalable to accommodate future expansions

2. SYSTEM ARCHITECTURE:

!"

"

#

$

$

!

%& %

! ' ()* +" , -)

As per the architecture shown above, the entire system is further divided into 3 sub-systems: I. BAY CONTROLLER / IED II. DATA CONCENTRATOR III. MASTER SCADA HMI

I. BAY CONTROLLER / IED: D25

2

D25 Multifunction IED: For all the 16 NDPL Grid stations in HAIL scope, there will a Bay Controller and IED’s supplied for each 66/33KV bay. In this project, D25 Multifunction IED will be acting as a Bay Controller. All the field I/O’s will be physically connected to the D25 Bay Controller which in turn will send the data to D20 Data Concentrator on IEC 60870-5-104 TCP/IP Ethernet LAN protocol. Connectivity – Copper, 10Mbps, RJ-45 Ethernet LAN Protocol – IEC 60870-5-104 TCP/IP

(.#

/0 1 2 3

DATA CONCENTRATOR: D20

4

Purpose of a Data Concentrator is to collect data from Reyrolle Numerical Protection Relays, Bay Controllers, Transformer Monitoring Unit, FRTU’s, 11KV Protection Relays and send it to the Master Control Station. The function Performed by D20 Data Concentrator for NDPL project can be divided in 2 Groups: I. D20 as Master for Field IED: Bay Controllers, Reyrolle Protection Relays, TMU’s, F-RTU’s, all these field devices are connected to the D20 Data Concentrator via Ethernet LAN or Serial Connectivity. The D20 Data Concentrator will send periodic communication polls to the field devices via the communication medium specified in the architecture. Upon receiving the appropriate demand request polls, the field devices will transmit data. I.

Fgg

4

II.

D20 as Data Concentrator:

D20 Data Concentrator will collect all the Field data from the Local devices, store this data in its database and then transmit this data to the different master levels. The protocol required for communication with PLA Master is DNP 3.0 TCP/IP and MCC/BCC Master is IEC-60870-5104 TCP/IP. The D20 Data Concentrator has these protocol drivers inbuilt in its firmware flash which will process the data collected from field IED’s, translate it to the PLA/MCC/BCC Master understandable protocol format (i.e. DNP 3.0 TCP/IP and IEC 60870-5-104 TCP/IP) and then transmit the data to the Master Stations.

D20 Design & Technology: The WESDAC D20 remote terminal unit is based on an open-ended distributed processing Configuration consisting of a main processor, peripheral I/O modules, termination panels, power suppliesand communications equipment. Communication between the main processor and I/O peripherals takes place over a high-speed serial port. Field data acquired by the D20 is stored as raw data in a system database so that any application program can access and use the same data. Once field data is processed, it is stored separately from the raw data it was derived from. Main Processor: The WESDAC D20M is the main CPU module. The D20M and its associated power supply unit form the core of the D20 Substation System. The primary function of the D20M is as a data concentrator and central processor. As a data concentrator, it obtains data from peripheral I/O units and/or serial ports, processes the data, and conveys the data to the host computer.

Peripheral I/O Modules: Intelligent D20 peripheral I/O modules provide specialized interfaces for inputs and outputs to the D20M.These modules are:

#

D20S for up to 64 digital inputs D20A for up to 32 analog inputs D20K for up to 32 single or trip/close control outputs D20C, a combination board, for low point (16) count digital inputs, 8 trip/close control outputs, and16 analog inputs or 8 analog inputs and 8 analog outputs.

Pulse accumulators, sequence of events recording [SOE], connection to interposing relays and other field I/O interfacing is accomplished through these peripheral I/O modules. Communications : Communications between the host computer, D20M and the D20 peripheral I/O modules take place over physical communication links and through the use of protocols.

