EPRI Guidelines for Implementing Substation Automation Using IEC 61850

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Guidelines for Implementing Substation

Automation Using IEC61850, theInternational Power System InformationModeling Standard

Technical Report


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EPRI Project ManagerL. van der Zel

EPRI 3412 Hillview Avenue, Palo Alto, California 94304 PO Box 10412, Palo Alto, California 94303 USA800.313.3774 650.855.2121 [email protected] www.epri.com

Guidelines for ImplementingSubstation Automation Using

IEC61850, the International PowerSystem Information ModelingStandard

1008688

Final Report, December 2004


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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS ANACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCHINSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THEORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I)WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, ORSIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESSFOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON ORINTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUALPROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'SCIRCUMSTANCE; OR

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER(INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVEHAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOURSELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD,PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.

ORGANIZATION(S) THAT PREPARED THIS DOCUMENT

Utility Consulting International (UCI)

ORDERING INFORMATION

Requests for copies of this report should be directed to EPRI Orders and Conferences, 1355 WillowWay, Suite 278, Concord, CA 94520, (800) 313-3774, press 2 or internally x5379, (925) 609-9169,

(925) 609-1310 (fax).

Electric Power Research Institute and EPRI are registered service marks of the Electric PowerResearch Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric PowerResearch Institute, Inc.

Copyright 2004 Electric Power Research Institute, Inc. All rights reserved.


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CITATIONS

This report was prepared by

Utility Consulting International (UCI)20370 Town Center Lane, Suite 211Cupertino, CA 95014

Principal InvestigatorsF. ClevelandR. Ehlers

This report describes research sponsored by EPRI.

The report is a corporate document that should be cited in the literature in the following manner:

Guidelines for Implementing Substation Automation Using IEC61850,the International PowerSystem Information Modeling Standard, EPRI, Palo Alto, CA: 2004. 1008688.


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PRODUCT DESCRIPTION

This report provides guidelines for substation planners, project managers, substation engineers,information technologists, and substation integrators on informational issues related to substationautomation (SA) when IEC61850 standards are used.

Results and FindingsSubstation automation is far more than just the automation of substation equipment. It is the firststep toward the creation of a highly reliable, self-healing power system that responds rapidly to

real-time events with appropriate actions and that supports the planning and asset managementnecessary for cost-effective operations. Automation does not simply replace manualproceduresit permits the power system to operate in an entirely new way based on accurateinformation provided in a timely manner to the decision-making applications and field devices.

Substation automation would not have been feasible a few years ago. Communicationtechnologies simply were not available to handle the kinds of demands imposed by thecomplexity of SA requirements. However, communication standards have now been developedthat can address many of these demands. In particular, the international power systeminformation modeling standard IEC61850 provides solutions to automation issues using state-of-the-art object-modeling technologies. IEC6185 also provides the key capabilities needed for theincreasingly sophisticated requirements of data management.

Challenges and ObjectivesThis report provides guidelines on the informational issues related to SA in regard to the use ofIEC61850 standards. Substation automation is a new challenge for the utility industry. Theseguidelines provide the overall vision as well as the specific steps that should be taken forsuccessful implementation of this new enabling capability.

The guidelines also build on the work undertaken in E2Is (one of EPRIs family of companies)IntelliGrid Architecture project by using specific examples from SA functions to show how thesefunctional requirements drive the need for the capabilities provided by IEC61850.

This guideline is organized by the different stages of SAplanning, specifying, implementing,deploying, and operations/maintenance. It is expected that most readers will begin with thereport overview and the vision for substation automation (Sections 1 and 2) as an introduction tothe broader issues of power system management, information technologies, and SA. Readers canthen refer to those report sections that meet their specific areas of interest. The document,therefore, is designed so that each section can stand alone.


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Applications, Values, and UseIt is not easy to understand how the various parts of the IEC61850 documents work together.Therefore, this guideline is designed to help the users of SA automation by describing theIEC61850 standards in more user-friendly terms and by identifying the available options forautomation. Even though most users will rely on equipment vendors to implement the actual

IEC61850 standards, it is important to have a basic understanding of the options available and ofhow the various object models work together.

Additional capabilities are being added to the IEC61850 series of standards, includingconfiguration language standards and conformance test planning. When these standards arefinalized, they should be included in future updates to these guidelines.

EPRI PerspectiveOrganizations such as the IEC do excellent work in developing international standards. EPRIplays a key role in translating those standards into understandable language and discussing thedifferent options and issues related to the standards.

E2I sponsored the development of the IntelliGrid Architecture, which defines the strategic visionfor developing the vital communications and information infrastructure required for reliable,efficient, and secure power system operations. E2I recommends international standards and bestpractices to meet those requirements. One of the key recommendations is the use of IEC61850 insubstation automation.

