Transcript No Slide Title

New structure in Deregulated Environment
Genco
Genco
Genco
Open access in
Transmission
Traders
Discom
Traders
Customer
Discom
Discom
Open access in
Distribution
Customer
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.
Event Printer
Remote Center
HMI
Hard Copy Printer
Ethernet LAN
ER1000 Station Controller
Fault Analysis
Reyevo / SEL5601 / IPSCOM
Multifunction Meter
Argus
Duobias-M
Delta
Ohmega
Engineering Tool
ISAGRAPH
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
7
Application
6
Presentation
55
4
Sessions
Transport
3
2
1
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
System Y
Application
7
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Session
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Peer communication Protocols
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Transport
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Network
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Data Link
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Physical
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Intermediate System A
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3
Physical Media
Intermediate System B
4
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3
2
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2
1
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1
3
Physical Media
5
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
3-Layer
Application
Application
Presentation
Session
Transport
Network
Data Link
Data Link
Physical
Physical
OSI
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
Application
Application
Presentation
Presentation
Presentation
Session
Session
Transport
Transport
Transport
Network
Network
Network
Data
Data Link
Link
Data Link
Physical
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)
IEC 104
DNP3/TCP
Application
Presentation
Session
TCP/UDP
IP
IEEE 802.1
IEEE 802.3
}TCP/IP
}Ethernet
Transport
Network
Data Link
Physical
Link Layer
Balanced Transmission
Request Message
Master
[P]
Slave
(User Data, Confirm Expected)
(Acknowledgment) [S]
Response Message
(User Data, Confirm Expected)
[P]
[S]
(Acknowledgment)
[P] = Primary Frame
[S] = Secondary Frame
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
Request Message
Master
[P]
Slave
(User Data, Confirm Expected)
(Acknowledgment)
[S]
Response Message
[P]
(Request User Data)
(Respond User Data or NACK)
[S]
[P] = Primary Frame
[S] = Secondary Frame
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 open standard,
administered
by
the
Modbus-IDA
(www.modbus-ida.com).
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
In Digital data transmission, BW is expressed
system. Measured in Hertz. How fast data
as data speed in bits per second. Thus, highe
can flow on a given transmission path.
the BW, more data can be transmitted.
• Purpose of 60870-5 Protocol
• High Integrity
Correct data should reach the destination
• Efficient Data Transmission
• Protection Against Undetected
Transmission Errors
Without Loss
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 as a MBAP Header to basic Modbus over
serial frame.
• 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, and
configuration management & Conformance testing.
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 # 1
HMI # 2
Remote Control Center
Ethernet LAN
ER 1000
400 & 220 kV Bay Control Units
Protective Relays
Tariff Meter
MV Architecture
Remote HMI
Local 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
IEC 60870-5-103 Slave
Components
DNP 3.0 Master
DNP 3.0 Slave
Components
Modbus Master
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
Remote HMI
Ethernet/Dialup
IEC 103
SOE Printer
Serial to Fibre Optic ER 10
Converter
IEC 103
Modbus
ER 05
ER 10
RS 485/422 to RS 232
Converter
Multifunction
Meters
RTU
ER Relays
ER Relays
Modbus/RS485
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 brings 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
Network
Expansion
Planning
Network
Operation
Customer
Inquiry
IEC 61968
Compliant
Interface
Architecture
Meter
Reading &
Control
Substation Protection,
Monitoring, & Control
Maintenance
&
Construction
Operational
Planning &
Optimization
WG 14
RTU Communications
(ERP, Billing, Energy
Trading, Other Systems)
Corporate
LAN
Distribution Automation
Records
& Asset
Management
Utility
Business
Systems
IEC TC57 Reference Architecture
Control centre
60870-5
-103
Protection
61850
61850
Metering
Physical
Device
60870-6
60870-5
-101
Substation
Automation
Remote
Terminal
Unit
Substation
61850
S
C
A
D
A
61970
61968
EMS
Application
DMS
Subsystem
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 a recommended standard for business
transactions
• 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 61850
IEC 60870-5-101,
-103, -104
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
Standardised
language for
describing
substation
Standard
communication
with TCP - IP
Defines structure
for protection and
control
Communication
between
bay devices
IEC 61850
Based on
Ethernet
standard
Fault
records
in
Comtrade
format
Time
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
GOOSE
Receiver
Device Y
Ethernet
GOOSE
Sender
Device X
GOOSE message
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 Z
Difference of IEC 61850 and UCA 2.0 : fast messaging “GOOSE”
Overtaking path for IEC GOOSE
Fast 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,

peer-to-peer links, replacing conventional wires with no extra hardware but
and also
permitting the design of innovative automation schemes,

client-server relations offering flexible solutions easy to upgrade compared
to master
slave communications,

object oriented pre-defined names, creating a single vocabulary between
users,
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
found in many legacy protocols and leading to long integration
tests and tuning.

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
REC 670
REL 670 Main I
Ethernet Switch
Ethernet Switch
Ethernet Switch
REC 670
RET 670 Main I
REC 670
REC 670
REL 670
7SA522 Main II
REB 500 Main I
RET 670 Main II
REL 670
BBP Bay Units
Main I, Main II
Line x 2
REB 500 Main II
BBP Bay Units
Main I, Main II
Autotransformer x 2
BBP Bay Units
Main I, Main II
Bus Coupl. x 1
Auxiliaries
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
REC 670
REL 670 Main I
Ethernet Switch
Line x 4
Ethernet Switch
REC 670
7SA522 Main II
BBP Bay Unit
Ethernet Switch
REB 500
BBP Bay Unit
Autotransformer x 2
Bus Coupler x 1
Busbar