MASTER SCADA HMI:

5

Master SCADA will serve as a Man-Machine-Interface system. In NDPL project there are 2 levels of Master Control, GE Power Link Advantage and 3rd Party DMS SCADA Package. The DMS Master will collect data from D20 Data Concentrators on IEC-60870-5-104 TCP/IP. GE Power Link Advantage: HAIL/GE SCADA automation equipments in NDPL project is spread across 16 Grid Stations. To enable the operator to monitor the entire data of all the Grid Stations, HAIL has provided 3 Power Link Advantage systems that will be viewed on 3 different HMI’s .

Network addressing considerations for your Power Link Advantage System: - Network protocol addressing - Addressing conventions for DNP

- Physical addressing

# $"% %

$ - " $ ! $" "

$ ! * "

$ ) ,

$ & $ +$ " % "

& "

% & " $ +" " & $ +$ "

$"

" "

"

,-"

" "

) " $

3. STATION EQUIPMENTS: 5 2 #"

" 6

" &

" & #7- $ !

&

$ &" &" +

(

&" && !

$"

7

"

8

& " % ! "+ $" " . $ $" " " & + "% 4 7 9 & $ $"

"

&" $"% % + "% 41 & $ + $ " +"

#"

#" 6 & #" $

3/ $ 3 ,6

54 .

. #" $

! "

$

4 7 9 $"

+"

: $

$"

"

! " 8

8

, -) ; " ' () $"& * $ & " +" $"% % $ " ! " * 41 #" " * 9< -) % $ ! %" 4

! 4 " #" $

$ ! D25 Bay Controller

"

9

%

" ! ) , #"

!

D20 Data Concentrator

. ' .7, .

Transformer Monitoring Units

= ( #'

NDPL Communication Network

"

55 , % .

$ 7

% +" " ?

- " $ " 7 " +"

% $

8

, % >55

$ !

7 &

! "+

& " $ " & !

8 2

@ ,"

$ "

56 ># A 2.>B - " $ " 7

?

8 96

( 2

4 / # 243

@, % @ ,"

@ @9 @,

$

++ $ "

8 $ " 56 ># A 2.>B - " $ " 7 " C 6 " 7 # 9 ! $ 7

? 2

@ ,"

- " $ " 7 56 ># A 2.>B - " $ " 7

8 56 ># A 2.>B - " $ " 7

$ "

?

8 2

@ ,"

$ "

56 ># A 2.>B - " $ " 7

All the numerical relays will be multi-dropped via fiber cables and will be connected to a Sigma Convertor [SIGMA3]. The Sigma convertor [Light signal to RS-232 Digital signal] will be further connected to the D20 Data Concentrator. The communication protocol between Argus Relays and D20 is IEC 870-5-103 protocol

5 3 (. <

22

C B 7 9< 8

There are F-RTU’s and 11KV (IED’s) installed by NDPL in each Grid Station. All these devices will be integrated with the D20 Data Concentrator Unit at that Grid Station. The D20 Data Concentrator is equipped with the appropriate protocol driver for communicating with these field devices. The communication with 11KV ABB protection relays will be on SPA protocol whereas communication with 11KV Sepam protection relays will be on Modbus protocol. The F-RTU’s will communicate with D20 Data Concentrator Unit on IEC60870-5-101 protocol. 51

+" %

"

"

9

8

Transformer Monitoring Unit is supplied for each Transformer feeder. Transformer PT, Tap Position (4-20ma dc) & Oil Temp (4-20ma dc) will be physically wired to the TMU. The TMU will transmit the Transformer data to the D25 Bay Controller. All the TMU’s will be connected to the Ethernet LAN switch available in the D20 Data Concentrator cabinet via a RJ-45 – UTP – Ethernet LAN cable. The communication protocol between TMU and D20 Bay Controller is IEC-60870-5-104 TCP/IP. & +" %

!