ApproachThese guidelines were developed to describe the overall vision of SA to help ensure that theparadigm shift provided by this new enabling technology is appreciated by the utility industry.The guidelines describe the steps required in each phase of implementation with IEC61850.

KeywordsIEC61850IntelliGrid architectureSubstation automationUtility communications architecture (UCA)


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CONTENTS

1 AN OVERVIEW OF IEC61850 SUBSTATION AUTOMATION GUIDELINES...................... 1-11.1 Identifying the Purpose, Scope, and Audience for IEC61850 Substation

Automation Guidelines.............................................................................................. 1-11.1.1 Purpose............................................................................................................ 1-11.1.2 Scope ............................................................................................................... 1-11.1.3 Audience .......................................................................................................... 1-1

1.2 The Vision for Substation Automation ....................................................................... 1-41.3 Project Management for Substation Automation Projects.......................................... 1-51.4 Developing Functional Requirements for Substation Automation Equipment,

Systems, and Applications........................................................................................ 1-61.5 Specifying Functional Requirements and IEC61850 for Substation Automation ........ 1-71.6 Implementing IEC61850 in Equipment and Systems................................................1-101.7 Installing IEC61850 Equipment and Systems in Substations....................................1-111.8 Key Points................................................................................................................1-11

2THE VISION FOR SUBSTATION AUTOMATION ............................................................... 2-12.1 Purpose and Audience for This Section .................................................................... 2-12.2 Thinking Outside the Box Paradigm Shift of Substation Automation....................... 2-12.3 Enabling Information Technologies That Enhance Substation Automation

Capabilities ............................................................................................................... 2-32.4 The Benefits of Substation Automation for Different Users........................................ 2-52.5 Information Technology Requirements That Drive Substation Automation

Designs .................................................................................................................... 2-72.5.1 IntelliGrid Architecture Framework Contents..................................................... 2-92.5.2 Abstract Modeling............................................................................................2-102.5.3 Information Security Planning and Management..............................................2-132.5.4 Data Management ...........................................................................................2-152.5.5 System and Application Management..............................................................2-172.5.6 Network Management......................................................................................2-18


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2.5.7 Telecommunications Management ..................................................................2-203PROJECT MANAGEMENT FOR SUBSTATION AUTOMATION........................................ 3-1

3.1 Purpose and Audience for This Section .................................................................... 3-13.1.1

Purpose............................................................................................................ 3-1

3.1.2 Audience .......................................................................................................... 3-1

3.2 The Big Picture ......................................................................................................... 3-13.2.1 Why a New Approach Is Necessary.................................................................. 3-13.2.2 The Importance of Project Management ........................................................... 3-23.2.3 Project Scenarios ............................................................................................. 3-2

3.2.3.1 Pilot Projects .............................................................................................. 3-33.2.3.2 Production Deployments............................................................................. 3-3

3.2.4 Strategic Approaches ....................................................................................... 3-33.2.4.1 Objectives and Priorities............................................................................. 3-43.2.4.2 Migration Strategy ...................................................................................... 3-5

3.3 Project Organization.................................................................................................. 3-53.3.1 Identifying a Champion..................................................................................... 3-53.3.2 Selecting a Project Manager............................................................................. 3-53.3.3 Involving Stakeholders...................................................................................... 3-53.3.4 Creating Project Teams.................................................................................... 3-6

3.4 The Project Team...................................................................................................... 3-73.4.1 Project Management Team............................................................................... 3-7

3.4.1.1 Team Composition ..................................................................................... 3-83.4.1.2 Responsibilities .......................................................................................... 3-8

3.4.2 Functional Requirements Team........................................................................ 3-83.4.2.1 Functional Requirements Team Composition ............................................. 3-93.4.2.2 Responsibilities of the Functional Requirements Team............................... 3-9

3.4.3 System Design Team ......................................................................................3-103.4.3.1 System Design Team Composition............................................................3-113.4.3.2 System Design Team Planning Responsibilities ........................................3-113.4.3.3 System Design Team Implementation Responsibilities..............................3-15

3.4.4 Technology Team............................................................................................3-193.4.4.1 Technology Team Composition .................................................................3-203.4.4.2 Technology Team Responsibilities ............................................................3-20

3.5 The Project Management Roadmap.........................................................................3-20


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3.5.1 The Project Charter Vehicle for Launching the Project..................................3-203.5.1.1 Purpose and Objectives.............................................................................3-213.5.1.2 Critical Success Factors and Risks............................................................3-213.5.1.3 Deployment Sites ......................................................................................3-213.5.1.4 Expected Benefits......................................................................................3-213.5.1.5 Constraints ................................................................................................3-22

