New structure in Deregulated Environment Genco Genco Open access in Transmission Traders Discom Traders Customer Genco Discom Open access in Distribution Customer Discom Customer

These changes require the following: 1) Monitoring system wide information and commands via data communication system 2) To send selected local information to control center, customer, market participants.

3) Monitor critical real time information for taking security related operation .

4) To support Power Trading and spot market.

4) Reliable and fast communications among IED’s ( Intelligent Electronic Devices viz Relays, Meters, Fault recorders, RTU’s etc.) for exchanging information and change in settings as part of wide area protection system .

5) Dissemination of billing and other related calculations from Generation to Distribution for to various agencies including information for DMS & EMS.

7) To perform effective co-ordination through communications , Communication Protocols used are expected to be high speed ,reliable , fault tolerant and intelligent enabled.

8) The Protocols are to be accomplished for both local ( LAN) and wide area communications (WAN). 9) The protocols should be thin, flexible and have provisions for accommodating future requirements.

10) Safe , secured and reliable transmission of information.

11) Protecting information network from Hacking & misuse.

12.

Information about the power system gives the utility the strength to be more successful and competitive in a free market .

13.In this environment information becomes a strategic requirement when fast decisions are required.

Fault Analysis Event Printer HMI Reyevo / SEL5601 / IPSCOM Hard Copy Printer Ethernet LAN ER1000 Station Controller Engineering Tool ISAGRAPH Remote Center Multifunction Meter Argus Delta Duobias-M Ohmega SEL-311C M-3425

What is Protocol ?

When Intelligent Devices communicate with each other, there needs to be a common set of rules and instructions that each device follows.

A specific set of communication rules is called a protocol.

* The diversity of Equipments and Manufacturers lead to a increase of Proprietary Protocols

•

Computer to Computer data communication standards have been developed over past few decades.

•

Well known model for this purpose is the 7 Layer OSI ( Open System Interconnection) reference model.

•

This model provides encapsulation of the relevant data with in a packet.

•

This model provide isolation of application program from system and media. But adds significant overhead in processing power and bandwidth utilisation.

OSI 7 Layer Model 55 4 3 2 1 7 6 Application Presentation Sessions Transport Network Data link Physical

Functionality of different layers

•

Application Layer: This provides the interface and services that support user application. Ex. E-mail, WWW, SMTP.

•

Presentation Layer: This layer responsible for data encryption, data compression .Ex JPG, MPEG etc

•

Sessions Layer: Responsible for setting up the communication link and manages the sessions. It could provide connection oriented and connectionless services.

Functionality of different layers

•

Transportation Layer: Responsible for flow control, Packet size, error free delivery with proper sequence.

•

Network layer: Route determination takes place in this layer. Translation of IP address to physical address ( NIC) also takes place here.

•

Data link layer : Responsible for data movement across the actual physical link.

•

Physical Layer: It defines the physical aspect of how the cabling is hooked.

7 LAYER System X Application 7 System Y ••••••••••••••••••••••••••••••••••••••••••••••••••••••• 7 Presentation Session Transport Network Data Link Physical 6 5 4 3 2 1 ••••••••••••••••••••••••••••••••••••••••••••••••••••••• Peer communication Protocols ••••••••••••••••••••••••••••••••••••••••••••••••••••••• •••••••••••••••••••••••••••••••••••••••••••••••••••••••

Intermediate System A Intermediate System B

••• 3 ••• 3 ••• ••• 2 2 ••• 2 2 ••• ••• 1 1 ••• 1 1 ••• 6 5 4 3 2 1

Physical Media Physical Media Physical Media

•

Due to addition of many layer overhead and bandwidth goes higher.

•

It is not suitable for SCADA application.

•

Most of the Protocols follows various flavours of this model.

Need For Standards

* Protocol is a set of rules that governs how message containing data and control information are assembled at a source for their transmission across the network and then dissembled when they reach their destination.

* The communication protocol allows two devices to communicate with each other. Each device involved in the communication must essentially support not only the same protocol but also the same version of the protocol. Any differences involved in the implementation of protocol at the either of ends will result in the communication errors.

Proprietary Vs Open Protocols

* Protocol, used by the vendor, the utility is restricted to one supplier for support and purchase of future devices. This presents a serious problem.