+" %

"

"

9

+" "

8

It will monitor the transformer digital indications such as Tap Chage in Progress, Tap Change Stuck-up, Fan On, Bucholz Trip, OSR Trip, WTI Trip,OTI Trip, SPR Trip, PRV Trip, Bucholz Alarm, WTI Alarm, OTIAlarm, MOGAlarm, Tap Local/Remote & Fan local/Remote Status Monitor Transformer Tap Position, Oil Temp, Winding Temp and 1/3 Phase P.T voltage Initiate Automatic Voltage Control depending upon voltage variations Initiate Fan Control depending upon WTI/OTI temperature variations

4. CONTROL &RELAY PANELS:

,"

7.) D #6 .

D-.

2

42

4

40

5

12

(

%

6

3

12,

(

%

;"

1

1E /0(

$ - " $ " 7 $9

$6

"

7

"

(

$

7 6

++

- " $ "

0

0

$

$ "

6

/

0,

$

$ "

.>B 7

/

)"$ "

2

/0

++

22

35

24

4

25

1 ,

(

23

1 )

)"$

7

7 "

E

$

$

7

7 7

" $"

7

%

7 "

6 $

$

7

&- " $ "

DC SELECTOR SWITCH: There shall be three position DC selector switch i.e neutral, DC1 &DC2. In normal supply condition the left side panel & bus section is fed by DC1 Source .and right side panel is fed from DC2 Source. In case of failure of DC2 source, all panels will be fed by DC1 source. Similarly In case of failure of DC1 source, all panels will be fed by DC2 source.

The following indicating lamps with color shall be mounted over CONTROL & RELAY PANELS to indicate important status/alarm of breaker: Breaker close

Red

Breaker open

Green

DC Healthy

Yellow

Spring Charge

White

SF6 pressure not o.k.

Amber

Operational Philosophy: The Operation of the individual field devices shall be possible from both locally from the Bay Level & remotely from the SCADA. There shall be provision for remote/local switch at the Bay Level IED (Either soft or hard switch) for selecting local or remote operation. The local position of the switch shall be displayed in remote/local workstation and the remote operation shall be blocked if the switch is in local position. The control & protection functions shall be functionally separated and all the control, protection & metering function shall be numerical in nature. Each Breaker panel shall be with Circuit Breaker TNC switches which shall have three positions and shall be spring return to “NEUTRAL” and “TRIP” positions and shall have pistol grip handle. Philosophy is explained in tabular form below: BKR Control From BKR PANEL TNC Switch BCU Local

BKR L/R Local Remote Remote

CRP L/R

BCU L/R

Local Local

Local

SCADA

Remote

Remote

Remote

5. SCADA/EMS/DMS: Definition SCADA: system that will be the essential tool for the Load Dispatch Center (LDC) Energy Management System (EMS): suite of applications that are directed for better modeling and use of the high voltage assets including substations and sub-transmission lines and cables. Please not that SCADA/EMS/DMS are shown sharing a unique database since they normally are purchased as a package to enhance integration and for better user interface. Distribution Management System (DMS): set of functions that take advantage of a distribution system model that provides for representing the distribution network of NDPL in the SCADA or GIS platform, depending where this functionality is implemented. The DMS applications cover from the output breaker at the substations up to the transformer levels or up to the customer level in case secondary voltage networks are also represented. Substation Automation System, (SAS): this system would be the best approach to achieve two goals that are needed at NDPL: • Have a technological up-to-date protection system and • Get in a more cost-effective way the SCADA inputs required by the SCADA/EMS/DMS functions. Distribution Automation (DA): set of functions supported by appropriate devices that allow remotely monitoring and controlling the distribution network including feeders and distribution stations. Given the number of equipment that belongs to this part of the power network, selected portions are automated, mainly those providing for greater benefits to NDPL. Automatic Meter Reading (AMR): set of functions that provide for the automation of the meter reading process at selected utility customers Different technologies and communication media are available for this implementation. Only a group of selected customers is normally candidate for this application.

Trouble Call System (TCS): this system is shown separately as part of the corporate systems but it can be implemented as stand alone or integrated with other applications such as DMS. A Call Center, other required infrastructure piece, is needed to feed the data to the TCS and provide feedback information to the affected users.