3.5.2 Management Dynamics...................................................................................3-223.5.2.1 Building Teamwork ....................................................................................3-223.5.2.2 Delegation .................................................................................................3-233.5.2.3 Fostering Good Communication and Problem Solving...............................3-233.5.2.4 Maintaining Project Documents .................................................................3-233.5.2.5 Training .....................................................................................................3-243.5.2.6 Tracking Progress, Budgets, Schedules, and Resources ..........................3-243.5.2.7 Evaluating Project Work ............................................................................3-253.5.2.8 Arbitration..................................................................................................3-25

3.5.3 Benefit/Cost Analysis.......................................................................................3-263.5.4 Risk Assessment and Risk Management.........................................................3-27

3.5.4.1 Risks for a Project in Progress...................................................................3-283.5.4.2 Risks After a System Has Been Placed Into Service .................................3-293.5.4.3 A Description of the Risk Management Process........................................3-293.5.4.4

Using a Formal Process ............................................................................3-29

3.5.4.5 Risk Mitigation Techniques........................................................................3-30

3.6 The Roadmap to Design the Desired Substation......................................................3-313.6.1 Basic Concepts................................................................................................3-323.6.2 Business Processes ........................................................................................3-34

3.6.2.1 Describing a Business Process .................................................................3-343.6.2.2 Principles for Documenting Business Processes .......................................3-343.6.2.3 A Practical Methodology for Documenting Business Processes ................3-35

3.6.3 Substation Functions .......................................................................................3-373.6.4 Software Application Modules..........................................................................3-383.6.5 Application Functions.......................................................................................3-383.6.6 Logical Nodes and Information Flow................................................................3-39

3.7 Project Documents...................................................................................................3-393.7.1 Administrative Documents ...............................................................................3-40


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3.7.1.1 Project Request.........................................................................................3-403.7.1.2 Project Charter ..........................................................................................3-403.7.1.3 Statements of Work ...................................................................................3-413.7.1.4 Contracts...................................................................................................3-41 3.7.1.5 Budgets .....................................................................................................3-413.7.1.6 Schedules..................................................................................................3-41

3.7.2 Working Project Documents Project Deliverables in Process........................3-423.7.2.1 Functional Requirements...........................................................................3-423.7.2.2 Design Plans .............................................................................................3-433.7.2.3 Design Implementation..............................................................................3-43

3.7.3 Other Documents Related to System Operation..............................................3-433.7.4 Tracking Documents........................................................................................3-44

3.7.4.1 Progress Reports.......................................................................................3-443.7.4.2 E-mails and Correspondence ....................................................................3-443.7.4.3 Meeting and Teleconference Minutes........................................................3-443.7.4.4 Project Notes.............................................................................................3-44

3.7.5 Vendor Product Material ..................................................................................3-443.7.6 Reference Documents.....................................................................................3-45

4DEVELOPING FUNCTIONAL REQUIREMENTS FOR SUBSTATION AUTOMATIONEQUIPMENT, SYSTEMS, AND APPLICATIONS................................................................... 4-1

4.1 Purpose and Audience for This Section .................................................................... 4-14.1.1 Purpose............................................................................................................ 4-14.1.2 Audience .......................................................................................................... 4-1

4.2 Power System Functions That Drive the Requirements for SubstationAutomation ............................................................................................................... 4-1

4.2.1 Transmission Planning Functions ..................................................................... 4-44.2.2 Normal Real-Time Transmission Operation ...................................................... 4-74.2.3 Emergency Real-Time Transmission Operation...............................................4-114.2.4 Post Real-Time Transmission Operation .........................................................4-16

4.3 Examples of Key Substation Automation Power System Functions Based onthe IntelliGrid Architecture .......................................................................................4-20

4.3.1 Data Acquisition and Control (DAC) Functions Within SubstationAutomation......................................................................................................4-20

4.3.2 IntelliGrid Environments...................................................................................4-20


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4.3.3 Substation High-Speed DAC Direct Power Equipment Monitoring andControl in the Deterministic, Rapid-Response Intra-SubstationEnvironment....................................................................................................4-23

4.3.3.1 Description of Function Direct Power Equipment Monitoring andControl .............................................................................................................