Examples of Proprietary Protocols are SPA, K-Bus, VDEW etc.

* With the arrival of open systems concept , it is desired that devices from one vendor be able to communicate with those of other vendors i.e. devices should inter-operate . To achieve interoperability one has to use industry standard open protocols.

Ex: IEC60870 -5-103,101,104, IEC61850,DNP,Modbus etc

Advantages of Open Protocols

* Migration to standard communication protocol is a very important decision that leads to cost reduction and maximized flexibility within the utility sector. Broadly benefits for the utilities are: Availability of open system connectivity > Vendor independence > Reliable products at optimized costs > Easily available knowledge and specification Benefits drawn for vendors by standardization are: > Lower costs of installation and maintenance > A large market and thus opportunity to compete on price performance instead of technical details only.

> Cost effective project implementation

Interoperability Vs Interchangeability

*

Interoperability

is the ability of two or more IEDs from same vendor or different vendors to exchange information and uses that information for correct co-operation.

*

Interchangeability

is the ability to replace the device the supplied by one manufacturer with a device without making change to the other elements in the system.

PROTOCOL STRUCTURE

7-Layer Application Presentation Session Transport Network Data Link Physical OSI 3-Layer Application Data Link Physical EPA

Network Technology mainly based on OSI (Open System Interconnect) which is a 7 Layer model representing networking node by dividing tasks into layers that perform specific Functions.

Logical Connection

Application Presentation Session Transport Network Data Link Physical

Physical Connection

OSI Seven Layer architecture

PROTOCOL STRUCTURE for IP based Open Protocols

IEC, DNP, UCA (and even MODBUS) standards are successfully able to adopt TCP/IP based Ethernet based technology for substation automation. IEC 61850 (UCA2) DNP3/TCP IEC 104 TCP/UDP IP IEEE 802.1

IEEE 802.3

} TCP/IP } Ethernet Application Presentation Session Transport Network Data Link Physical

Master

Link Layer Balanced Transmission

Request Message (User Data, Confirm Expected) [P] (Acknowledgment) [S] [S] Response Message (User Data, Confirm Expected) [P] (Acknowledgment) [P] = Primary Frame [S] = Secondary Frame Slave

Link Layer Balanced Transmission

• At the link layer, all devices are equal • Collision avoidance by one of the following: – Full duplex point to point connection (RS232 or four wire RS485) – Designated master polls rest of slaves on network (two wire RS485 and disable data link confirms in slaves) – Physical layer (CSMA/CD)

Link Layer Unbalanced Transmission

Master Request Message [P] (User Data, Confirm Expected) (Acknowledgment) [S] [P]

Response Message

(Request User Data) (Respond User Data or NACK) [S] [P] = Primary Frame [S] = Secondary Frame Slave

Link Layer Unbalanced Transmission

• • • Only Master device can transmit primary frames Collision avoidance is not necessary since slave device cannot initiate exchange, or retry failed messages If the slave device responds with

NACK: requested data not available

the master will try again until it gets data, or a response time-out occurs

Protocols used in Electrical utilities are as follows: 1) Modbus / Profibus 2) DNP ( Distributed Network Protocol ) 3) IEC 60870 series 4) UCA ( Utlity Communication Architecture ) – IEC 61850 series

MODBUS Developed in the process-control industries by MODICON , USA during 1976 - Application layer Protocol ( 7 th Layer of OSI )

-

Extensively used in industrial environment

-

Used in process bus of substation bay ( Relays )

-

It operates on master slave type mode

-

Slave node will not typically transmit data with out a request from the master.

• •

It was originally designed as a simple way to transfer data between controls and sensors via RS-232 interfaces.

•

Modbus now supports other communication media, including TCP/IP.

Modbus is now an administered by (www.modbus-ida.com).

the open standard, Modbus-IDA

Modbus and DNP3 Communication Protocols

• • • • • Modbus and DNP are both byte-oriented protocols.

Modbus is an application layer protocol, while DNP contains Application and Data Link Layers, with a pseudo-transport layer.

Both protocols are widely used over a variety of physical layers, including RS-232, RS-422, RS-485, and TCP/IP.

