a report on distribution automation

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

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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 � � � � � � � � � � � � � � � � � � � � � � � � � � �

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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

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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

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2. SYSTEM ARCHITECTURE:��

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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

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I. BAY CONTROLLER / IED: D25

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 �

DATA CONCENTRATOR: D20

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.

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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.

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-60870-5-104 TCP/IP. The D20 Data Concentrator has these protocol drivers in-built 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.

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

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.

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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.�

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. Network addressing considerations for your Power Link Advantage System:

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- Physical addressing�

- Network protocol addressing�

- Addressing conventions for DNP�

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MASTER SCADA HMI:

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.

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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�

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3. STATION EQUIPMENTS: �

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D25 Bay Controller�

D20 Data Concentrator�

Transformer Monitoring Units

NDPL Communication Network�

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�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��

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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 IEC-60870-5-101 protocol. ��

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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.

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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�

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4. CONTROL &RELAY PANELS:

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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. �

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

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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 L/R CRP L/R BCU L/R BKR PANEL Local TNC Switch Remote Local BCU Local Remote Local Local SCADA Remote Remote Remote �

Breaker close Red Breaker open Green DC Healthy Yellow Spring Charge White SF6 pressure not o.k. Amber

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5. SCADA/EMS/DMS: Definition �

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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.

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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.

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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:

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Energy Management System (EMS):

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Advantages of the EMS Implementation.

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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.

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Distribution Automation (DA):

Advantages of the DA Implementation

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Real-time monitoring and control of selected equipment located at distribution substations or pole mounted. �

The automation of the distribution network provides for locating the faults, isolating them in a short time period and reconfigures the distribution network promptly.

The improving of reliability indices such as SAIDI and SAIFI are very much impacted by the automatic means that can be provided by DA.

Remote monitoring of selected analog values such as feeder voltages and capacitor bank status.

Better control of power quality and enhanced use of reactive power sources.

Improves quality of service while reducing��"��

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Feature Benefit/Advantages Support of NDPL Objectives

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 geo-referenced information and the network topology and customer-network connectivity provides a powerful means to reduce to a minimum the outage times. It provides useful feedback information to the customer in terms of expected outage duration times for instance. Provides better use of crews and reduces travel times.

Increases reliability while improving the corporate image to the customer by the better service provided.

Network Optimization Functions

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.

Losses reduction support via reconfiguration and better use of control and reactive sources while maintaining variables related to quality of service within boundaries.

Network Analysis Functions

Provide the means to analyze the present and hypothetical operating conditions of the distribution network to respond what if type of questions.

Help in the analysis of potential solutions to failures or to network conditions that can prevent equipment overload thus increasing network reliability.

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Advantages of DMS Implementation.

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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 activities-

A) 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.

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Benefits: The GIS System is envisaged with following benefits: a) Provide a DATABASE and map for better network planning and design. b) Efficient work management c) Expeditious Construction and effective control d) Facilitate commercial function e) 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. ��

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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.

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Data Objects:

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Load:

NAME/ Location GIS

No of Customers connected to the

x-mer GIS Phases 3 GIS Peak Load Magnitude in kW

GIS/ Datasheet

Maximum Percentage Load 100% 100% Maximum Percentage Load Phase A Data sheet Maximum Percentage Load Phase B Data sheet Maximum Percentage Load Phase C Data Sheet Default Power Factor 0.95 Data sheet

Load Curve Type Name

Res, Com, Ind,

mixed Data sheet Load Behavior Type Name Data sheet COM1 Constant Power Coefficient -P part Data sheet Constant Power Coefficient -Q part Data sheet Constant Impedance Coefficient -P part Data sheet Constant Impedance Coefficient –Q part Data sheet Constant Current Coefficient -P part Data sheet Constant Current Coefficient -Q part Data sheet Scheduled Season Type Data Sheet WI Scheduled Day Type Data Sheet WE

1. Load 2. Line Cable 3. Transformer 4. Capacitor 1� Load Format�

Legend:

Example must be filled

Source

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Line Cable:

Following are the parameters acquired for the line cable modeling for Sinaut-Spectrum:

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NAME GIS

TYPE

Dog/XLPE

GIS/ DataSheet

Nominal Voltage kV 11 GIS

Number of Conductors 3 GIS

Positive Sequence Resistance R Ohm /

km 0.623 Data Sheet

Pos. Sequence Reactance X Ohm /

km 0.36 Data Sheet

Line Charging in kVAr per phase

3 Cal

Zero Sequence. Resistance R Ohm /

km 0.623 Data Sheet

Zero Sequence Reactance X Ohm /

km 0.36 Data Sheet

Length km 2.75 GIS

Long Term

Rating (CONDUCTORCAPACITY) A 77 Data Sheet

Medium Term

Rating Data Sheet

Short Term

Rating Data Sheet

Legend:


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Transformer:

Substation GIS

Name 25

kVA GIS/

Datasheet

Highside voltage kV 11 GIS

Lowside voltage kV 0.415 GIS

Highside configuration

Y or triangle D Data Sheet

Lowside configuration

Y or triangle Y Data Sheet

Resistance between High side Neutral and Ground Ohm 0

Reactance between High side Neutral and Ground Ohm 0

Resistance between Low side Neutral and Ground Ohm 0

Reactance between Low side Neutral and Ground Ohm 0

Nameplate rating

S KVA 25 GIS Positive Sequence

Resistance in % of Rating % 11,8 Cal Positive Sequence

Reactance in % of Rating 138,6 Cal Positive Sequence

Conductance in % of Rating 32,5 Cal Positive Sequence

Susceptance in % of Rating % 0,35 Cal

Low Side Neutral Voltage kV 11 Not for Distribution

Transformer High Side Normal Tap

Position 1 …. 17

Not for Distribution Transformer

High Side Limit to Number of Steps Up from Neutral

1 …. 17


High Side Limit to Number of Steps Down from Neutral

1 …. 17


High Side Step Size % 1.25 Not for Distribution

Transformer High Side Neutral Tap

Position x 1 … 17


Minimum Regulating Voltage kV Not for Distribution

Transformer Maximum Regulating

Voltage kV Not for Distribution

Transformer Voltage Bandwidth kV Cal

Zero Sequence. Resistance R in % of Rating Ohm 0.623 Data Sheet

Zero Sequence Reactance X in % of Rating Ohm 0.36 Data Sheet

Legend:


Source �

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Capacitor:�

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Load Format: �

NAME/ Location Phases

Peak Load(KW)

Default Power factor

Load Curve Type Name

Scheduled Day type

Season Type

Grid Name

Feeder Name

DT/HT Name

Meter No.

PP-1 Kapil Vihar

Jhulal appt S/stn 03099350 3 103.63 0.89 Res Weekend Summer

PP-1 Kapil Vihar

Jhulal appt S/stn 03099351 3 129.87 0.87 Res Weekend Summer

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Data Acquisition FLOWCHART: �

Following algorithm was used for rendering Load Format Sheet as required by Sinaut-Spectrum® primary Database:

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Name/ Location Type Nominal

Voltage Phases Ratings kW Loss

kV No kVAr % 7.4 kVAr LT 0.4 3 100

GIS GIS/Datasheet Datasheet Data Sheet

Data Sheet

Data Sheet

L&T remote metering module - VINCOM�

Selection of duration e.g. from 15/01/2006 to 16/06/2006 � Select Energy Format�

Export to excel�

Selection of Meter no.

Data is then converted as per required format

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8. ABB - MicroSCADA Training Programme

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

MicroSCADA is a microcomputer-based, programmable and distributed supervisory control and data acquisition (SCADA) system. Microcomputer-based:

� MicroSCADA programs run on commercially available PC-computers.

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.�

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� 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.�

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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.

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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.

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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.

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a report on distribution automation

Documents