basics of iec61850 standard

Doble

SUNDAY TUTORIAL: “Basics of IEC 61850 Standard” Sunday, October 10th, 1:00 pm 5:30 pm IEC 61850 is a standard that is being used to make substation automation easier, save money by elimination of significant amount of substation wiring and make interoperability between relays manufactured by different vendors. The standard has its root in Europe and is spreading fast in other parts of the world. In USA the response has been cautious. American utilities are implementing this standard on specific stations to study the performance and savings impact. Hence there is an unclear understanding of this standard in the US. The intent of this tutorial is to introduce this standard to the engineers, managers and technicians representing various utilities. This session assumes that the audience knowledge of this standard is minimal to none. The tutorial will start with background information and will explore the basics of the standard. It will provide a general overview of the various aspects of this standard including station bus details, GOOSE and GSE messaging, and a brief description of Process Bus implementation. The implementation of this standard imposes new methods for testing relays that are compliant with this standard. Details of testing such relays and IEDs (Intelligent Electronic Devices) will be presented. After attending this tutorial, the audience will take away a very good conceptual knowledge of the IEC 61850 standard with the advantages and challenges posed in its implementation. This tutorial will be presented by three speakers; Lars Frisk from ABB, Rich Hunt from GE, and Ralph Mackiewicz from SISCO, Inc. Ralph Mackiewicz of SISCO, Inc. will discuss the following topics dealing with a technical overview of the IEC 61850 Standard. This will provide basic concepts of the standard needed by engineers, managers, etc. who are involved with substation equipment in general and automation in particular. Technical Overview of IEC 61850 1. IEC 61850 Summary 2. IEC 61850 Logical Device Structure 3. IEC 61850 Services 4. Substation Configuration Language 5. Question/Answer Ralph Mackiewicz is VP of Business Development for SISCO, a developer of communications and integration products for electric utility applications located in Sterling Heights, Michigan. Ralph has a BSEE from Michigan Technological University and was engineering manager for Westinghouse Electric Corporation prior to joining SISCO in 1985. Ralph has been an active participant in the MMS, UCA and ICCP‐TASE.2 standards activities. Ralph has presented tutorials, papers, and seminars at events and in publications sponsored by IEEE, CIGRÉ, Pennwell, EPRI, UCA International Users Group, and others. Ralph holds two patents, is a member of IEEE and CIGRÉ, and is currently chair of the UCA International Users Group Marketing Oversight Subcommittee.

Doble

Rich Hunt of GE will discuss the Process Bus portion of the IEC 61850 standard. He will go into detailed discussion about GE implementation of the Process Bus. He will also discuss the business case for such an implementation and some thoughts of testing process bus installation. IEC 61850 Process Bus—Business Case, Implementation and Testing.

1. Definition of IEC 61850 Process Bus 2. The Business Case for Process Bus 3. Considerations for Process Bus Installations 4. Some thoughts on testing Process Bus installations 5. Question and Answer

Rich Hunt is presently a Market Development Leader for GE Digital Energy, responsible for HardFiber, the IEC 61850 Process Bus solution from GE. Between utilities and vendors, Rich has over 20 years experience in the electric utility industry. Rich earned the BSEE and MSEE degrees from Virginia Tech, is a Senior Member of IEEE, the past Chair of the Systems Protection Subcommittee of the IEEE PSRC, and is a registered Professional Engineer. Lars Frisk of ABB will discuss field/practical examples of IEC 61850 Solutions. This will provide the audience with clear examples of various applications of this standard and how this has/will help substation automation, communication, cost savings and easy duplication of system design. Field examples of IEC 61850 Solutions

1. Power distribution ‐ Where can you start 2. Transmission substations ‐ Copper wire, how to get rid of it 3. Large systems ‐ How to go big 4. Process bus installations ‐ A highway in your substation 5. Q&A

Lars Frisk is Application Specialist with the ABB Substation Automation Products team in Burlington, Ontario. Lars is the ABB North American expert on IEC 61850 and has been instrumental in implementing a number of projects in the United States, Canada and Mexico. He has published papers that have been presented at numerous conferences throughout the United States. Lars has 15 years experience in hydro power, power distribution and substation automation in Sweden, India and Canada. Mr. Frisk holds a patent on Automated Generation of Disturbance Reports. His studies focused on operations and maintenance in hydro power at Mid Sweden University.

Systems Integration Specialists Company, Inc.

IEC 618 0 T h i lIEC 61850 Technical Summary

Ralph MackiewiczSISCO, Inc.6605 19½ Mile Road

© Copyright 2010 SISCO, Inc.

Sterling Heights, MI 48314-1408 USATel: +1-586-254-0020 x103Fax: +1-586-254-0053Email: [email protected]

AcronymsAcronyms

A id bl h di iAcronyms are unavoidable when discussing communications and integration technology.

It bj ti t d fi llIt was our objective to define all acronyms before using them.

If t t i l k tiIf you are not certain, please ask a question.

© Copyright 2010 SISCO, Inc.2

Ground RulesGround Rules

Have a Question?Ask a Question As Needed!


THERE WILL BE A TEST!!


Why Standards Are Needed

An Overview of IEC TC57 Standards


InteroperabilityInteroperabilityInteroperabilityInteroperability

The ability of computer systems to exchange information ith th twith other systems.

IntegrationIntegrationThe ability of computer based applications to interact with other y p pp

systems in order to perform a useful function for the user.


Interoperability andInteroperability and Integration

Easy to Achieve:Easy to Achieve:

Nearly anything is possible with enough money and


development effort

A Better Way

Interoperability and Integration without having to create supportInteroperability and Integration without having to create, support, maintain, improve, and fix it all yourself:

Where applications and devices are inherently capable of interoperating with other systems and performing integrated application functions in a cooperative and distributed manner.

This is only possible with Standards

This is the goal of the IEC TC57 standards


A Cautionary Note

Interoperability and Integration of applications is a path, not an end

point.

By the time we get to were we are going today, someone will have

moved the goal.

If you don’t set out on the path, you will never make any progressprogress.


International Electrotechnical Commission (IEC)

IEC is an international Standards Development Organization (SDO) withIEC is an international Standards Development Organization (SDO) with membership that is made up of national standards bodies of countries.

American National Standards Institute (ANSI) for USA

Standards jointly issued with International Organization for Standardization (ISO)

IEC standards are inherently internationally focused versus other SDOsIEC standards are inherently internationally focused versus other SDOs

IEC standards from Technical Committee 57 (Power systems management and associated information exchange) have been the key foundation for many smart grid efforts.

125 existing publications27 active projects


Key IEC TC57 Working GroupsKey IEC TC57 Working GroupsWG 10 - Power system IED communication and associated data models

IEC 61850 – Communications for power system automationIEC TC88 – IEC 61400-25 series for IEC 61850 interfaces for wind powerIEC TC88 IEC 61400 25 series for IEC 61850 interfaces for wind power

WG 13 - Energy management system application program interface (EMS - API)IEC 61970 – Common Information Model (CIM) and Generic Interface Definition (GID)

WG 14 - System interfaces for distribution management (SIDM)IEC 61968 CIM f di t ib ti d d l d i iIEC 61968 – CIM for distribution and model driven messaging

WG 15 - Data and communication securityIEC 62351 – Communications Security

WG 16 - Deregulated energy market communicationsIEC 62325 – CIM for energy markets

WG 17 - Communications Systems for Distributed Energy Resources (DER)IEC 61850-7-420 – IEC 61850 for DER applications

WG 18 - Hydroelectric power plants - Communication for monitoring and controlWG 18 Hydroelectric power plants Communication for monitoring and controlIEC 61850-7-410 – IEC 61850 for Hydropower applications

WG 19 - Interoperability within TC 57 in the long termTC57 strategy and coordination


CIM – IEC 61850 HarmonizationICCP-TASE.2 Update


What is IEC 61850?

Communications and Networks for Power Systems Automation


Automation

Traditional Protocol Standards

Specified how you arrange bytes on the wire in order to transfer bytes of data between a device and an application

Good News: It worked! Device communications costs were lowered.

Bad News: No standard for:Bad News: No standard for:The meaning and organization of data.

Configuration of devices.

How devices should look and behave to network applications.