Load Dispatch Center Systems Functions:

The main support for NDPL´s power system operation will be the SCADA functions. The SCADA functionality will be the cornerstone for most of the automation functions that are recommended for implementation at NDPL. Following advantages are expected to be derived from this implementation among others:

!

# !

(

+

)

* &

+

&

*

+

*

) ,, +

-

# "% & % & " %" " "+ &" " 55 !" "+ $ &" " "+ 22 ! " " - & %

+

% +" "

" $" +" "& % .

B &

)

/

%

0 &

%& % $ "

&&"

&'

!

(% & "

$

! %

+"

"

+

"+

$ "

"

:&

"

"+ :

F &%

(% & " ! "& " & $ $

& "$ &" " "+ +

" #

%

%$"&

' &

"!

)" &"

$ " + $ " $"

+

"

" &"

% +" %

!

!

"

"

$"

"

"

+

+

7 B & "&

$ $

&> " " "+ " & " " &" % $ G " H

&&" "+ " " ! "+ &" &&"

% "

+" %

&& "

" &&

" "+

$"

) ) !)

0 *

+

0 0

23 ! # 3 !

1

$ F &%

+ $ " " "& "+ # & " $" ! ! + % "+ "% $ $ " "+ % " $" " +" " * % % " " "+ % * $ $ " +" % % ! " % F # %

- " %& %& $ +"

+" ! ! % % " $" % " % " *" % "

+ :& $

&& $

$ %

+ " % $ % &&" "& " "+ "&" "

"+ && $ " & " ! + % "+ ! &" % "& "

!

Energy Management System (EMS):

Advantages of the EMS Implementation. !

" # $% &'

.

( ) * * + & 1

.

%

$"

+

% " &" !

% "

*

(

+

/ / )

&"

$" //

" %

" & " "+ +" % " " "+ % " % & "+ % " "% "+ I "& " " +" "+ %" "+

% "& "

&&"

& " +" " & "! % " & ! +" "$$ " +" 7 , #6 $"% & % " ++ $ &&" &" $" +"

(% & " " %

& $

"+ " " +" $$"% % " $ % $ "

"+

+"

%

!

%

"$$

"&

"+ F &% " $" " %

#

" +" %" %" * " +" : " , -) % "& " "

+

$

"" &"

%"

! :&

$" &"

& " "& " +" "

" " $

(% & " ! " % $ $ " % " :& " &" $" " $ & $

" "

!

Distribution Management System (DMS): Under the DMS name a number of functions are included which can help with various functions to better operate and use the distribution network. For this analysis DMS includes functions that: Help to detect, report and correct outages which includes the Trouble Call System, the Outage Management System and the Fault Location and Service Restoration System, Optimize the network conditions including the Network Reconfiguration and the Volt-Var Control functions, Support the analysis and study of different scenarios, including the dispatcher power flow. These three categories are discussed next. Distribution Automation (DA): Advantages of the DA Implementation ! Real-time monitoring and control of selected equipment located at distribution substations or pole mounted. Remote monitoring of selected analog values such as feeder voltages and capacitor bank status.

The automation of the distribution network provides for locating the faults, isolating them in a short time period and reconfigures the distribution network promptly. Better control of power quality and enhanced use of reactive power sources.

" #

%$&' The improving of reliability indices such as SAIDI and SAIFI are very much impacted by the automatic means that can be provided by DA. Improves quality of service while reducing "

Advantages of DMS Implementation. Feature

Benefit/Advantages

Detection, report and correction of outages via TCS, OMS, and other related functions

The full use of information starting from the user reported problems and taking advantage of the georeferenced information and the network topology and customer-network connectivity provides a powerful means to reduce to a minimum the outage times.

Support of NDPL Objectives Increases reliability while improving the corporate image to the customer by the better service provided.

It provides useful feedback information to the customer in terms of expected outage duration times for instance.

Network Optimization Functions

Network Analysis Functions

;

Provides better use of crews and reduces travel times. Provide for maximum use of the installed equipment in terms of best configuration and/or best settings of controls to reach specific objectives such as minimum losses. Provide the means to analyze the present and hypothetical operating conditions of the distribution network to respond what if type of questions.