Modbus has a separate specification for use over TCP/IP (Modbus-TCP). With DNP, the protocol is simply encapsulated within TCP/IP.

Distributed Network Protocol 3.0

Distributed Network Protocol ( DNP) was developed by Harris, USA

.

• • • •

The Distributed Networking Protocol (DNP) was originally developed by Westronic, Inc. (now GE Harris) in 1990.

The “DNP 3.0 Basic 4” protocol specification document set was released into the public domain in 1993, and ownership of the protocol was given to the newly formed DNP Users Group in October 1993.

DNP was specifically developed for use in Electrical Utility SCADA Applications.

It is now the dominant protocol in electrical utility SCADA systems, and is gaining popularity in other industries, including Oil & Gas, Water, and Waste Water.

-In 1993 the responsibility for defining further DNP specification was given to DNP user Group.

- DNP is based on the earlier work of IEC TC 57 - It is based on Enhanced Performance architecture ( EPA) model - There are 4 core documents to define DNP 3

Emergence of Standard

• DNP 3.0

• Based on earlier work of IEC TC57 • Developed by GE Harris

DNP 3.0 is an open protocol that was developed to establish interoperability between RTUs, IEDs (Intelligent Electronic Devices) and master stations. DNP was largely influenced by North and South America, together with the African and Asian regions as IEC 101 was from the European community.

DNP 3.0 Structure

• Three Layered Protocol (EPA) • Application (Layer 7) • Data Link (Layer 2) • Physical (Layer 1)

This structure is similar to IEC. However, DNP3 enhances EPA by adding a fourth layer, a pseudo transport layer that allows for message segmentation.

Additional Pseudo Layer

• In addition • Pseudo Transport Layer (Layer 4)

DNP introduces a pseudo-transport layer(OSI Layer 4) to build application data messages larger than a single data link frame. In case of IEC, each 101 message should be contained in a single data link frame.

• Support Advance RTU functions

• • • • • • • • • • DNP3 is an open, intelligent, robust, and efficient modern SCADA protocol.

It can request and respond with multiple data types in single messages, segment messages into multiple frames to ensure excellent error detection and recovery, include only changed data in response messages, assign priorities to data items and request data items periodically based on their priority, respond without request (unsolicited), support time synchronization and a standard time format, allow multiple masters and peer-to-peer operations, and allow user definable objects including file transfer.

In 1994, the IEEE Power Engineering Society’s Data Acquisition, Monitoring and Control Subcommittee formed a Task Force to review the communication protocols being used between Intelligent Electronic Devices (IEDs) and Remote Terminal Units (RTUs) in substations.

• • • • The IEEE Task Force found a very confusing, constantly changing environment that was increasing the cost and time to completion of substation SCADA systems. The IEEE Task Force collected information on approximately 140 protocols and compared them to a list of communication protocol requirements. This comparison resulted in a short list of protocols that met most of the requirements. This short list was balloted and two serial SCADA protocols tied for being the most acceptable: IEC 60870-5-101 and DNP3.

• Structure of IEC 60870-5 – Three Layered Protocol(EPA) • Application (Layer 7) • Data Link (Layer 2) • Physical (Layer 1)

For Tele Control System that require particularly

• Why 3-Layered Structure of EPA 1) Short Reaction Time 2) Reduced Transmission Bandwidth

BW: Measure of capacity of a transmission system. Measured in Hertz. How fast data can flow on a given transmission path. In Digital data transmission, BW is expressed as data speed in bits per second. Thus, higher the BW, more data can be transmitted.

• Purpose of 60870-5 Protocol • High Integrity

Correct data should reach the destination

• Efficient Data Transmission

Without Loss

• Protection Against Undetected Transmission Errors

DNP 3.0 and IEC 60870-5-101

• Both DNP 3.0 and IEC 60870-5-101 • Designed for Transmission of SCADA Data for Electric Power System Control • Wide Market Acceptance • Intended for Use in SCADA Systems Using directly Connected Serial Links

DNP 3.0 and IEC 60870-5-101

• 60870-5-101 and DNP Usage • Collection of Binary Data • Collection of Analog Data • Collection, freezing and Clearing of Counters

DNP 3.0 and IEC 60870-5-101

• Time Synchronization • Time-Stamping Events • File Transfer • Unsolicited Events Reporting

IEC 60870-5 Series It is bit serial communication standards. The standard is optimised for efficient and reliable transfer of process data and commands to and from geographically widespread systems over low-speed (up to 64 kbps) fixed and dial-up connections.