Some Level of Interoperability was achieved but not end-to-end Integration


Integration

IEC61850 is DifferentIEC61850 is DifferentIEC61850 is an object oriented substation automation standard that defines:

Standardized namesStandardized meaning of dataStandardized abstract servicesStandardized device behavior modelsMapping of abstract services and models to specific protocol profiles for:

Control and reportingP t ti GOOSEProtection - GOOSETransducers – Process I/O

Companion Standards for:Wind powerHydro powerDistributed Energy Resources


More likely

IEC 61850 Object ModelsIED:Relay1/MMXU1.MX.A IED:Relay1/XCBR2.CO.Pos

Current Breaker

A PhV A PhV Pos Pos

CurrentMeasurements

BreakerPosition Control

MXMeasurements

AAmps

PhVVolts

DCDescriptions

AAmps

PhVVolts

Logical Nodes

STStatus

PosPosition

COControls

PosPosition

Logical Device(e g Relay1)

MMXU1Measurement Unit #1

XCBR2Circuit Breaker #2

Logical NodesIEC 61850 Object Names Use Power

System Context

Physical Device – Named IED(network address)

(e.g. Relay1)


IEC 61850’s Original Design PurposeSubstation Automation


Smart Grid Application of IEC 61850Wide Area Phasor Measurements and Protection


Smart Grid Application of IEC 61850SCADA communications


Smart Grid Application of IEC 61850Distributed Energy Resources


Smart Grid Application of IEC 61850Impact on Meter Models


Long Term Impact of IEC 61850Communications for Power System Automation


New IEC 61850 Activities

IEC 61850-80-1 – Gateway mapping to IEC 60870-5-101/104 (DNP3)

IEC 61850-90-1 – Use of IEC 61850 for Communications Between S b t tiSubstations

IEC 61850-90-2 – Use of IEC 61850 for SCADA Communications

IEC 61850-90-5 – Use of IEC 61850 for Synchrophasor Communications (GOOSE and Sampled Values (process bus) over UDP/IP)

Edition 2 of IEC 61850 Update to the standard including some fixesEdition 2 of IEC 61850 – Update to the standard including some fixes, clarifications, improvements, and more consistency.


Common Information Model (CIM) is an object-Common Information Model (CIM) is an objectoriented information model of the power system

Central Generating Step-UpCentral GeneratingStation

Step-Up Transformer

DistributionSubstation

ReceivingStation

DistributionSubstation

Distribution

Gas Turbine Recip

Engine

Micro-Substation

Commercial

Industrial

RecipEngine

Cogeneration

Fuel cell

turbine

Flywheel

Photovoltaics

Batteries

Industrial CommercialResidential

UML – Unified Modeling Language


CIM PackagesIEC 61970 from IEC TC57 WG13

SCADACore

Documen

Load

Outage

ProtectionFinancialIEC 61968 from IEC TC57 WG14

Wires

Consumer

Assets Documen-tation

Core2 Generation

Outage

Measurements

EnergyScheduling

Reservation

IEC 62325from

IEC TC57WG16

Wires

ERP OAG TopologyDomain MarketOperations


Distribution EMS, Transmission & Planning Markets (Euro & NA)

How is CIM Used?

Power System Model Exchange between neighboring utilities and ISO/RTOs

D fi iti f M f h E t i S i BDefinition of Messages for exchange over an Enterprise Service Bus (ESB) using web services and a Service Oriented Architecture (SOA)

Common Data Exchange Model for Application Integration using model-g pp g gaware, model-independent interface services

Generic Interface Definition (GID) and OPC Unified Architecture (UA)

f fA common semantic model for integration of disparate systemsIt is the binding element of most of the NIST Smart Grid Interoperability Road Map standards.


CIM versus IEC 61850: What they defineCIM IEC 61850

Detailed Power System Topology

Asset Model

Consumer and load models

Power System Topology Model

Device Configuration Description

Device ModelsConsumer and load models

Financial

Scheduling and transactions

M k t ti

Device Models

Service ModelsReportingControls

Market operations

Work management

SCADA and Measurements

Protection

Performance/Requirements

Object and Data Naming Conventions

GIS – Location

Business Messaging (WG14)

Interface Services (GID)

Protocols



CIM versus IEC 61850: What they defineCIM IEC 61850

Detailed Power System Topology

Use of Globally Unique IDs (GUID)

Asset Model

Power System Topology Model

Use of names in topology model

Device Configuration Description

Consumer and load models

Financial

Scheduling and transactions

Device Models

Service ModelsReportingC t l

g

Market operations

Work management

SCADA and Measurements

ControlsProtection

Performance/Requirements

Object and Data Naming ConventionsSCADA and Measurements

GIS – Location

Business Messaging (WG14)


Object and Data Naming Conventions

Protocols



CIM Asset-Power System Models & IEC 61850 Device Models

IEC61970/68 CIM IEC61850

Power System Models

Power System Models

WG19 Harmonization

Device Models

Asset, trading, Models

Measurements

g,etc.


Measurements

CIM and IEC 61850 Difference in TopologyCIM and IEC 61850 Difference in Topology

Are these thesame objects?same objects?

IEC 61970-301 EMS Diagram


IEC 61850-6-1 SCL Diagram

Integration of CIM – IEC 61850

IEC TC57 WG19: “Interoperability Within TC 57”IEC 61850 for communications

CIM for modeling, messages, and enterprise integrationg g p g

Integration of non-overlapping models into a single unified modelIEC 61850 “package” for IEC 61970

Rules and procedures for transforming overlapping models when needed.

Convert from one model form to another to suit the applicationConvert from one model form to another to suit the application

Modifications needed to the standards to support this.


DNP 3.0 and IEC 61850 Comparison


Evolution

EPRI UCA UCA2 0100s of

100s ofProprietaryProtocols

EPRI UCAArchitecture

1991

UCA2.0IEEE TR1550

1999

IEC 61850ICCP

100s ofProprietaryProtocols

Mfg. Auto.Protocol-MAP

1984

MMSISO9506

1988

IEC 618502003

ICCPIEC60870-6

1996

100s ofProprietary

IEC60870-5IEC TC57

IEC TC57SubstationProtocolUpdate1995p y

Protocols 1994

DNP3Serial Links

DNP3Ethernet


Serial Links1993

Ethernet~2000

Comparison of Roots

DNP3 addressed North American requirements from IEC60870-5 work.

IEC61850 addressed European requirements from UCA2.0 workwork.


Comparison of Roots

IEC61850 was developed for LAN/WAN Exclusively

UCA2.0 included profiles for serial links but not IEC 61850

DNP3 was developed for serial links and profiles were addedDNP3 was developed for serial links and profiles were added later to run the protocol over LAN/WAN.


Comparison of Roots

DNP3 has roots in the RTU world where byte efficiency for low-speed links was important.

IEC61850 has roots in the LAN/WAN world where independence from the organization and storage of “bytes” was important.


Impact of Roots

DNP3 is very byte efficient optimized for low-bandwidth applications.

IEC61850 is feature rich with capabilities optimized for LAN/WAN based systems.


Impact of the Standard Structure

The DNP3 specifications look simpler.

IEC61850 defines more externally visible behavior for a device.


Service Comparisonp

Service Description DNP3 IEC61850

Read/Write YES YES

Reporting YES YES

Control (SBO and Direct) YES YES

Enhanced Control (with Reports) * YES

Files YES YES

Start/Stop YES *p

Event Logs * YES

Substitution (Forcing) YES YES

Object Discovery - YES

Substation Configuration Language (XML) Partial in future

YES


Protection Messaging (GOOSE) - YES

* Not in the standard, but can be implemented

Observation on Service ComparisonObservation on Service Comparison

IEC61850 does have more services and options most notably:IEC61850 does have more services and options most notably:Buffered reportingGOOSE (multi-cast protection messaging)Object Discovery Servicesj ySubstation Configuration LanguageSampled values for a process bus

B th DNP3 d IEC61850 id ffi i t i fBoth DNP3 and IEC61850 provide sufficient services for many applications.


Object Model Similarities

Both support discrete, digital, analog, counter, and floating point data types.

B th t d fi d lit flBoth support pre-defined quality flags

Both support time stamped data.


Object Models: DNP3

DNP3 Objects are described by:Object #: 1=Binary Input Static, 2=Binary Input Event, etc.

Variation #: 1=With status, 2 = without status, etc.

Index #: Refers to a specific instance of an object.


Object Models: IEC 61850IED:Relay1/MMXU1.MX.A IED:Relay1/XCBR2.CO.Pos

Current Breaker

A PhV A PhV Pos Pos

CurrentMeasurements


MXMeasurements

AAmps

PhVVolts

DCDescriptions

AAmps

PhVVolts

Logical Nodes

STStatus

PosPosition

COControls

PosPosition





System Context


(e.g. Relay1)


Names v.s. Indexes

Names convey context and meaning improving understanding and reducing configuration.

N d b d idth t i tNames need more bandwidth to communicate.


Conclusions

Both can be optimal for a given application depending on the requirements.

Both can be applied successfully in sub-optimal applications.

Using one does not preclude the use of the other.

Both can easily co-exist, AND PROBABLY SHOULD.



Benefits of IEC 61850


L SCADA Vi f D tLegacy SCADA View of Data

Flat set f t

Applications

of tags Applications Access Data by Tag

Device Addressing or SCADA Tag Data Base


Legacy View of Data

Proprietary tag formats.

Arcane addressing:DriverWireRackDevice Register/Index #Network

Manually entered.

Manually verified.

Applications tied to tag or free form alias.

Any user tag conventions are proprietary.


Typical Legacy Protocol Data ModelIt is in:

Obj t #6Object #6,Variation #2,

Index #27

That’s intuitive?

I d h Ph A lI need the Phase A voltage for the 345KV primary feeder

NO POWER SYSTEM CONTEXT


Device NO POWER SYSTEM CONTEXT FOR DATA ACCESS

Legacy Object MappingLegacy Object Mapping

Legacy data objects must be manually mapped to power system for each different device, application, and vendor.