Losses reduction support via reconfiguration and better use of control and reactive sources while maintaining variables related to quality of service within boundaries. Help in the analysis of potential solutions to failures or to network conditions that can prevent equipment overload thus increasing network reliability.

6. Geographical information system:

Geographical Information system is going to be implemented in NDPL to facilitate efficient and optimized decision making in entire gamut of NDPL activities. In addition to usual function of network planning and engineering, construction management, asset management, managing planned and unplanned maintenance, it is going to feed network information to SCADA and DMS system. GIS implementation in NDPL shall broadly comprise of two major activitiesA) Land Base and Electrical network mapping B) Software implementation and related application development NDPL is planning to get the map developed in 1:1000 scale using precision equipment like total station with a combination of using satellite imagery for quality check. The GIS software at NDPL is from GE, which will be the source master for the data at the DMS level. This comprises of all equipment, installed in the 11kV and below network, right until the point of the consumer. The GIS application stores geographical, graphical and equipment specific data of this network. In addition, data on the geographical location of the equipment in terms of the landbase system in that area – i.e. buildings, contours, altitudes, roads, landmarks etc is stored. All of this data can be imported in the SCADA system for viewing and action.

Benefits: The GIS System is envisaged with following benefits: a) b) c) d) e)

Provide a DATABASE and map for better network planning and design. Efficient work management Expeditious Construction and effective control Facilitate commercial function Data source for network information for SCADA and GIS system

JUSTIFICATION:The following benefits are achieved on the establishment of Automation in NDPL Electrical distribution system. 1. Improve reliability figures through expedite assessment of situation & better operation practices. 2. Better use of existing & installed equipment. 3. diminishes operator potential mistake 4. Helps to better use of the information gathered 5. Reduce the time for supply restoration thus reducing outages time and no supply of energy. 6. Increase the reliability by implementing remote control mechanism. 7. Condition monitoring from remote location reduce the risk of potential failures of the equipment i.e. operation life, no of operation etc. 8. Availability of additional information for planning, Engineering & protection setting 9. Improve quality of services while reducing losses.

7. SIEMENS SINAUT-Spectrum_Data_Requirements:

DMS Data Specific DMS data for each of the different types of components will be added on during the creation of the database elements. Seen below is a typical power transformer with data as present on the GIS system. On the Sinaut Spectrum system however, data required is dealing wire resistances, impedances, tap changing, oil levels etc. A one by one map of the elements will be done, once the DMS area of supervision is clear. Since the data on the GIS system and what is required on the Sinaut Spectrum system is very different, it is proposed that suitable DMS –specific data be entered directly into the system. Only the graphical connectivity and geographical location of the equipment will be picked from the GIS Data Entry The data entry for these points will be through the creation of IDDUG (Import Data Definition User Guide) files.

Data Objects: 1. Load 2. Line Cable 3. Transformer 4. Capacitor 1 Load Format Load: NAME/ Location No of Customers connected to the

GIS

x-mer Phases Peak Load Magnitude in kW Maximum Percentage Load Maximum Percentage Load Phase A Maximum Percentage Load Phase B Maximum Percentage Load Phase C Default Power Factor

Load Curve Type Name Load Behavior Type Name Constant Power Coefficient -P part Constant Power Coefficient -Q part Constant Impedance Coefficient -P part Constant Impedance Coefficient – Q part Constant Current Coefficient -P part Constant Current Coefficient -Q part Scheduled Season Type Scheduled Day Type

3 100%

GIS GIS GIS/ Datasheet 100% Data sheet Data sheet

0.95 Res, Com, Ind, mixed

Legend:

Data Sheet Data sheet

Data sheet Data sheet Data sheet Data sheet

Example must be filled Source COM1

Data sheet Data sheet Data sheet Data sheet Data Sheet Data Sheet

WI WE

Line Cable: Following are the parameters acquired for the line cable modeling for SinautSpectrum: NAME