IEC 60870-5-101

–

It deals the functionality for the interoperability of telecontrol equipment of different manufactures for the communication between substations and between substation and control centres .

IEC 60870-5-102 This standard deals with values of integrated totals which are transmitted at periodic intervals to update the energy interchanges between utilities or between heavy industry and utilities.

IEC 60870-5-103 - This deals with informative interface of protection equipment . IEC 60870-5-104 - This present a combination of the application layer of IEC 60870-5-101 and the transport functions provided by a TCP/IP.

IEC 61850 This standard unifies UCA with European standard. It aims to design a communication system that provides interoperability between the functions to be performed in a substation.

IEC 61107 : This specifies hardware and protocol specifications for local systems in which a hand held unit is connected to only one tariff device at a time. This specifies hardware and protocol specifications for local systems in which a hand held unit is connected to only one tariff device at a time.

 

1) IEC 61107 is essentially a protocol providing a means to access (read and write) memory locations, without telling anything about how those memory locations should be filled with information.

2) IEC 61107 does neither say anything about the format and the interpretation of the data.

3) IEC 61107, developed for the purposes of local data exchange, does not follow the OSI model of layered protocols and does not have the functions provided by these layers. Therefore, although it is widely used over telephone networks, it is only possible with some compromises.

4) IEC 61107 lacks advanced security functions.

5) Consequently, for each new meter type, even from the same manufacturer, a new device driver is required.

Such drivers carry information about where and how to find the information and how to interpret it. The development of device drivers has proven to be a lengthy and costly exercise.

Communication - Interfaces & Protocols in Substation

* * Serial (RS232/RS485/RS422) LAN (Ethernet)

Serial Protocols

* * * * IEC 60870-5-103 (Protection) IEC 60870-5-101 (Tele Control) DNP 3.0 (Protection, Monitoring & Metering) Modbus RTU (Metering)

LAN Protocols

* * * * IEC 60870-5-104 DNP 3.0 over TCP/IP MODBUS over Ethernet ( For Industries) IEC 61850

Communication Protocols from Station Level Equipment.

Station Level

* Serial * Ethernet

Station Level Protocol

* IEC 60870-5-101 * IEC 60870-5-104 * DNP 3.0 over TCP/IP * Modbus over Ethernet / Serial

DNP 3.0

* Supports Balanced Transmission Services * Supports - Time Synchronization - Time-stamped events - Freeze/Clear Counters - Select before operate - Unsolicited Responses

IEC 870-5-101: Basic Telecontrol Tasks

• Protocol Standard for the telecontrol of Electrical Power Transmission Systems.

• Permanent Directly Connected (Serial) Link between Telecontrol stations.

• Supports both Balanced/Unbalanced Transmissions • Frame Type FT1.2 (1 Byte Checksum error check)

IEC 60870-5-104

• This protocol standard is developed to Provide Network access for IEC 870-5-101 • Application Layer remains same. • Does not use the Link Layer functions of IEC 870-5-101.

• Some APCI (Application Protocol Control Information) Added to 101 ASDU To suitable for network transportation

Modbus Over Ethernet / Serial

• Modbus Over Ethernet protocol if useful in sending Modbus messages on LAN / WAN network.

• Additional of 6 Bytes serial frame.

as a MBAP Header to basic Modbus over • Slave Address byte of serial Modbus frame is replaced with Unit Identifier.

IEC 870-5-103 • Companion Standard for Interface of Protection Equipment's • Unbalanced Master Slave Serial Protocol.

• Protective Relays Act as Slave Devices.

• Station Controller as a Master.

• Physical Interface may be RS232,RS485 (or) Fiber Optic.

• Status indications,Measurement values, time-tagged events, control commands and clock synchronization Can be transferred between Master & Slave Devices .

Future ( IEC 61850 / UCA )

Standard for communication network and systems in Substation.