4.3.3.2 IntelliGrid Environment of the Function Deterministic RapidResponse Intra-Substation Environment ...................................................4-23

4.3.3.3 Requirements Defining the Deterministic Rapid Response Intra-Substation Environment ............................................................................4-24

4.3.3.4 Recommended Technologies for This Environment...................................4-254.3.4 Substation IED Interactions in the Deterministic, Rapid-Response Intra-

Substation Environment and the Critical Intra-Substation Environment...........4-264.3.4.1 Description of the Function Local Interactions Among Intelligent

Electronic Devices.....................................................................................4-264.3.4.2 Environments of the Function Deterministic Rapid Response Intra-

Substation Environment and Critical Operations Intra-SubstationEnvironment..............................................................................................4-27

4.3.4.3 Requirements Defining the Critical Operations Intra-SubstationEnvironment..............................................................................................4-28

4.3.4.4 Recommended Standards and Technologies for the CriticalOperations Intra-Substation Environment..................................................4-29

4.3.5 SCADA DAC Functional Requirements in the Critical DAC Environment.........4-324.3.5.1 Description of the Function DAC Functional Requirements for

SCADA Systems.......................................................................................4-324.3.6 Energy Management System Information Requirements in the Intra-Control Center Environment............................................................................4-33

4.3.6.1 Description of the Function EMS Operations ..........................................4-33

4.3.6.2 IntelliGrid Environment of the Function Intra-Control CenterEnvironment..............................................................................................4-35

4.3.6.3 Requirements Defining the Intra-Control Center Environment ...................4-364.3.6.4 Recommended Standards and Technologies for the Intra-Control

Center Environment ..................................................................................4-374.3.7 Protection Engineering Information Requirements in the Critical and

Noncritical Operations DAC Environments......................................................4-404.3.7.1 Description of the Function Protection Engineering ................................4-404.3.7.2 IntelliGrid Environment of the Function Critical Intra-Substation and

Critical Operations DAC Environments......................................................4-414.3.7.3 Requirements Defining the Critical Operations DAC Environment .............4-414.3.7.4 Recommended Standards and Technologies for the Critical

Operations DAC Environment ...................................................................4-42


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4.3.8 Mobile Operations and Maintenance Activity Requirements ............................4-424.3.8.1 Description of the Function Mobile Operations and Maintenance

Activity Requirements................................................................................4-424.3.8.2 IntelliGrid Environment of the Function Field Equipment

Maintenance Environment.........................................................................4-434.3.8.3 Requirements Defining the Field Equipment Maintenance

Environment..............................................................................................4-434.3.8.4 Recommended Standards and Technologies for the Field Equipment

Maintenance Environment.........................................................................4-445SPECIFYING FUNCTIONAL REQUIREMENTS AND IEC61850 FOR SUBSTATIONAUTOMATION........................................................................................................................ 5-1

5.1 Purpose and Audience for This Section .................................................................... 5-15.1.1 Purpose............................................................................................................ 5-15.1.2 Audience .......................................................................................................... 5-1

5.2 Model-Based Development of Functional Requirements ........................................... 5-25.2.1 Problems of Historical Concepts and Technologies .......................................... 5-25.2.2 Benefits of Modeling Technologies ................................................................... 5-3

5.3 Use of Abstract Modeling Tools to Develop Requirements........................................ 5-45.3.1 Abstract Modeling............................................................................................. 5-45.3.2 Information Exchange Interoperability............................................................... 5-45.3.3 Interworkability.................................................................................................. 5-45.3.4

Interchangeability ............................................................................................. 5-5

5.4 Unified Modeling Language (UML)............................................................................ 5-5

5.4.1 Abstract Modeling in UML................................................................................. 5-55.4.2 Use Cases........................................................................................................ 5-65.4.3 UML Methodology ............................................................................................ 5-9

5.5 IEC61850 Information Exchange Configurations......................................................5-115.6 Procedure for Specifying IEC61850 .........................................................................5-12

5.6.1 Step 1 Determine Functional Requirements .................................................5-135.6.2 Step 2 Determine IEC61850 Logical Nodes and the Available Data .............5-145.6.3 Step 3 Determine IEC61850 Data Exchanges Within the Substation............5-14 5.6.4 Step 4 Determine IEC61850 Data Exchanges With External Systems..........5-155.6.5 Step 5 Specify Conformance Testing............................................................5-155.6.6 Step 6 Specify IEC61850 Configuration Tools ..............................................5-15


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6IMPLEMENTING IEC61850 IN EQUIPMENT AND SYSTEMS............................................ 6-16.1 Purpose and Audience for This Section .................................................................... 6-1

6.1.1 Purpose............................................................................................................ 6-16.1.2 Audience .......................................................................................................... 6-1

6.2 IEC TC57 Architecture and the Components of the IEC61850 Standard................... 6-16.2.1 Outline of the IEC61850 Document .................................................................. 6-36.2.2 Object Modeling................................................................................................ 6-4

6.2.2.1 Object Model Structure............................................................................... 6-56.2.2.2 Object Model Naming ................................................................................. 6-7

6.2.3 Communication Services Modeling................................................................... 6-86.2.3.1 ACSI Abstract Communication Services Interface ................................... 6-96.2.3.2 Implementation Settings and HMI..............................................................6-13