P S t F tiLegacy Device

Power System Functions

Phase A Voltage

Phase B VoltageMeasurements

R400040

R400041

R400042

R400043Phase B Voltage

Phase C Voltage

Local/Remote Status

Breaker Position

Blocked Open

Measurements

Controls

R400044

R400045

R400046

R400047Blocked Open

Activate Phase A

Activate Phase B

Activate Phase C

Protection

R400048

R400049

R40004A

R40004B


Behavior Modeling

Assume Index #25 is always used to store breaker status.Does 1 mean open or closed?Can I write this object to operate the breaker?Where is the select?Is it selected?

Even if every device used Index #25 to hold breaker status this stillEven if every device used Index #25 to hold breaker status this still isn’t enough to provide end-to-end integration.


A New Approach Needed

For protocols to provide interoperability at the system level they need to:

Specify the bytes/format of the data on the wire

Specify the meaning of data

Specify the behavior of the data


IEC61850 is DifferentIEC61850 is an object oriented substation automation standard that defines:

Standardized names

Standardized meaning of data

Standardized abstract services

Standardized device behavior models

Standardized mapping of services to protocols for:ControlSCADASCADAProtectionTransducers

Self-describing devices

Common configuration language


Anatomy of an IEC61850 Object Model

IED:Relay1/MMXU1.MX.A IED:Relay1/XCBR2.CO.PosCurrent Breaker

A PhV A PhV Pos Pos

CurrentMeasurements


MXMeasurements

AAmps

PhVVolts

DCDescriptions

AAmps

PhVVolts

Logical Nodes

STStatus

PosPosition

COControls

PosPosition





System Context


(e.g. Relay1)


B d Y

IEC61850 View of Devices

B d X Brand YBrand XIOC Relay Diff Relay

PIOC MeasurementsMMXU1 PDIF Measurements

MMXU1

ST DC DC MX

PhV PhV

ST DC DC MX

PhV PhV

MMXU1 MX PhV

Mod Mod PhV PhV Mod Mod PhV PhV


MMXU1.MX.PhVIEC61850 Name for Phase-to-Ground Voltage Measurements

IEC 61850 Object Mapping

NO MANUAL MAPPING NEEDED: IEC61850 objects already portray the power system context.

IEC61850 D iIEC61850 Device

LD

MMXU1

MX.A.PhsA.cVal.mag.f

MX A PhsB cVal mag fMMXU1

XCBR1

MX.A.PhsB.cVal.mag.f

MX.A.PhsC.cVal.mag.f

ST.Loc.stVal

ST.Pos.stVal

ST BlkOpn stVal

PIOC1

ST.BlkOpn.stVal

ST.Op.phsA

ST.Op.phsB

ST.Op.phsC


IEC618 0 Vi f D iIEC61850 View of Devices

Only network addressing requires configuration in the remote client.

Point names portray the meaning and hierarchy of the data with no mapping to I/O required.

Point names can be retrieved from the device automatically without manual intervention or imported via SCL file.

All devices share a common naming convention.


S b i C fi i L (SCL)Substation Configuration Language (SCL) (IEC 61850-6-1)

SCL – Substation Configuration Language a standardized method of describing

Substation power systemsD i fi tiDevice configuration

SCL can be used to unambiguously describe user requirements for systems and devicessystems and devices.

SCL can be used to configure applications without connecting to devicesdevices.

SCL enables third party tools for configuration promoting choice and flexibility


flexibility.

B fitBenefitsReduced configuration costs:

Eliminates most manual configuration via automatic point name retrieval fromEliminates most manual configuration via automatic point name retrieval from devices

Common naming and object models eliminates ambiguity and manual mapping of data points.

Equipment migrations occur with minimal impact on applications.

Application changes have minimal effect on devices, network or other applications.

Users can specify equipment more precisely eliminating delays and costly rework.

Adoption of IEC 1850 in the engineering process can significantly reduceAdoption of IEC 1850 in the engineering process can significantly reduce the effort to design, test, and deploy substations.



IEC61850 SummaryIEC61850 Summary


IEC61850 Substation Architecture

GOOSE multicast and TCP/IP client/server communications

Station Bus 10/100/1000 MB Ethernet

Relay Relay Relay

Process Bus

RemoteAccess

RemoteAccess

IED IED IED

.1/1/10GBEthernet

Network.1/1/10GBEthernet

Network

MU MU MUClk1 Clk2MU MU MUClk1 Clk2


PT1 OpticalCT

PT2 CT2 OpticalPT

OpticalCT

I/O I/O I/O

MU = Merging Unit

PT2 CT2 OpticalPT

OpticalCT

I/O I/O

IEC 61850 Profiles

Today: SNTPToday: SNTPFuture:

IEEE 1588


Two Party Application Association – Client/Server

Used for read/write, reporting, controls (SBO), configuration, SCADA, etc.

Client Client Client

Maximum

SERVER

# of TPAASupported


From IEC61850-7-2

Multi-Cast Application Association

Generic Object Oriented Substation Event (GOOSE) is used to transmit a data set of

“Subscribing”

Generic Object Oriented Substation Event (GOOSE) is used to transmit a data set of status values to other relays for high-speed data exchange for protection messaging

Application

A DB

Network

A B C C DB 2 MCAAs

“Publishing”SERVER



1 Service Access Point


Service: send Data (unconfirmed)

Redundant Port ImplementationsRedundant Port: 2 independent Ethernet ports with 2 different addresses

Redundant Port Implementations

addresses

Ethernet1 Ethernet2 MAC – 2IP Addr - 2

MAC – 1IP Addr - 1

Redundant Media: 1 Ethernet port with switched media

EthernetMAC – 1 Ethernet

Switches on loss of Ethernet link pulses

IP Addr - 1

p

Primary Back-Up


Redundant Media is Common - Easy to Configure for Redundancy

Redundant Network ConfigurationRedundant Network Configuration

Ethernet Switch Ethernet Switch Ethernet Switch

Ethernet Card

WAN WAN

Recent work involves putting 2 port switches in the devices to form a


Recent work involves putting 2-port switches in the devices to form a ring for redundancy without switches

VLANsVLANs: Are logical groupings of nodes that reside in a common broadcast domain

Virtual because the VLAN is artificially created and the nodes need not be

VLANs

Virtual because the VLAN is artificially created and the nodes need not be physically located on the same switch or even reside in the same building, but

Nodes that are members behave like they are connected together by one layer 2 bridge or switchA router is required to communicate between the two VLANs

E F GSegment 1

AB C

D

G


VLAN 2 = Multicast domain ABEVLAN 3 = Multicast domain CDFG

Ethernet PriorityEthernet 802.1q provides a priority setting“High” priority messages are moved to the priority queueS ifi d i IEC GOOSE d I l t d i it h

Ethernet Priority

Msg 1

Specified in IEC GOOSE and Implemented in switches

Ethernet Switch Port 5 Port 6NewMsg 1Msg 2Msg 3Msg 4

Msg 1Msg 2Msg 3

New

g

Port 1 Port 2 Port 3 Port 4

gMsg 4

New New “high priority” message for Port 6Courtesty of GE Multilin


Courtesty of GE Multilin

IEC61850 St d dIEC61850 Standard

Basic principles Part 1

Glossary Part 2

General Requirements Part 3

System and project management Part 4

Communication requirements Part 5

Substation Automation System Configuration Part 6Substation Automation System Configuration Part 6

Basic Communication Structure Part 7

Sampled ValuesMapping to Part 9

Sampled ValuesPart 8

Conformance testing Part 10

Mapping to Ethernet

pp gMMS and Ethernet


g

IEC61850 L d St d dIEC61850 – Layered Standard

Device Object Models - IEC61850-7-3, 7-4

Device Model Data Objects Data Types Naming Conventions

Abstract Service Model - IEC61850-7-2Abs

tract

Associate Reporting Self-Description Control Data Set Logs

M A P P I N G

Mapping to MMS Protocol - IEC61850-8-1

Initiate InfoReport GetNameList Write VariableList Journalsal

Communication Stack Profiles

ISO/OSI protocol stack TCP / IP protocol stack

Initiate InfoReport. GetNameList Write VariableList Journals

Re


IEC61850 Vi t l M d lIEC61850 Virtual Model


From IEC61850-7-1

IEC61850 Class Model in UML

Obj tN

Name SERVER Contains LDs and filesObjectNameObjectReference

LOGICAL-DEVICE(LD)

1

1..*“Containment Heirarchy”

Inheritance

(LD)

LOGICAL-NODE(LN)

1

3..*

Contains all other objects(LN)

DATA

1

1..*

j

DataAttribute

1

1..*

© Copyright 2010 SISCO, Inc.70 UML – Unified Modeling Language

Logical Device StructureIEC61850 Clients

IEC61850 Server Physical DeviceClient

LogicalDevice

LogicalDevice1 to N Logical Devices

ClientFunctions

LogicalNode

LogicalNode

Data Data Data Data

LogicalNode

LogicalNode

Data Data Data Data

. . . . . .

… …Data Data Data Data Data Data Data Data

Communications Driver

… … … …

Process Bus


Legacy DeviceField Signals

Logical Node

A named grouping of data and associated services that is logically related to some

power system function.


Circuit

Examples of Logical Nodes

Breaker

Current T f

Switch Controller

Transformer

Voltage Transformer


Common Data Classes (CDC)

Defines structure for common types that are used to describe data objects.