Intended to integrate * Protection System * Control System * Substation Field Devices * Interface to Supervisory Control and Data Acquisition(SCADA) of Control Center * One of the most important features of IEC 61850 is that it covers not only communication, but also qualitative properties of engineering tools, measures for quality management, configuration management & Conformance testing.

and

Communication Standards Within the Substation IEC 60870-1-103 / DNP 3.0 Modbus / IEC 61850

What to Expect from Vendor on Protocols in their Devices??

IEC-60870-5-103 protocol

* Communication Settings supported (Baudrate, Parity, IED address range config.).

*Function Types supported (both Standard, Private).

*COT Supported.

*ASDU Type supported for each type of Tag or Parameter or information.

*Information number (Standard, Private) for each parameter or tag & description for the same.

*Any private ASDU ( ASDU 254,255 )implementation?

If so then details.

* Interoperability Table if any

DNP3.0 Protocol * Details of Communication Interface supported.

* DNP Levels Supported.

* Data Scaling Range if any?

*Data Retrieval Method supported (unsolicited/polled static/exception).

*Object Type & variations supported.

*Data Map (Index number ) of each parameter.

Modbus (RTU) Protocol

*Details of Communication Interface supported.

*Relay Address range supported.

*Function Types supported.

*Address range for each parameter.

*Data Type(16 bit(integer),32 bitz(long int), etc) *Multiplication factors if any.

*Parameters type (Read only/read/write).

Typical Architecture of ERSA System

HMI # 2 HMI # 1 Remote Control Center Ethernet LAN

ER 1000 400 & 220 kV Bay Control Units Protective Relays Tariff Meter

MV Architecture

Local HMI Remote HMI Station Controller Modbus Hardwired I/O’s for protection and Equipment Status Bay Control & Protection Units Multifunction Meters

ER 1000 Station Controller/Communication Gateway

Remote Control Center Local HMI

ER 1000

DNP 3.0 / IEC 101 / IEC 104 / Modbus serial or Ethernet [ Slave components] IEC 103 Master DNP 3.0 Master Modbus Master IEC 60870-5-103 Slave Components DNP 3.0 Slave Components Modbus Slave Components Hardwired Analog/Digital I/O’s for protection and Equipment Status

Functionality's & Requirement of station Controller

•Communication Gateway •Protocol Converter •Virtual RTU •Data Concentrator •Automation Unit •Wired I/O’s •Open H/W architecture and OS •IEC 61131-3 compliant PLC programming •Highly modular and hence easily expandable •Superior architecture compared to a PC based architecture •Can work in any extreme environmental conditions

What is Simple Substation Control And Monitoring System????...

* Present the state and operational Details of the field equipment in a user friendly manner through a powerful GUI •Control and monitor the field equipment, protection IED’s locally or remotely •Inbuilt -Energy Management System with communicable Multifunction Meters. • Report Generation (Hourly, Daily, monthly, yearly), Alarms •IED Parameterization, Disturbance Analysis.

•Online Sequence of Time Tagged Events (Source / System Time Stamp) printing and Event File Storing.

A simple relay based substation control Local Workstation Ethernet/Dialup Remote HMI SOE Printer IEC 103 IEC 103 Serial to Fibre Optic Converter ER 10 ER 10 Modbus ER 05 RS 485/422 to RS 232 Converter Multifunction Meters RTU Modbus/RS485 ER Relays ER Relays

•

Electric utilities were among the first entities to embrace data telemetery.

•

Data telemetry was introduced for monitoring , Control and Protection.

•

Development in communication, Computer, introduction of Intelligent Electronic Devices (IED) made information collection easier.

•

Different manufacturers introduced different rules for communicating and exchanging information among their intelligent devices.

•

This introduced barriers in communicating with other device manufactured by others.

IEC 62056 - Series Data Exchange for Meter Reading- Tariff and Load control

1) 62056 covers all metering functions required on the liberalised market. The functions are modelled using metering domain specific interface objects. This allows developing meters meeting exactly customer needs, using standard building blocks.

It also allows innovation and competition by enhancing functionality in a standard way as required while maintaining interoperability.

2) It ensures unique identification of all metering equipment world-wide and unambiguous identification of all data elements.

3) It ensures unambiguous interpretation of all metering data.

4) It allows controlled and selective access by various parties to application relevant data.