GIS Dog/ XLPE 11

GIS/ DataSheet GIS

3

GIS

Ohm / km

0.623

Data Sheet

Ohm / km

0.36

Data Sheet

3

Cal

TYPE Nominal Voltage

kV

Number of Conductors

Positive Sequence Resistance R Pos. Sequence Reactance X Line Charging in kVAr per phase Zero Sequence. Resistance R Zero Sequence Reactance X Length

Legend:

Ohm / km

0.623

Data Sheet

Ohm / km km

0.36 2.75

Data Sheet GIS

A

77

Data Sheet

Long Term Rating

(CONDUCTORCAPACITY)

Medium Term Rating Short Term Rating

Data Sheet Data Sheet

Example must be filled Source

Transformer: Substation Name Highside voltage Lowside voltage Highside configuration Lowside configuration Resistance between High side Neutral and Ground Reactance between High side Neutral and Ground Resistance between Low side Neutral and Ground Reactance between Low side Neutral and Ground Nameplate rating S Positive Sequence Resistance in % of Rating Positive Sequence Reactance in % of Rating Positive Sequence Conductance in % of Rating Positive Sequence Susceptance in % of Rating

25 kVA

GIS GIS/ Datasheet

kV

11

GIS

kV Y or triangle Y or triangle

0.415

GIS

D

Data Sheet

Y

Data Sheet

Ohm

0

Ohm

0

Ohm

0

Ohm

0

KVA

25

GIS

%

11,8

Cal

138,6

Cal

32,5

Cal

%

0,35

Low Side Neutral Voltage High Side Normal Tap Position High Side Limit to Number of Steps Up from Neutral High Side Limit to Number of Steps Down from Neutral

kV

11 1 …. 17 1 …. 17 1 …. 17

High Side Step Size High Side Neutral Tap Position x

%

1.25 1… 17

Minimum Regulating Voltage Maximum Regulating Voltage Voltage Bandwidth Zero Sequence. Resistance R in % of Rating

kV

Cal Not for Distribution Transformer Not for Distribution Transformer Not for Distribution Transformer Not for Distribution Transformer Not for Distribution Transformer Not for Distribution Transformer Not for Distribution Transformer Not for Distribution Transformer Cal

Zero Sequence Reactance X in % of Rating

kV kV Ohm

0.623

Data Sheet

Ohm

0.36

Data Sheet

Legend: Example must be filled Source

Capacitor: Name/ Location

GIS

7.4 kVAr LT

Nominal Voltage kV 0.4

GIS/Datasheet

Datasheet

Type

Phases

Ratings

No 3 Data Sheet

kVAr 100 Data Sheet

kW Loss % Data Sheet

Load Format:

Grid Name PP-1

PP-1

NAME/ Location Feeder DT/HT Name Name

Phases

Peak Load(KW)

Default Power factor

Load Curve Type Name

Scheduled Day type

Season Type

Meter No.

Kapil Vihar

Jhulal appt S/stn

03099350

3

103.63

0.89

Res

Weekend

Summer

Kapil Vihar

Jhulal appt S/stn

03099351

3

129.87

0.87

Res

Weekend

Summer

Data Acquisition FLOWCHART: Following algorithm was used for rendering Load Format Sheet as required by Sinaut-Spectrum® primary Database: L&T remote metering module - VINCOM Selection of Meter no. Selection of duration e.g. from 15/01/2006 to 16/06/2006

Data is then converted as per required format

Select Energy Format

Export to excel

8. ABB - MicroSCADA Training Programme 4 )5

) 6 / 7 88

MicroSCADA is a microcomputer-based, programmable and distributed supervisory control and data acquisition (SCADA) system. Microcomputer-based: MicroSCADA programs run on commercially available PCcomputers. Programmable: All MicroSCADA application programs as well as most system configuration programs are built in SCIL - Supervisory Control Implementation Language. Distributed system: The system can be regarded as a network where the control system can communicate with the widely distributed process through a communication system.