CDC l bj t b ilt d fi d i l b tCDC are complex objects built on predefined simple base types organized into functional constraints (FC)

Examples:pSingle point status (SPS) – on/offDouble point status (DPS) – on/off/transient


IEC 61850 TimeStamp Format

4 Bytes = Second Of Century (SOC) Starting January 1, 1970Based on the Network Time Protocol (NTP) standardThere are 31,536,000 seconds/year (non-leap)4 bytes = 4 294 967 296 counts do not wrap for 136 years or 21064 bytes = 4, 294,967,296 counts do not wrap for 136 years or 2106

3 Bytes = Fraction of Second16,777,216 countsabout 60nsec potential resolutionabout 60nsec potential resolution

1 Byte = Quality1 bit : Leap Seconds not known1 bit Cl k F il1 bit : Clock Failure1 bit : Loss of Synchronization5 bits: Number of significant bits in Fraction of Second (N)


IEC 61850 QualityIEC 61850 Quality13 bit Bit-String, typically stored in a 16-bit integerMSB LSB

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

OperatorBlocked

Inaccurate

Source = 0 Process= 1 Substituted

Test

p

OscillatoryFailure

OldDataInconsistent

Inaccurate

00 Good01 Invalid10 Reserved11 Q ti bl

OverflowOutofRange

BadReferencey


11 Questionable

Common Data Classes

Name DescriptionSPS Single Point Status

DPS Double Point Status

INS Integer Status

ACT Protection Activation

ACD Directional Protection Activation Info.

SEC Security Violation Counting

BCR Binary Counter Reading

MV Measured Value

CMV Complex Measured Value

SAV Sampled Value

WYE Phase to ground measured values for 3-phase system

DEL Phase to phase measured values for 3-phase systemDEL Phase to phase measured values for 3 phase system

SEQ Sequence

HMV Harmonic value

HWYE Harmonic value for WYE


HDEL Harmonic value for DEL

Common Data ClassesCommon Data Classes

Name DescriptionSPC Controllable Single Pointg

DPC Controllable Double Point

INC Controllable Integer Status

BSC Binary Controlled Step Position Info.

ISC Integer Controlled Step Position Info.

APC Controllable Analogue Set Point Info.

SPG Single Point Setting

ING Integer Status Setting

ASG Analogue Setting

CURVE Setting Curve

DPL Device Name Plate

LPL Logical Node Name Plate

CSD Curve Shape Description


F ti l C t i tFunctional Constraints

Th d t tt ib t i bj t lik b k th t hThere are many data attributes in an object like a breaker that have related use

Control, configuration, measurement, reporting, etc.

Functional Constraints (FC) is a property of a data attribute that characterizes the specific use of the attribute.

Useful to functionally organize the data attributes to provide structure and context.


Functional ConstraintsFunctional Constraints

FC Name DescriptionST Status Information

MX Measurands (analog values)MX Measurands (analog values)

CO Control

SP Set point

SV Substituted Values

CF Configuration

DC Description

SG Setting Group

SE Setting Group Editable

EX Extended Definition (naming – read only)

BR Buffered Report

RP Unbuffered Report

LG LoggingLG Logging

GO GOOSE Control

MS Multicast Sampled Value (9-2)

US Unicast Sampled Value (9-1)

XX U d ild d i ACSI


XX Used as wild card in ACSI

Single Point Status (SPS)Single Point Status (SPS)

From IEC61850-7-3

AttributeName

per clause 8f IEC61850 7 3

Type Functional Constraint

Mandatory/OptionalReport

Trigger


of IEC61850-7-3 Constraint Range ofValues

TriggerOptions

Logical Node Name Plate - LPL

From IEC61850-7-3


Device Name Plate - DPL

From IEC61850-7-3From IEC61850 7 3


Double Point Status (DPS)Double Point Status (DPS)

From IEC61850-7-3


2-bit pair in DPS versus boolean in SPS

Integer Status - INS

From IEC61850-7-3


Controllable Double PointControllable Double Point

Mandatory ifFrom IEC61850-7-3

Mandatory if control is supported

Optional if control is supported


Logical Node

A named grouping of data and associated services that is logically related to some

power system function.


IEC61850 Logical Node GroupsIEC61850 Logical Node GroupsName Description

Axxx Automatic Control (4)Cxxx Supervisory Control (5). p y ( )Gxxx Generic Functions (3). Ixxx Interfacing/Archiving (4). Lxxx System Logical Nodes (2). Mxxx Metering & Measurement (8). g ( )Pxxx Protection (28). Rxxx Protection Related (10). Sxxx Sensors, Monitoring (4). Txxx Instrument Transformer (2). Xxxx Switchgear (2). Yxxx Power Transformer (4). Zxxx Other Equipment (15). Wxxx Wind (Set aside for other standards)Oxxx Solar (Set aside for other standards)Hxxx Hydropower (Set aside for other standards)Nxxx Power Plant (Set aside for other standards)Bxxx Battery (Set aside for other standards)


Fxxx Fuel Cells (Set aside for other standards)

System Logical Nodes

Name Description

LPHD Physical Device

LLNO Common Logical Node MANDATORY


Automatic Control Logical Nodes

Name Description

ANCR Neutral Current Regulator

ARCO Reactive Power ControlARCO Reactive Power Control

ATCC Automatic Tap Changer controller

AVCO Voltage Control


Supervisory Control Logical Nodes

Name Description

CALH Alarm HandlingCALH Alarm Handling

CCGR Cooling Group Control

CILO Interlocking

CPOW Point-on-wave switchingC O o o a e s c g

CSWI Switch Controller


Generic Function Logical Nodes

Name Description

GAPC Generic Automatic Process Control

GGIO Generic Process I/O

GSAL Generic Security Application


Interfacing and Archiving Logical Nodes

Name Description

IARC Archiving

IHMI Human Machine Interface

ITCI Telecontrol Interface

ITMI Telemonitoring InterfaceITMI Telemonitoring Interface


Metering and Measurement Logical Nodes

Name Description

MDIF Differential measurements

MHAI Harmonics or interharmonics

MHAN Non phase related harmonics or interharmonics

MMTR Metering

MMXN Non phase related measurements

MMXU Measurements

MSQI Sequence and Imbalance

MSTA Metering Statistics


Protection Logical NodesProtection Logical Nodes

Name DescriptionPDIF Differential

PDIR Direction

PDIS Distance

PDOP Directional overpowerPDOP Directional overpower

PDUP Directional underpower

PFRC Rate of change of frequency

PHAR Harmonic restraintPHAR Harmonic restraint

PHIZ Ground detector

PIOC Instantaneous overcurrent

PMRI Motor restart inhibition

PMSS Motor starting time supervision

POPF Over power factor

PPAM Phase angle measuring


Protection Logical Nodes (cont’d)

Name DescriptionPSCH Protection scheme

PSDE Sensitive directional earth fault

PTEF Transient earth fault

PTOC Ti tPTOC Time over current

PTOF Over frequency

PTOV Over voltage

PTRC Protection trip conditioningPTRC Protection trip conditioning

PTTR Thermal overload

PTUC Under current

PTUV Under voltagePTUV Under voltage

PVOC Voltage controlled time over current

PVPH Volts per Hz

PZSU Zero speed or under speed


Protection Related Logical Nodes

Name Description

RDRE Disturbance recorder function

RADR Disturbance recorder channel analogue

RBDR Disturbance recorder channel binaryRBDR Disturbance recorder channel binary

RDRS Disturbance record handling

RBRF Breaker failure

RDIR Directional element

RFLO Fault locator

RPSB Power swing detection/blocking

RREC Auto reclosing

RSYN Synchronism-check or synchronising


y y g

Sensors and Monitoring Logical Nodes

Name Description

SARC Monitoring and diagnostics for arcs

SIMG Insulation medium supervision

SIML Insulation medium supervision (liquid)

SPDC Monitoring and diag. for partial discharges


Instrument Transformer Logical Nodes

Name Description

TCTR Current transformerTCTR Current transformer

TVTR Voltage transformer


Switchgear Logical Nodes

Name Description

XCBR Circuit Breaker

XSWI Circuit SwitchXSWI Circuit Switch


Power Transformer Logical Nodes

Name Description

YEFN Earth fault neutralizer

YLTC Tap changer

YPSH Power shunt

YPTR Power transformer


Other Power System Equipment Logical Nodes

Name DescriptionZAXN Auxiliary networky

ZBAT Battery

ZBSH Bushing

ZCAB Power cable

ZCAP Capacitor Bank

ZCON Converter

ZGEN Generator

ZGIL Gas insulated lineZGIL Gas insulated line

ZLIN Power overhead line

ZMOT Motor

ZREA Reactor

ZRRC Rotating reactive component

ZSAR Surge arrestor

ZTCF Thyristor controlled frequency converter


ZTCR Thyristor controlled reactive component

Logical Node NamesLogical Node NamesExample for Breaker:

ddd XCBR01Logical Node Instance #

Logical Node Name perIEC 61850-7-4 (circuit breaker)

Optional Application Specific Prefix

prefi digits + instance digits ≤ 7


prefix digits + instance digits ≤ 7

L i l N d ClLogical Node ClassesLN

InheritedRelationships

LPHD Common LN

LLN0 Domain Specific An IEC 61850 device must contain LPHDLNs (i.e. XCBR) must contain LPHD, LLN0, and 1 or more domain specific logical nodes.