5) It provides various levels of security mechanisms to control access to data depending on authentication and access rights.

6) opens the way for exchanging data over various communication media, as the meter data model is independent of the communication protocol stack.

7) It b rings interoperability, and therefore lowers costs, as it is based on a standard data model and internationally approved standard protocols.

8)

It allows developing a genuine driver, as the meter describes the functions available and sends all information necessary to interpret data. This allows meter manufacturers and data collection system providers to concentrate on the applications relevant for their customers rather than on connectivity and interfaces; 9) It comes complete with a conformance testing scheme to guarantee interoperability.

IEC 60870-6, TASE.2

This deals with mechanism for exchanging time-critical data between control centres. In addition, it provides support for device control, general messaging and control of programs at a remote control centre.

IEC 61970 This deals with CIM facilities for the integration of EMS applications developed independently by different vendors, between entire EMS systems developed independently, or between an EMS system

IEC 62210 This deals with safety, security and reliability of systems in Electrical Utilities. The deregulated market has imposed new threats and safe operation is essential in a deregulated environment.

IEC 61400-25 This provides a standard for interconnection of monitoring and control systems for wind power plants

IEC 62195 TR This report deals with Electronic communication in deregulated markets and makes a clear distinction between communications for control of energy systems and communications for the market

Possible trend in the near future Ref: CIGRE report on Substation Automation

Possible trend in the far future Ref: CIGRE report on Substation Automation

Utility Control Center Substation Protection, Monitoring, & Control Network Expansion Planning Customer Inquiry Network Operation Records & Asset Management IEC 61968 Compliant Interface Architecture Meter Reading & Control Maintenance & Construction Operational Planning & Optimization Utility Business Systems (ERP, Billing, Energy Trading, Other Systems) Corporate LAN

IEC TC57 Reference Architecture 60870-6 Control centre Protection Metering 60870-5 -103 61850 Substation Automation 60870-5 -101 61850 Remote Terminal Unit S C A D A 61970 EMS Application 61968 DMS Subsystem Physical Device Substation Control Centre

Relevant IEC Standards • • • • .

Technical Committee 57 – Power system control and associated communications Published – IEC 60870 Telecontrol equipment and systems – IEC 61334 Distribution Automation using Power Line Carrier – IEC TR 62210 Power system Control and associated Communications – Data and Communication security – IEC 61400-25 Communication for monitoring and control of Wind Power plants. – TR 62195 Deregulated energy market communications • confirmed EDIFACT as transactions

a

recommended standard for business In progress – IEC 61850 Communication networks and systems in substations – IEC 61968 System Interfaces for Distribution Management – IEC 61970 Energy Management Systems Application Program Interfaces – IEC 62350 Communication systems for Distributed Energy Resources – IEC 62344 Hydro Electric Power Plants – Communication for monitoring and control.

Introduction UCA

Brief Description about UCA 2.0

Electric Power Research Institute (EPRI) launched a concept in 1990 known as the Utility Communication Architecture or UCA. The goal behind UCA was to identify a suite of existing communication protocols that could be easily mixed and matched, provide the foundation for the functionality required to solve the utility enterprise communication issues, and be extensible for the future. After some initial revisions, the results of the project have been known as UCA 2.0. UCA 2.0 is described in a technical report TR 1550 of the IEEE [2]. UCA2- SUBSTATION COMMUNICATION MODEL

Concept of 61850

Brief description about IEC 61850

The basis and the way of standardizing communications in IEC 61850 are entirely new. IEC 61850 was developed from IEC 60870-5-x and UCA 2.0.

Comprehensive EPRI project UCA 2.0

International Agreed Goals IEC 60870-5-101, -103, -104 IEC 61850

The goal of this standard IEC 61850

“

Communication networks and systems in substations

”

is to provide interoperability between the IED

’

s from different suppliers or, more precisely, between functions to be performed in a substation but residing in equipment (physical devices) from different suppliers. Interchangeability is outside the scope of this standard, but the objective of interchangeability will be supported following this standard.

Interoperability has the following levels for devices from different suppliers: (1) The devices shall be connectable to a common bus with a common protocol (syntax) (2) The devices shall understand the information provided by other devices (semantics) (3) The devices shall perform together a common or joint function if applicable (distributed functions) Since there are no constraints regarding system structure and data exchange, some static and dynamic requirements shall be fulfilled to provide interoperability.