6.2.4 Mapping to Protocol Profiles............................................................................6-146.2.5 Substation Configuration Language Modeling .................................................6-156.2.6 Power System Configuration Modeling............................................................6-16

6.3 Implementing IEC61850 Object Models ...................................................................6-186.3.1 Electric Power Measurements .........................................................................6-196.3.2 Switches, Circuit Breakers, and Reclosers ......................................................6-206.3.3 Transformers and Tap Changers.....................................................................6-226.3.4 Capacitor Bank Switch Logical Nodes .............................................................6-236.3.5 Protection Logical Nodes.................................................................................6-24

6.3.5.1 Typical Protection Logical Nodes for a Transformer Relay ........................6-286.3.5.2 Typical Protection Logical Nodes for a Line Distance Relay ......................6-296.3.5.3 Typical Protection for a Feeder Relay........................................................6-306.3.5.4 Typical Protection for a Generator Relay...................................................6-316.3.5.5 Typical Protection for a Bus Differential Relay ...........................................6-326.3.5.6 Typical Protection for a Motor Relay..........................................................6-32

6.3.6 Disturbance Recording Logical Nodes.............................................................6-336.3.7 Metering Logical Nodes...................................................................................6-346.3.8 Archiving, HMI, and Alarming Logical Nodes...................................................6-346.3.9 Power Quality ..................................................................................................6-34

6.4 Implementing Communications Service Models in Servers and Clients....................6-356.4.1 Basic Conformance Statement ........................................................................6-35


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6.4.2 ACSI Models Conformance Statement ............................................................6-386.4.3 ACSI Service Conformance Statement............................................................6-44

7INSTALLING IEC61850 EQUIPMENT AND SYSTEMS IN SUBSTATIONS........................ 7-17.1

Purpose and Audience for This Section .................................................................... 7-1

7.1.1 Purpose............................................................................................................ 7-17.1.2 Audience .......................................................................................................... 7-1

7.2 Evaluating and Selecting Equipment and Suppliers .................................................. 7-17.2.1 Support for Functional Requirements ............................................................... 7-1

7.2.1.1 General ...................................................................................................... 7-27.2.1.2 Application Functionality ............................................................................. 7-37.2.1.3 Product Tools ............................................................................................. 7-3

7.2.2 Support for Substation Automation Communication Objectives ........................ 7-37.2.2.1 Network Support......................................................................................... 7-47.2.2.2 Support for Utility-Specific Object Models ................................................... 7-47.2.2.3 Support for Utility-Specific Communication Services .................................. 7-4

7.2.3 Support for Collateral Communications ............................................................ 7-47.2.4 Technical Support and Commitment................................................................. 7-4

7.3 Monitoring and Managing System Development ....................................................... 7-57.3.1 Project Management ........................................................................................ 7-57.3.2 Meetings........................................................................................................... 7-67.3.3 Change Order Management ............................................................................. 7-6

7.4 Evaluation Process ................................................................................................... 7-77.5 Statement of Work .................................................................................................... 7-87.6 System Integration and Testing................................................................................. 7-8

7.6.1 Specification ..................................................................................................... 7-97.6.2 Vendor Selection .............................................................................................. 7-97.6.3 Certification ...................................................................................................... 7-97.6.4 Factory Acceptance Test .................................................................................. 7-97.6.5 Site Acceptance Test.......................................................................................7-107.6.6 What Is Tested and When ...............................................................................7-107.6.7 Conformance Testing of OM-SA Products.......................................................7-117.6.8 Test Plan Outline.............................................................................................7-13

7.7 IEC61850 Testing ....................................................................................................7-147.7.1 Key Testing Definitions....................................................................................7-14


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7.7.2 Conformance Test Process .............................................................................7-157.7.3 Standard Test Procedure Groups ....................................................................7-167.7.4 Control Test Example ......................................................................................7-167.7.5 Sample Test Cases .........................................................................................7-19

7.8 System Maintenance and Support............................................................................7-21A GLOSSARY/ACRONYMS...................................................................................................A-1BA BRIEF HISTORY OF UTILITY INDUSTRY STANDARDS DEVELOPMENT...................B-1CLISTING OF KEY INFORMATION......................................................................................C-1


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LIST OF FIGURES

Figure 1-1 Audience for Each Section of the SA Guidelines................................................... 1-3Figure 1-2 Two Infrastructures Must Be Managed in the Future.............................................. 1-5Figure 1-3 Organization of Project Teams............................................................................... 1-6Figure 1-4 IntelliGrid Architecture Framework ......................................................................... 1-7Figure 1-5 Example of a UML Diagram Implementing Substation Automation Using