Common Logical Node ClassCommon Logical Node Class

From IEC61850-7-4

ALL other logical nodes contain these attributes even though they are t li t d i th th l i l d d i ti t bl


not listed in the other logical node description tables.


From IEC61850-7-4

NamPlt is mandatory and contains the nameplate for the individual logical node


NamPlt is mandatory and contains the nameplate for the individual logical node


From IEC61850-7-4

If the logical node is logically connected to some external equipment (e.g. breaker controller or server is a proxy, etc.) then EEName can contain the nameplate for that e ternal de ice


contain the nameplate for that external device.

LLN0 Containment

ContainmentRelationshipRelationship

InheritedRelationship


From IEC61850-7-2

Logical Node Description - XCBRg p

From IEC61850 7 4

SPS

From IEC61850-7-4

Loc

From IEC61850-7-4


Data Object NamesCommon Data Class

Mandatory/Optional

Description

Single Point Status (SPS) CDCSingle Point Status (SPS) CDC(e.g. loc)

stVal

From IEC61850-7-3

Data Attrib te Names


Data Attribute NamesData Type of Attribute

Object Name for Local/Remote Attribute of XCBR1

XCBR1.ST.Loc.stVal

Attribute

L i l N dFunctional Constraint

Data

Logical Node


Mapping of Names via 8-1

Section 8-1 maps the IEC61850 LN and Data Object Names to MMS (ISO9506)

MMS allows only numbers, letters, “$”, and “_” in object names.

Resulting MMS Object Name:

XCBR1$ST$Loc$stValXCBR1$ST$Loc$stVal


Alternate Object Name Used

XCBR1.Loc.stVal[ST]

FunctionalConstraint

L i l N d

ConstraintData

Attribute

Logical Node


Breaker PositionBreaker Position

From IEC61850-7-4

DPCPos

From IEC61850-7-4


Breaker Position – DPC ClassBreaker Position DPC Class

From IEC61850-7-3

stVal


Object Name for Breaker Position Attribute of XCBR1

XCBR1.ST.Pos.stVal

Attribute

L i l N dFunctional Constraint

Data

Logical Node



Report Model


ReportingReporting

Unbuffered Reporting allows clients to receive data from theUnbuffered Reporting allows clients to receive data from the server without polling.

If network connection (association) between client and server is lost, data is lost.

Buffered Reporting enables the server to retain data if associations are lost enabling the client to retrieve ALL data.

Reports are sent using the MMS InformationReportFunctionally equivalent to sending a Read response without the client having issued a Read request.g q


Report-Log ModelReport Log Model

F IEC61850 7 2


From IEC61850-7-2

Report Control Block AttributespAttribute Name DescriptionRptID Name assigned to this RCBRptEna = 1 Reports enabled, = 0 Reports disabledResv = 1 In-use by client, =0 AvailableDatSet Name of the DATA SET referenceDatSet Name of the DATA-SET referenceConfRev Configuration Revision Number (can track Data Set changes)

OptFlds Optional Fields to Include in the Reportsequence-number Include the sequence numberreport-time-stamp Include a report time stamp (even if DATA is time stamped)

reason-for-inclusion The reason the report was sent (dchg qchg etc )reason-for-inclusion The reason the report was sent (dchg, qchg, etc.)data-set-name Include the DATA-SET name in the reportdata-reference Include the names of the DATA elements in the reportbuffer-overflow Include buffer status in report (buffered only)

entry-ID Include the entry ID in the report (buffered only)conf-revision Include the current value of the ConfRev in the reportp

BufTim Buffer Time (the fastest that reports will be sent)SqNum Sequence NumberTrgOp Trigger Conditions

data-change Send report on data change exceeding deadbandquality-change Send report on change in quality

integrity Send report on integrity period expirationgeneral-interrogation Send report when requested

IntPd Integrity PeriodGI General InterrogationPurgeBuf Purge the report buffer (buffered only)


EntryID Start reporting from a specific entry in the buffer (buffered only)TimeOfEntry Start reporting from a specific entry time (buffered only)

Buffered Reporting with GI ExampleBuffered Reporting with GI Example

SqNum = 01, data change, <data>

SqNum = 02 data change <data>

Client enables BRCB

report

report SqNum = 02, data change, <data>

SqNum = 03, integrity, <data>



p

report

report

report

time

q , g ,


IEC 61850Client

reportCommunications Terminated

Communications Reestablished – Client Re-Enables the BRCB

Cli t t G l I t ti t



S N 09 i t it d t

Client request General-Interrogation

report

report



SqNum = 12 data change <data>

report

report

report

report

SqNum = 10, general-interrogation, <data>


SqNum = 12, data change, <data> report

SqNum = 10 flags when the GI was issued by the client to identify data that was reported while disconnected.


Controls


Control Model Objects

Enables control of ACSI Objects:Controllable Single Point (SPC)

Controllable Double Point (DPC)( )

Controllable Integer Status (INC)

Binary Controlled Step Position (BSC)

Integer Controlled Step Position (ISC)Integer Controlled Step Position (ISC)

Controllable Analog Set Point (APC)


Control Model (ctlModel)

0: Status only. No control allowed.

1: Direct control with normal security (direct-operate)

2: SBO control with normal security (operate-once or operate-many)

3: Direct control with enhanced security (direct-operate)y ( p )

4: SBO control with enhanced security (operate-once or operate-many)


Direct Control with Normal Security

From IEC61850-7-2


SBO Control with Enhanced SecuritySBO Control with Enhanced Security

Report_req(int)


From IEC61850-7-2(modified)


Setting Groups


Setting Groups

Settings group is a logical element that is associated to all the settings in all the logical nodes within a logical device.

A tti i f d t b b 1 h i th b fA setting group is referred to by a number 1….n where n is the number of setting groups supported.

IEC 61850 clients use setting group control blocks (SGCB) to access and g g p ( )manipulate the settings.

2 groups of settings:S tti G (SG) th t b l t d th ti ttiSetting Groups (SG) that can be selected as the active setting group

Editable Setting Groups (SE) that can be selected and manipulated for editing.



Relay to Relay Applications

GOOSE Protection Messaging


GOOSE Protection Messaginga.k.a. “Peer-to-Peer messaging” (misnomer – Multicast messaging)

Legacy Hardwired ArchitectureLegacy Hardwired Architecture

Breaker

Relay 2

Relay 1Breaker Relay 3 Breaker

1

5

2

Relay 1Breaker Relay 3 Breaker

4 3

6

Relay 4

Hardwired signals for relay to relay links


Breaker

Legacy Architecture

Requires N*(N-1)/2 links for N relays.

Requires filtering on links to prevent false trips.

Reprogramming can require rewiring.

Don’t know if links are working until you use them.


IEC61850 Network Architecture

Network – Multicast Communications

GOOSE

Relay 1 Relay 2 Relay 3 Relay 4

GOOS

Breaker Breaker Breaker Breaker

GOOSE - Generic Object Oriented Substation Event (data sets)


R l h t k ki hi ti t d t ti

IEC61850 Network Architecture

Relays share a common network making sophisticated protection schemes possible even across very large distances.

Number of links for N relays is N and shared with SCADA.

Relays send their status to all other relays at once using GOOSERelays send their status to all other relays at once using GOOSE.

Status exchanged continuously.

Messages contain “Time Allowed to Live” parameter to detect missing messages


messages.

GOOSE Traffic

Each line below represents a GOOSE message

St t 2 S 0State = 1, Seq = 0State = 1, Seq = 6

State = 2, Seq = 0

tEvent at t=0 Hold time increases from until

steady state of 1/min is reached


steady state of ~1/min is reachedState change occurs

BenefitsReduction of wiring costs

More flexible programming is independent of wiring

Reliability: Link status known before use.

New capabilities not cost-effective with hardwired systems.

Higher performance with more data ~ 3ms for hundreds of points


Improved Performance

Network access resolves very fastNetwork access resolves very fast

Duplex Ethernet switches NO collisions

Data is transmitted multiple times to avoid missing data.

Digital error checking instead of analog filtering.

Use of IEEE 802.1p with Virtual LAN (VLAN) for segmenting and priority tag processing by network switches.


GOOSE Wide Area Application

Wide Area Network

Substation-to-SubstationIEC 61850 90 1

Application of VLAN and priority critical


IEC 61850-90-1


Transducer Interfaces

Process Bus for transmitting sampled values


IEC61850 Substation Architecture

GOOSE multicast and TCP/IP client/server communications

Station Bus 10/100/1000 MB Ethernet

Relay Relay RelayRelay(s) Subscribe to Datasets

Process Bus

RemoteAccess

Relay(s) Subscribe to Datasets

RemoteAccess

IED IED IED

MU Publishes V/I/Status Datasets

.1/1/10GBEthernet

NetworkMU Publishes V/I/Status Datasets

.1/1/10GBEthernet

Network

MU MU MUClk1 Clk2MU MU MUClk1 Clk2


PT1 OpticalCT

PT2 CT2 OpticalPT

OpticalCT

I/O I/O I/O

MU = Merging Unit

PT2 CT2 OpticalPT

OpticalCT

I/O I/O

Legacy Approach

Protection BayRelay Controller

A/D A/D A/D A/DInput InputB k

Voltagesand

currents

Voltagesand

currentsBreakerStatus

BreakerStatus


Legacy Approach

Individually and redundantly wired to all devices needing the same signals:CTsPTsStatus InputsOutputsp

Each individual sensor must be calibrated and maintained separately.