What does IEC 61850 achieve

System configuration Defines structure for protection and control Communication between bay devices Standardised language for describing substation Standard communication with TCP - IP IEC 61850 Based on Ethernet standard Comtrade Time Fault records in format synchronisation with SNTP

• • • • • •

Advantages in IEC 61850?

IEC 61850 is a global standard for “Communication Networks and Systems in Substations”

It specifies an expandable

data model and services

It does not block future development of functions – It specifies

no protection or control functions

It supports free allocation of functions to devices – It is open for different system philosophies It provides the Substation Configuration description Language (SCL) – It supports comprehensive consistent system definition and engineering It uses Ethernet and TCP/IP for communication – Provides the broad range of features of mainstream communication – It is open for future new communication concepts

GOOSE ??

IEC 61850 – GOOSE Principle

A device sends information by Multicasting. Only devices which are subscribers receive this message.

In the example, Receiver Z receives the message. Receiver Y is not a subscriber.

GOOSE Receiver Device Y GOOSE Sender Device X GOOSE Receiver Device Z

Difference of IEC 61850 and UCA 2.0 : fast messaging “GOOSE”

Fast GOOSE Overtaking path for IEC GOOSE

Ethernet Switch

Normal message Buffer for Normal Message

IEC 61850 Key benefits IEC 61850 is a definite step towards unified substation communication, compared to the former IEC 60870-5-103, DNP3 and most proprietary protocols:



to be speed of exchanges: 100 Mbps instead of few 10kbps, enabling more data exchanged or a better operation or maintenance of the system,



and also peer-to-peer links, replacing conventional wires with no extra hardware but permitting the design of innovative automation schemes,



client-server relations offering flexible solutions easy to upgrade compared to master slave communications,



users, object oriented pre-defined names, creating a single vocabulary between suppliers and supplier’s devices therefore facilitating the system integration and commissioning,



XML interfaces referencing the above objects for straightforward exchanges between engineering tools in order to optimise the data consistency and minimise project lead times.



communication conformance tests that help reducing the variety of interpretation tests and tuning. found in many legacy protocols and leading to long integration

    

IEC 61850 Based SAS Projects

PGCIL Maharanibagh GIS: 400 KV Switchyard with 5 bays (Two Main) 220 KV Switchyard with 7 bays (Two Main) Separate SA systems for 400 and 200 kV Levels.

FAT completed in Dec. 2005  PGCIL Bhatapara:  400 KV Switchyard with 6 Diameters (1½ Breaker)  220 KV Switchyard with 12 bays (Two Main +Transfer)  Common SA system for 400 and 220 kV Levels  FAT completed in Dec. 2005  PGCIL Raigarh:  400 KV Switchyard with 8 Diameters (1½ Breaker)  220 KV Switchyard with 9 Bays (Two Main +Transfer)   Common SA system for 400 and 220 kV Levels FAT completed in Jan. 2006

PGCIL Maharanibagh 400 kV S/S

IEC 60870-5-101 Laser Printer Redundant HMI DR WS GPS Receiver DMP Gateway IEC 61850 Redundant Ring network Ethernet Switch Ethernet Switch Ethernet Switch Ethernet Switch Ethernet Switch REC 670 REL 670 Main I REC 670 REL 670 7SA522 Main II RET 670 Main I RET 670 Main II REC 670 BBP Bay Units Main I, Main II REL 670 BBP Bay Units Main I, Main II BBP Bay Units Main I, Main II REC 670 Line x 2 Autotransformer x 2 Bus Coupl. x 1 Auxiliaries REB 500 Main I REB 500 Main II Busbar

PGCIL Maharanibagh 220 kV S/S

IEC 60870-5-101 Laser Printer Redundant HMI DR WS DMP Gateway IEC 61850 Redundant Ring network Ethernet Switch Ethernet Switch Ethernet Switch Ethernet Switch Ethernet Switch REC 670 REL 670 Main I 7SA522 Main II BBP Bay Unit REC 670 REB 500 Line x 4 BBP Bay Unit Autotransformer x 2 Bus Coupler x 1 Busbar