Application systems: The main MicroSCADA-based application systems are: 1. Substation Automation System for Power transmission distribution substation 2. Network Control and DMS for Power distribution Substation Automation system: Substation Automation means that the substation has equipment, which enables communication with the primary equipment and use of process data for supervision, control and communication. The function may include: viewing status of breakers and disconnectors controlling the breakers and disconnectors

dynamic coloring of the bus bars viewing and setting of protection parameters viewing condition of auxiliary equipment e.g. batteries collection of metering data Transferring data to network control center (S). Network Control System: Network control that a geographically widely distributed process is supervised and controlled from a central control office. Network control of power distribution means remote control of: • power networks • substations and secondary substation The basic functionality is supervisory control and data acquisition (SCADA) including at least: • process status overviews and process control • Data collection and handling historical reports. In addition, a network control application may include user authorization, viewing and setting of protection parameters, bus bar coloring function etc.

Supervision: MicroSCADA lets the operator supervise the process interactively with schematic pictures which illustrate the real process and direct the operator to make correct decision. Control: The operator performs control operations-open, close, lower, higher, etc by activating function keys, dialogs and windows. Data acquisition: Process information is stored on a process database and a report database. The real-time process database stores incoming and outgoing process data signals. Process communication from and to the base system passes through the process database. The report database stores historical data and mathematically or statistically handled values. It also executes SCIL programs based on time or events.

Distribution management System: Distribution management provides the tools to handle the distribution network and quickly locate and eliminate disturbances and faults. The basic distribution management functions are: • network coloring • fault location • Operation simulation. The network coloring function presents the distribution process as a topological map of the network. Additional distribution management functions are e.g. load flow calculation, loss minimization and security analysis. Operational features: MicroSCADA provides: • a picture-oriented operator technique • on-screen function keys, dialogs and windows • a reporting system that supports advanced calculation • access to all process and system data, which is limited by user rights • simultaneous supervision of several processes on one screen or several screen • on-line programmability (i.e. user systems can be extended and adjusted during normal operation) • Possibilities to simulate processes and control operation.

9. Time ripe for automation.... Distribution Automation is anytime a pragmatic solution for a prime distribution firm like NDPL to gratify its esteemed customers to fetch the sense of reliability from that side. Existing distribution systems have certain inherent inefficiencies due to their legacy. For one, most systems are monitored manually. This results in maintenance taking place only during breakdowns. The present system also does not ensure reliable and complete power system and usage information that can facilitate trend forecasting or help the utility in better analysis and planning. At places, the billing systems are still unreliable. While the present system has intensive manpower requirement and over-dependence on experts, it is still a logistic nightmare to reach remote locations. Even trouble-shooting in case of breakdowns is based on the conventional call system through telephone answering machines. ...but there are hurdles Although many utilities are talking to distribution automation vendors, this has not taken off the way it should have. There are two reasons. First, the cost factor. The cost of a complete distribution automation system for a major city is Rs 30-50 crore. Another limiting factor could be the quality of existing communications network. Distribution automation systems require reliable communication media from control centre to field equipment -- through telephone cable, microwave, optic fibre, etc. In the absence of efficient telecommunications infrastructure, the creation of a complete communication system may add up to around 30 per cent of the total project cost. This may be higher in case of an optic fibre network. The implementation of OFC broadband network by ASPs in different cities can help the utilities to use it for automating distribution.

The future There is an imperative need for solutions to optimize efficiencies within the existing system. Globally, distribution automation by utilities has shown that it pays for itself in a very short span of time. Already, there is a growing realization in India that SCADA systems will have a significant impact on distribution control applications and the way enterprises manage, or will manage, their business to stay competitive. Quite of few of the SEBs and most of the newly formed distribution companies are increasingly looking at SCADA to provide solutions ensuring efficient distribution of power across their respective territories, despite financial and communications infrastructure constraints.

" J

*

"%

K