Incremental cost is exponential (signals x devices)

Result is minimization of I/O

Analog signal wiring constraints


IEC61850 Process BusIEC61850 Process BusBay

ControllerProtection

RelayFault

RecorderRTU

y

Ethernet Ethernet Ethernet Ethernet

9-2 Process Bus

Ethernet

Merging UnitA/D A/D Input

Voltagesand

currents

BreakerStatus


IEC61850-9-2 Process Bus

Transducer and I/O signals are shared via a network.

Only one transducer or I/O point per signalOnly one transducer or I/O point per signal.

Minimization of calibration and maintenance.

Incremental cost is linear (signals only)

CT/PT signals can be sent across long distances


What is a bus?What is a bus?Bay

ControllerProtection

RelayFault

RecorderRTU,etc.y

Ethernet Ethernet Ethernet Ethernet

9-2 Process Bus

Ethernet

Merging UnitA/D A/D Input

Voltagesand

currents

BreakerStatus


What is a Bus?What is a Bus?


Merging UnitA/D A/D I t

Ethernet

A/D A/D Input

Voltagesand

currents

BreakerStatus


What is a Bus?What is a Bus?


Process Bus

Merging UnitA/D A/D I t

Ethernet

A/D A/D Input

Voltagesand

currents

BreakerStatus


New Development in Process Bus point to point!?New Development in Process Bus – point-to-point!?

Fiber Patch Panel

Merging Unit or “brick”

A/D A/D I t

Fiber Optic Connector

A/D A/D Input

Voltagesand

currents

BreakerStatus



Substation Configuration Language

SCLIEC61850-6


IEC61850-6

SCL Substation Configuration LanguageSCL – Substation Configuration LanguageIEC61850-6-1

Description language for communication in electrical substations related to the IEDs.

XML based language that allows a formal description ofSubstation automation system and the switchyard and the relationSubstation automation system and the switchyard and the relation between themIED configurationSupport for private extensions


SCL Fil TSCL File TypesSSD: System Specification Description.

XML description of the entire system.

SCD: Substation Configuration Description. g p

XML description of a single substation.

CID: Configured IED Description. XML configuration for a specific IED.

ICD: IED Capability Description. XML description of what is supported by an IED (required for servers).


SCL Files

SSD File – Entire Systemy

SCD File #1Single Substation

SCD File #2Single Substation

Substation #1 Substation #n

…CID File forIED #1

CID File forIED #2

CID File forIED #1

CID File forIED #2IED #1 IED #2

… …

CID File forIED #n-1

CID File forIED #n

CID File forIED #n-1

CID File forIED #n


ICD versus CID FilesCID File = Subset of ICD File A t ll U d + S b t tiActually Used + Substation Specific Configuration Info.

Subset:ICD File – What an IED is capable of

Not all logical nodes, control blocks, I/O, etc. supported by the device are used in a system.

CID – Configuration for a specific IED

Substation Configuration Info:

Report control block

Substation specific

configuration information

presetsStatic values for location, and other descriptions.


SCL Driven Naming


Logical Device and LN Naming = IEDName


E l SCL B d O Li DiExample SCL Based One-Line Diagram

Logical Node Designators


Example of SCL

SISCO IED For Demo


SCL Applications

For users to specify IED requirements.

For vendors to specify IED capabilities.

Configure IEC61850 clients w/o IEDs.

Extract IED configuration from power system design tools.g p y g

Export IED configuration to power system design tools and other applications.



A Shameless PlugA Shameless Plug

UCA International Users Group


Users Group for IEC Standards

C GUCA International Users Group

Advancing Interoperability for the Utility Enterprise

A non-profit users group


http://www.ucaiug.org

UCA International Users Group

Certification of test procedures and systemsCertification of test procedures and systems

Educational seminars and conferencesEducational seminars and conferences

Help desk for user assistance

G h i i f d d kGathering input for standards work

Promotional activities


Why Join?

Support rigorous testing that will lower your cost of ownership.

Participate in the standards process without the cost of attending IECParticipate in the standards process without the cost of attending IEC meetings.

Access to IEC drafts via Liaison with IEC

Vote on key technical issues important to your organization.

Learn from others through participation.


Who Needs to Join?

Every small utility using IEC61850 should have at least one individual member for access to information.

Every large utility should be a corporate member to participate in and influence the standard and user group processes.



Were you paying attention?

A quick test before discussion


Here’s the Test

Question #1:

The IEC 61850 set of standards specifies which of the following:

A. How data is stored in the memory of a device

B. A configuration language for devices

C. A single protocol for all IED communications

D. An object model for how data in a device relates to the power system

E. Reporting, controls, settings, and protection services and protocols

F. How devices should be tested for conformance

G.How an asset management system should be implemented


Here’s the Test

Question #2

IEC 61850 specifies 2 kinds of reporting. Name them.


Discussion

! !! !

! !zzzzz



Thank You

Ralph MackiewiczSISCO, Inc.6605 19½ Mile Road


6605 19½ Mile RoadSterling Heights, MI 48314-1408 USATel: +1-586-254-0020 x103Fax: +1-586-254-0053Email: [email protected]

2010 Doble Client Conference 1

IEC 61850 Process BusBusiness Case, Implementation, and Testing

Rich HuntGE Digital Energy


Agenda

• Definition of IEC 61850 process bus• The business case for process bus• Considerations for process bus installations• Some thoughts on testing process bus

Definition of IEC 61850 Process Bus


IEC 61850: a definition

IEC 61850 is not a protocol. It is a standard that describes a methodology of designing substations based on required functionality

for operating the power system. 61850 defines the functions, the models, and the

communications protocols required to achieve interoperability. The goal is

“reusable engineering” based on standard, repeatable physical design.


Substation logical interfaces


Process bus definition

• Process bus interfaces:– IF4: CT and VT instantaneous data exchange

(especially samples) between process and bay level– IF5: control-data exchange between process and

bay level• Process bus:

– When “process bus” is discussed, it usually means “sampled values”

– Original concept was to separate process bus and station bus networks due to bandwidth limitations

• May still be a good idea for practical considerations


IEC 61850 9-2

• Part 9-2: Specific Communication Service Mapping (SCSM) – Sampled values over ISO/IEC 8802-3

• Scope of 9-2:– The intent of this SCSM definition is to supplement

IEC 61850-9-1 to include the complete mapping of the sampled value model.

– This part of IEC 61850 applies to electronic current and voltage transformers (ECT and EVT having a digital output), merging units, and intelligent electronic devices for example protection units, bay controllers and meters. Process bus communication structures can be arranged in different ways as described in Annex B and IEC 61850-1.


“Merging Unit”

ANALOGFILTER

A/DCONVERTER

DIGITALFILTER

MAGNITUDEESTIMATOR

INPUTS

Traditional Microprocessor Relay Front End

52

ANALOGFILTER

A/DCONVERTER DSP

INPUTS

Merging Unit

IEC 61850 9-2 SAV

52


IEC 61850 9-2 SAV

TimeDelay

Power system signal

Signal as measured bymerging unit

IEC 61850 9-2 SAV is somenumber of these samples

packaged together


Process bus architecture

52 52 52

Process Bus Ethernet Network

Process Interface Unit:- merging unit(s)- contact I/O


Application needs for process bus

• IEC 61850, and Part 9-2, do not define:– Process bus Ethernet network architecture

• Intentional: this is an application issue– Merging unit sampling rate

• IEC 61850 5 defines 480, 960, 1920 Hz for protection, 1500, 4000, 12000 Hz for metering

– Specific SV data frames– Frequency tracking– Time synchronization method

• Also, the standard does not define “why to use process bus”


The business case for process bus


Financial Performance• Improve T&D capital utilization• Reduced T&D operational & maintenance costsExample

• Leverage highly integrated IEDs for significant savings from reduced wiring costs, number of devices

• Reducing labor required for infrastructure renewal & expansion

• Complete infrastructure projects faster – faster ROI

Optimize shareholder investment

Enterprise Objectives


Changing Market Demands• Customer growth creating increased demand for

energy

• Customers expect more reliable power

• Regulatory compliance influencing operational requirements

Examples• Load growth requires increased capacity• Increased customer sensitivity to service interruptions• ISO’s limiting the length of outages

Higher expectations require improved infrastructure



Workforce Utilization• Manpower is the largest P&C expense for switchyard

expansion or refurbishment• Workforce demographic resulting in a shortage of

skilled labor• Previous advancements in technology have not

addressed workforce efficiencyExample

• Protection & Control material accounts for only 25% of total installed costs

• On-site labor for Protection & Control has changed little in 35 years

Improved workforce utilization



Technical Constraints

Designing-out copper wiring• Maximum pre-connectorization• Early and comprehensive acquisition of signals• Fiber-based signaling• Ruggedness and security paramount• Risk mitigation with built-in redundancy