Substation Configuration Language (SCL) ...................................................................... 1-9Figure 1-6 Suite of Components Within IEC61850 .................................................................1-10Figure 1-7 Architecture for Open Conformance Test..............................................................1-11Figure 2-1 Power System Infrastructure and the Information Infrastructure............................. 2-8Figure 2-2 IntelliGrid Architecture Framework ........................................................................2-10Figure 3-1 The Organization of Project Teams........................................................................ 3-7Figure 4-1 Example of IntelliGrid Environments Two Environments Within the

Substation, One Environment Between the Substation and the Control Center, andOne Environment Within the Control Center...................................................................4-21

Figure 4-2 Data Acquisition and Control for Distribution Operations (UML Use Case)............4-22Figure 4-3 Integration of EMS Transmission Functions with DMS/ADA Distribution

Functions A Real-Time Adaptive Decision-Making and Wide Area Control System

Is Required to Meet the Objectives of the Self-Healing Grid ...........................................4-35Figure 5-1 UML Use Case Implementing Substation Automation......................................... 5-8Figure 5-2 Basic Communication Services Concept Model ....................................................5-12Figure 6-1 Current Reference Architecture of IEC TC57 ......................................................... 6-2Figure 6-2 Suite of Components Within IEC61850.................................................................. 6-3Figure 6-3 Object Model Hierarchy.......................................................................................... 6-5Figure 6-4 Example of the Relationship of Logical Device, Logical Nodes, Data Objects,

and Common Data Classes............................................................................................. 6-7Figure 6-5 IED Object Naming ................................................................................................ 6-8Figure 6-6 Setting Group Model .............................................................................................. 6-9

Figure 6-7 Buffered Reporting Model .....................................................................................6-10Figure 6-8 Unbuffered Reporting Model .................................................................................6-10Figure 6-9 Log Model.............................................................................................................6-11Figure 6-10 Substitution Model ..............................................................................................6-11Figure 6-11 Sampled Values Model .......................................................................................6-12Figure 6-12 GOOSE Model....................................................................................................6-12


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Figure 6-13 GSE Model .........................................................................................................6-13Figure 7-1 Architecture for Open Conformance Test..............................................................7-12Figure 7-2 Conformance Test Steps ......................................................................................7-15Figure 7-3 State Transition Diagram ......................................................................................7-19


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LIST OF TABLES

Table 1-1 The Audience for Each Report Section ................................................................... 1-2Table 2-1 Possible Types of Networks and Systems Management Functions........................2-20Table 3-1 System Design Team Composition ........................................................................3-11Table 3-2 Training Topics ......................................................................................................3-24Table 3-3 Risk Mitigation Techniques ....................................................................................3-31Table 4-1 Transmission Operation Function Requirements for Transmission Planning ........... 4-4Table 4-2 Transmission Operation Function Requirements for Normal Real-Time

Operations....................................................................................................................... 4-7Table 4-3 Transmission Operation Function Requirements for Emergency Real-Time

Operations......................................................................................................................4-11Table 4-4 Transmission Operation Functions Requirements for Post Real-time

Operations......................................................................................................................4-16Table 6-1 Electric Power Measurement Logical Nodes ..........................................................6-20Table 6-2 Switch, Circuit Breaker, and Recloser Logical Nodes.............................................6-21 Table 6-3 Transformer and Tap Changer Logical Nodes........................................................6-23Table 6-4 Capacitor Switch Logical Nodes.............................................................................6-24Table 6-5 Protection Functions Logical Nodes .......................................................................6-25Table 6-6 Typical Protection Logical Nodes for a Transformer Relay.....................................6-28Table 6-7 Typical Protection Logical Nodes for a Line Distance Relay...................................6-29 Table 6-8 Typical Protection Logical Nodes for a Feeder Relay .............................................6-30Table 6-9 Typical Protection Logical Nodes for a Generator Relay ........................................6-31Table 6-10 Typical Protection Logical Nodes for a Bus Differential Relay ..............................6-32Table 6-11 Typical Protection Logical Nodes for a Motor Relay .............................................6-32Table 6-12 Disturbance Recording Logical Nodes .................................................................6-33Table 6-13 Metering Logical Nodes........................................................................................6-34Table 6-14 Archiving, HMI, and Alarming Logical Nodes........................................................6-34Table 6-15 Basic Conformance Statement.............................................................................6-38Table 6-16 ACSI Models Conformance Statement.................................................................6-42Table 6-17 ACSI Service Conformance Statement ................................................................6-45Table 7-1 Kepner-Trego Analysis............................................................................................ 7-8Table 7-2 Types of Testing.....................................................................................................7-11Table 7-3 General Flow of Automated Conformance Testing.................................................7-12