Ready to use today and future-proof• Accepts reality of substation switchyards

• Open standard – IEC 61850

• Complete, simple and robust architecture

• Does not introduce new problems

• Respects the art of protection and control as practiced today



Labour & work transfer

• Optimum partitioning for multiple suppliers

• Standardization of components and physical interfaces

• Minimum variability of material

• Minimum on-site labour and maximum quality control


Addressing the right problem

• A need for a technological solution that• Aligned with today’s P&C practices• Industry-wide acceptance – IEC 61850• Delivers savings to the customer• Replaces on-site labour with pre-fabricated material• Facilitates transfer of work• Increases key performance indices• Complete and future-proof

Bringing industrial revolution to protection and control field


Process bus

A technical way of providing a mission-critical function of P&C, while meeting a business goal of designing out all copper signaling from a switchyard, to achieve considerable cost savings by simplification of engineering, drafting, construction, commissioning and ownership

•A fit-for-purpose architecture

•Business goal delivered in …… the simplest and safest way

Considerations for process bus installations


System design factors

• Measurement types• Segmentation• Performance• Location• Reliability• Maintainability• Interoperability


Measurement Requirements

• Protection signals– Sampled values, breaker

status, breaker protection control

– Low latency– High determinism– Connection to few devices

• Operations signals– V, I data, equipment

status, equipment control– High reliability– Connection to many

devices possible

52

4 control points2 status points






XX control pointsYY status points

Protection Measurements (V,I)Protection Status and Control

Operations Measurements (V,I,P,E)Operations Status and Control


Segmentation

52 to relays

as neededfor I/O

PIU: MU and RIO

Allcopperkept inline bay

fiber tocontrolhouse



• How to design the process bus network architecture

• Zone / bay architecture as shown– Supports both point-to-

point connections, and LAN connections

• Station-wide architecture– LAN connections

• Choice is dependent on how many devices need access to data, how they are connected.


Segmentation

Line protection zone

Transformerprotection zone

Lineprotection zone

Zoneoverlap

Zoneoverlap

•Observation: data only needed by 2-3 devices


Performance Requirements

• Synchronization between MUs and IEDs– Zone-based– Station wide– External synchronization source or through the

network• Impact on relay operating speed

– Protection calculations, tripping speed• Time delay relative to conventional devices

– Line differential relaying• Response to lost SV message


Location

RIO RIO

RIO

RIO

RIO

RIO

52

to I/Onetwork

to I/Onetwork

to I/Onetwork

to I/Onetwork

to I/Onetwork

to I/Onetwork

fiber tocontrol house



RIORIO

RIO

RIO

RIO

RIORIO

RIO

RIO

RIO

RIORIO

RIO

RIO

RIO

to relays

• MUs, RIOs, PIUs placed where it makes sense to pick up signals

• Some can be centralized per zone, others may be distributed

• Yard vs. control house– Control house is non-

sensical– Hardened devices for the

yard


Reliability

• Failure modes– Loss of communications– Loss of SV messages– MU / PIU failure– Clock failure– Network equipment failure

• Redundancy– MUs / PIUs – Communications network equipment– IEDs


Maintainability

• Training– New skills (for P&C) for communications equipment,

clock?– Work procedures– Documentation

• Testing – Isolation for testing– Testing tools and procedures

• Operations– Maintenance, replacement on failure

• Expandability / Scalability– Adding additional zones to process bus system


Interoperability

52

Relay BRelay A1 PIU to 2 relays

52

Relay BRelay ADuplicate or Redundant System: Each relay

uses a PIU

52

Relay BRelay A

Redundant Systems: 1 PIU

More likely scenario. If PIU A andRelay A are from the same supplier, isthere any need to interoperate with

equipment from Supplier B?

Option 1 Option 2

Option 3

Option 1 is an unlikely scenario due tosystem availability requirements.

For Option 3, only 1 PIU is required tomaintain availability. The redundant

system uses a different protection system,so a duplicate PIU will have little impact on

protection system availability.

PIU A

PIU B


Interoperability

• Does it matter?– Redundant or duplicate process bus systems reduce the need

for interoperability• Benefits

– Future upgrades, changes to standard PIUs or IEDs, “hot swappable” SV measurements

• Risks– Compatability “glitches” between equipment from different

suppliers– Customer assumes all risk of performance

• Issues– IEDs from one supplier must accept SV data frames from MUs

from a different supplier.• There are 2 different SV profiles currently in use


System Architecture

Physical interface for P&C is always the same: PIU connected to a fiber optic cableCables can be point-to-point that land at patch panels, or LAN that land on switches.

•PIUs •PIUs

Cross-Connect PanelsIEDs, all I/OVia Fiber

Standard Ethernet Connectivity to SCADA & HMI

Outdoor multi-fiber Cables


Architecture comparison

• Switched network– Changes the P&C system into a LAN– Measurement: latency and determinism impacted by network

design– Segmentation: zone based or station-wide– Performance requirements: slower than conventional due to

latency, risk of lost SV messages– Location: PIUs in yard, switches in house– Reliability: function of network design. Redundant networks or

re-configuring ring. Redundant clock sources.– Maintainability: Significant training of P&C personnel on

communications equipment. Isolation for testing a concern. Scalability a factor of network design.

– Interoperability: high degree of interoperability required for successful implementation.


Architecture comparison

• Point-to-point network– P&C system still a P&C system– Measurement: low latency and highly deterministic– Segmentation: zone based– Performance requirements: comparable to

conventional. Little risk of lost SV messages.– Location: PIUs in yard, no other devices– Reliability: Based on simple redundancy/duplication– Maintainability: No training or special knowledge.

Components easily replaceable. Simple isolation for test. Scalable.

– Interoperability: no special requirements.


Some thoughts on testing process bus


Reasons for Testing

• Verify that the protection and control systems are capable of correctly performing their intended functions:

• When initially placed in service (commissioned)• When modifications are made

- Firmware updates- Minor setting changes- Component replacements- System reconfiguration

• Periodically (to detect hidden failures)• Troubleshooting


Conventional Protection

Test Switches


Process Bus Protection

Protected Transformer

High sidePIUs

Low side

PIUs


P&C System Testing - Overview

Interconnections

Primary Equipment

Relay

Process Bus Methodology

TraditionalMethodology

TestsZone of Verification

• hardware, including I/O• firmware• settings

• isolate relay• secondary ac injection (5A, 115/66.4V)• short contact inputs• monitor output contact continuity

• IT ratios and polarity

• condition sensing contacts

• breaker, disconnect, functionality

• excitation check, ratio check• force primary condition, monitor for continuity• inject command, observe operation

• correct wiring • buzz wiring

• overall functional test

• isolate relay• optical ac injection (sampled values)• optical contact input injection• optical output (GOOSE) monitoring

• excitation check, optical ratio check (sampled values)

• force condition, monitor optical output

• inject optical (GOOSE) command, observe

• check packet S/Ns

• overall functional test


Process Bus System

• Relay


Process Bus System

• Relay

• PIUs and associated

primary equipment


Process Bus System

• Relay

• PIUs and associated primary equipment

• Inter-connections


Overlapping zones:

Process Bus System

• Relay

• PIUs and associated primary equipment

• Interconnections


Relay Testing

• Follow conventional strategy:• Visual inspection • Isolate relay under test• Make any modifications or

repairs required• Inject signals representative of

power system conditions• Verify relay output signals (e.g.

trip) are appropriate• Restore relay to service after

checking that it is safe to do so


872748A1.CDR

Brick tester

PIU/Primary Equipment Testing

• Strategy:

• PIUs lumped with the associated primary equipment

• Equipment terminal points change from copper to fiber, otherwise same strategy as previous practices:

Test from terminal pointsP&C

terminal point


PIU Replacement

• PIU replacements are rare. For maximum worker safety, remove the primary equipment from service.

• Replacement PIU should be pre-tested before installation.

872748A1.CDR

Brick tester


• Inter-connections

PIU/IED Interconnection Testing

Establish that the fibers connect the relays to the correct PIUs, and that path losses leave adequate signal margin

Choice of network architecture determines degree, type of testing required


Test Switches

• Role of test switches:• Isolate the work space for personnel safety • Maintain integrity of current signal paths• Isolate the relay outputs to avoid inadvertent operations• Facilitate secondary injection without affecting other devices• Provide a convenient signal measuring facility


Testing - Summary

• Process Bus is testable using accepted principles– Uses overlapping test zones for full coverage– Some architectures require new worker skills

• Fewer manual tests required– Connectivity of all quantities on a fiber verified with a single test– Switched LAN testing requires more (VLANs, failover,

congestion)• Less prone to human errors

– Test mode blocks and unblocks all relay outputs with a single action

– Self-testing of fiber connections, optical and electronic hardware

– Fewer manual tests required


Testing - Summary

• Enhanced personnel safety– Reduced exposure to hazardous live electrical

circuits (CTs, VTs, battery) • Maintenance and periodic testing requirements relaxed

due to unprecedented self-monitoring– Outage-less routine maintenance – run-to-fail with


Final Thoughts


Control Cables 1

Turn This


Process bus wiring

Into This


Close-up of Relay as Installed

Eight fiber connections, plus station LAN

Five copper connections, plus IRIG-B

And This


Quiz Questions


Quiz Questions

• What are the required number of measurements (currents and voltages), and the required number o measurement samples, in a IEC 61850 9-2 sampled value data set?

• Is a switched network (LAN) architecture required for IEC 61850 process bus communications?