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Table 7-4 Sample Test Plan Outline.......................................................................................7-13Table 7-5 Test Procedure Groups..........................................................................................7-16Table 7-6 State Definitions for Control ...................................................................................7-18Table 7-7 Events/Message Definitions/Conditions/Actions.....................................................7-18Table 7-8 State Transition Table for Control...........................................................................7-18Table 7-9 Test Cases Defined in IEC61850 ...........................................................................7-20Table 7-10 Conformance Test Report Format........................................................................7-21 Table 7-11 Sample Service Level Agreement Response Times.............................................7-22


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1AN OVERVIEW OF IEC61850 SUBSTATION

AUTOMATION GUIDELINES

1.1 Identifying the Purpose, Scope, and Audience for IEC61850Substation Automation Guidelines

1.1.1 Purpose

This report provides guidelines for project managers, substation planners and engineers, projectengineers, vendors, and substation integrators on the informational issues related toimplementing IEC61850 in substation automation (SA). Substation automation is a newchallenge for the utility industry, particularly when the new capabilities of IEC61850 are utilizedto the fullest. The full range of new functions that IEC61850 enables are not yet well understood.

These guidelines were developed to describe the overall vision of SA to help ensure that theparadigm shift provided by this new enabling technology is appreciated by the utility industry.The guidelines describe the steps required in each phase of implementing SA with IEC61850.

1.1.2 Scope

These guidelines provide a basic understanding of IEC61850. Issues and methods for specifyingand implementing IEC61850 in SA are discussed. The guidelines describe the functionalrequirements that must drive the design of the information system, the methodology for utilitiesto determine the functions that are required in their specific situations, and the recommendedinformation standards for meeting those requirements (focusing on IEC61850).

1.1.3 Audience

The intended audiences for these guidelines are utilities who are interested in SA implementation

and vendors who sell systems and equipment for SA.

Table 1-1 describes the audience for each of the main sections of this report. This guideline isorganized according to the different stages of SA planning and implementation (see Figure 1-1).It is expected that all readers will review the first two sections of this report. Each of thesubsequent sections of the report is oriented toward a specific audience.


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An Overview of IEC61850 Substation Automation Guidelines

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After reviewing the overview (Section 1), it is expected that most readers will read Section 2,The Vision for the Future of Substation Automation as an introduction to the broader issues ofthe pressures of deregulation on power system management, evolving information technologies,and the drive to automate systems. In all likelihood, readers will determine their specific areas ofinterest, such as planning or deployment, and move directly to that section of the report. Thedocument, therefore, is designed so that each section can stand alone.

Table 1-1The Audience for Each Report Section

Section Title Audience

Section 1 An Overview of IEC61850 Substation AutomationGuidelines

All

Section 2 The Vision for the Future of Substation Automation All

Section 3 Project Management for Substation Automation SA project manager and team leads

Section 4 Developing Functional Requirements for SubstationAllocation Equipment, Systems, and Applications

Substation planners and engineers

Section 5 Specifying Functional Requirements and IEC61850for Substation Automation

Information technology engineers

Section 6 Implementing IEC61850 in Equipment and Systems Substation engineers and vendors

Section 7 Installing IEC61850 Equipment and Systems inSubstations

Substation automation integrators


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verviewofIEC61850SubstationAutomationGuidelines

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Figure1-1

AudienceforEachS

ectionoftheSAGuidelines


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1.2 The Vision for Substation Automation

Gunpowder, the printing press, the commercial generation of electricity, the personal computer,and the Internet were all major paradigm shifts. Information has become the driving necessity in

power system operations. In an interview

1

on August 14

th

, 2003 (during the east coast blackout),Kurt Yeager, CEO of EPRI, stated The first, the most important factor that we have to apply tothe power system today is to make it a digitally controlled system.

Substation automation is far more than just the automation of substation equipment. It is one ofthe first steps toward the creation of a highly reliable, self-healing power system that respondsrapidly to real-time events with appropriate actions and that supports the planning and assetmanagement necessary for cost-effective operations. Automation does not simply replace manualprocedures. It permits the power system to operate in an entirely new way based on accurateinformation provided in a timely manner to the decision-making applications and devices.

In the past, utility attention was focused only on managing the power system infrastructure.However, as illustrated in Figure 1-2, that old worldview has changed. There are now twoinfrastructures that must be managedthe power system infrastructure and the communicationsinformation infrastructure.

Substation automation was not feasible a few years ago. Communication technologies simplywere not available to handle the kinds of demands put on them by the complexity of substationautomation requirements. For instance, one of the main enablers of substation automation wasthe recognition that the vast bundles of point-to-point wiring between the control house and theequipment in the substation yard could be eliminated through the use of Ethernet networks.Communication standards have now been developed that can address many of these demands. Inparticular, IEC61850 provides solutions to automation issues using state-of-the-art object-

modeling technologies.