Fi ld l f IEC 61850 l tiLars Frisk, Doble Austin TX, October 10 2010

Field examples of IEC 61850 solutions- What have been done out thereat a e bee do e out t e e

© ABBMonth DD, YYYY | Slide 1

Agenda

BackgroundBackground

Distribution automation - Where can you start

C fTransmission substations - Copper wire, how to get rid of it

Large systems - How to go big

Process bus installations - A highway in your substation

Q&A


Background - why IEC 61850

Driving factors for IEC 61850 solutions

Cost reduction

Smart grid enabling

Future-proofing

Increase reliabilityy

Space saving

Using new technologyUsing new technology


Distribution automation


Distribution automationProtection and control applicationsProtection and control applications

Circuit Breaker Failure Protection (CBFP) trip signal from all outgoing feeders to each corresponding incoming bay

Under voltage and Under frequency trips from bothUnder voltage and Under frequency trips from both Incoming feeders to all outgoing feeders,

Truck positions,Truck positions,

Parallel operation of the power transformers

IED IEDGOOSE


Distribution automationBreaker failure schemeBreaker failure scheme

Relay B (outgoing feeder) detectsOK, I hear you!

I’ll open my Breaker

Relay B (outgoing feeder) detects a fault, issues opening command to the breaker and starts the breaker failure

Relay A The breaker in outgoing feeder fails to open and after a set time delay the breaker failure protection in Relay B sends outprotection in Relay B sends out back-up command as a GOOSE message to Relay A

After receiving the GOOSE

Relay BGOOSE message

After receiving the GOOSE message Relay A issues opening command to the incoming feeder breaker and the fault is cleared.

Activate Breaker

My Breaker is not opening!

© ABBMonth DD, YYYY | Slide 6© ABB Group June 19, 2009 | Slide 6

Activate Breakerfailure scheme

Distribution automation Arc protection using GOOSEArc protection using GOOSE

Both relay A (incoming feeder) and relay B3.

Relay A

Both relay A (incoming feeder) and relay B (outgoing feeder) are equipped with three arc sensors

Relay B detects an arc in the busbar

1.

2.

Relay B detects an arc in the busbar compartment via sensor 1 and sends a related GOOSE message to relay A

Conventional wiring: <37msWith GOOSE: <23ms

2. 1.

With GOOSE: <23ms

After receiving the GOOSE message relay A checks the current level and issues a trip command to breaker A

Relay B

GOOSE message-> GOOSE communication enables fast and station wide supervised arc protection schemes

3.


Distribution automation GOOSE based busbar protectionGOOSE based busbar protection

© ABBMonth DD, YYYY | Slide 8© ABB Group October 24, 2010 | Slide 8

Distribution automation GOOSE based busbar protection

S

GOOSE based busbar protection

GOOSE Message

Ethernet Connection

Substation automation system

X XX

X Up to 128X XX

X

……Up to 128

outgoing feeders


Distribution automation IEC 62271 3 Conformance testing with KEMAIEC 62271-3 Conformance testing with KEMA

Highlights confirmed by KEMA:


Distribution automationSimplifying wiringSimplifying wiring

Use case:UniGear switchgear with 10 baysg y

Load management system, as well as control system interface

~70% of the LV signals are between the relays

Froproteccont

Froother Tom

/ to ction

and rolIED

s

om/ to

rdevices

TotalNumber of IO wires

I t b i lli 104 116 220Intebay signalling 104 116 220

Automation system 85 47 132

Other externals, i.e. loadmanagement system 383 252 635

T t l


Total 572 415 987

Distribution automationLess wiring is moreLess wiring is more

Use case:UniGear switchgear with 10 baysg y

Load management system, as well as control system interface

~70% of the LV signals are between the relays

With GOOSE There’s a great

Froproteccont

Froother T With GOOSE. There s a great

potential to:Simplify

om/ to

ctionand

rolIEDs

om/ to

rdevices

TotalNumber of IO wires

I t b i lli 104 116 220 Make it more flexibleMake it more extendibleMake it more cost-efficient

Intebay signalling 104 116 220

Automation system 85 47 132

Other externals, i.e. loadmanagement system 383 252 635

T t l


Make it more cost efficientMake it more reliable

Total 572 415 987

Power TransmissionSingle lineSingle line

500kV line 1

87B87AA99B

LA99A DFR

30TA

30TB

30TC

87B87A

500kVYARD

LA99B5018

LA52BCALA52BCB 30SHA

30SHB

74DFRX

30TC

30TS

161kV line 1

YARD

161kV 9A99A50285024

30SHB

161kVYARD 9A99BB

9A99A

914 1016 918

LB52BCALB52BCB

L252BCAL252BCB

500kV line2

LB99B

LB99A9A52BCA9A52BCB

C1652BCAC1652BCB

9152BCA9152BCB

1026

SCADA GW C2652BCA


161kV line 2 161 kV line 3

9299B 9B99BA

9299A 9B99ASCADA GW

C2652BCB

Power TransmissionReducing copper wiresReducing copper wires

I/O IEDs in breaker cabinets in switchyardI/O IEDs in breaker cabinets in switchyard

GOOSE from switchyard

Breaker positionBreaker position

MOD position

Breaker alarmsBreaker alarms

GOOSE from P&C building

Breaker commandsBreaker commands

MOD commands

Distributed logic using GOOSEDistributed logic using GOOSE

Interlocking

AR master decision


AR master decision

Power TransmissionNetwork DesignNetwork Design


Power transmissionCompact installationCompact installation

P t ti d t l fProtection and control for

3*161 kV lines3 161 kV lines

2* 500kV lines


Large substation500 kV500 kV

1½ breaker

500kV4 lines

9 breakers9 breakers

4 transformers


Large substations220 kV220 kV

220

500 kV T2

110 kV

500 kV T2

110 kV 110 kV

10 kV 20 kV 10 kV 20 kV 500 kV T3

110 kV 110 kV

10 kV 20 kV 10 kV 20 kV 500 kV T3

Double breaker

18 lines

46 breakers

9 transformers



Double breaker

17 lines

33 breakers

9 transformers


Large substation20 kV20 kV


Large substation! 500 220 110 20 10 kV GIS500-220-110-20-10 kV GIS

500kV 220 kV500kV

10 kV 20 kV 10 kV 20 kV 10 kV 20 kV10 kV 20 kV

220 kV T1 220 kV T3

10 kV

220 kV T1 220 kV T3

220 kV T2 220 kV T4


220 kV T2 220 kV T4

20 kV

Large substation A lot of IEDsA lot of IEDs

Transmission ProtectionTransmission Protection

Line Distance 42 pcs

Line Differential 144 pcsLine Differential 144 pcs

Transformer Diff 34 pcs

B Diff ti l 80Bus Differential 80 pcs

Total 300 pcs

Control

Bay Controller 99 pcs

Distribution P&C

Feeder protection 115 pcs


Large Substation GOOSE usageGOOSE usage

Interlocking prevent e g closing a breaker in to aInterlocking – prevent e.g. closing a breaker in to a grounded bus.

DistributedDistributed

1-out-of-n control – prevent simultaneous operations

Works regardless of operator placeWorks regardless of operator place

Some IEDs do receive GOOSE from up to 25 other IEDs


Large substationHMI’s and GatewaysHMI s and Gateways

Front end communicationFront-end communication

IEC 61850 clients 9pcs

Hot-stand-by base system

Operator workplace 3pc

Relay engineering workplace

…


Large substation How to connect it allHow to connect it all

Redundant bay controllers connected via switch inRedundant bay controllers connected via switch in P&C cabinet to decentralized ring

Both A and B controller connected to the sameBoth A and B controller connected to the same network


Large substationMore connectionsMore connections

A and B protections connected to separate star topologiesA and B protections connected to separate star topologies

Separate networks for different voltage levels


Large substationOperators interface 500 kV partOperators interface 500 kV part


Process busEliminating copper for current and voltageEliminating copper for current and voltage


Process BusInside the Merging unitInside the Merging unit

Merging Unit

LD MU01

CPSCCPSC

CPSCADC

LD MU01…4

LD MU01LD MU01

LD MU01LN ATVTR

LN ATCTRLN ATCTR

IEC61850-9-2 LE


Process BusHow it all is connectedHow it all is connected

C t l CB1

PPS

CPSC

CPSC Merging Unit

Control CB1

CB1

CPSC

CPSC

Merging UnitLine Protection

CPSC Control CB3

CB3

CPSC Merging Unit

Line ProtectionCB2CPSC

CB2


Control CB2

Process BusReactor protection P t ti IEDReactor protection

Merging Unit

Protection IED

CPSCCPSC


Questions“The only stupid question is the one never asked”The only stupid question is the one never asked


Questions for CEU credits

1 What is the meaning of “MU”1. What is the meaning of MU”

a) Metering Unit

b) Measurement Unit

c) Merging Unit

2. Using GOOSE in your SA system can

a) Save space

b) Save time

c) Save cost

d) All of the above


Conclusions

IEC 61850 fits well for different kind of applicationsIEC 61850 fits well for different kind of applications

There are no absolute right and wrongs

SSolutions and concepts depend on requirements

Applications do expand all the time

Thank you for your interest!


basics of iec61850 standard

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