The vision for substation automation over the next years is presented in Section 2.

1 http://www.pbs.org/newshour/bb/fedagencies/july-dec03/blackouts_08-25.html


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Figure 1-2Two Infrastructures Must Be Managed in the Future

1.3 Project Management for Substation Automation Projects

The implementation of substation automation requires more effort and different expertise thansimply implementing a new substation using the traditional approaches. It is, therefore, veryimportant for a substation engineer to fully appreciate the different steps required, even thoughthese steps must be tailored to each individual situation.

Planning for substation automation requires a different approach than substation planners havetypically used in the past. In addition to the design of physical and electrical requirements, SAalso requires the design of the information requirements.

These are the basic steps in substation automation:

1. Find a champion who recognizes that substation automation will be cost-effective despite thelearning pains, the need for different skills and approaches, and the inevitable glitches.

2. Develop a project team, headed by an effective project manager, with three subteams: afunctional team, a system design team, and a technical team (see Figure 1-3).

3. Develop functional requirements by describing what the applications are to do in supportingstakeholder needs. This includes reaching out to stakeholder groups to determine what theyneed from SA systems.

4. Develop system management requirements that include security, performance, and otherfunctions necessary to effectively manage the equipment and communication networks.


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5. Develop technical specifications that truly capture the functional requirements, but that donot over-specify by identifying the specific hardware. The specifications must cover thesubstation equipment as well as the communication systems, including the object modelsdefined in the IEC61850.

6. Evaluate bidders and select vendors to provide the equipment and systems.

7. Monitor and manage the system development efforts (both in-house and by the vendors).

8. Review and comment on documentation, which is vital to ensure the equipment and systemsare developed as specified.

9. Complete factory, field, and acceptance testing.

10. Complete field installation, validation, and commissioning.

11. Conduct planning for future upgrades and extensions.

These implementation steps are discussed in Section 3.

Figure 1-3Organization of Project Teams

1.4 Developing Functional Requirements for Substation AutomationEquipment, Systems, and Applications

Planning for SA requires a different approach than substation engineers have typically used inthe past to construct new substations. In addition to the design of physical and electricalrequirements, SA also requires the design of the information requirements.


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The IntelliGrid Architecture (at http://IntelliGrid-Architecture.com), can provide much of thissupport to substation planners. The IntelliGrid Project was funded by the Consortium of ElectricInfrastructure to Support a Digital Society (CEIDS) for E2I, one of EPRIs family of companies,to provide a framework of communication and information standards to meet the needs ofexisting and future power system functions. The IntelliGrid Architecture (see Figure 1-4) derivedthe communication and information requirements of power system functions by first creating acomprehensive list of functions, analyzing the needs of these functions, and refining these needsby in-depth analysis of some of the key functions.

A discussion of the development of functional requirements, and some examples from theIntelliGrid Architecture, are presented in Section 4.

Figure 1-4IntelliGrid Architecture Framework

1.5 Specifying Functional Requirements and IEC61850 for Substation

Automation

Specifying the functional requirements for substation automation requires a different approachthan substation engineers have used in the past to construct new substations. The functionalrequirements must encompass far more than just purchasing equipmentthey need to describethe requirements of all stakeholders in taking advantage of the capabilities of SA based on thestate-of-the-art technologies of IEC61850. These stakeholders include operations, protection,planning, engineering, maintenance, data management, security, market operations, andcorporate.
http://intelligrid-architecture.com/http://intelligrid-architecture.com/http://intelligrid-architecture.com/


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By definition, functional requirements should focus on what rather than on how. The mosteffective way to develop these functional requirements is to use modeling techniques. Thesemodeling techniques allow functions to be described with their interactions illustrated throughformalized drawings (see Figure 1-5). Using models allows functions to be drawn and redrawn(on paper or on computer screens) so that all stakeholders can review them. The function must berefined as requirements are better understood and finalized into formal functional specificationsbefore actual designs are created and long before any hardware or software is purchased.

Substation automation involves not only equipment, but also the communications infrastructureto monitor and manage the equipment, particularly when all of the IEC61850 capabilities are tobe utilized. Therefore, in addition to the design of physical and electrical requirements,substation automation also requires the analysis of information requirements and a determinationof the flow of information between equipment and systems. Modeling techniques can also beused to develop the best infrastructure or these communication information requirements.

A brief overview of some key modeling techniques, a discussion of the use of IEC61850substation configuration language, and the procedure for specifying IEC61850 are presented in

Section 5.


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Figure 1-5

Example of a UML Diagram Implementing Substation Automation Using SubstationConfiguration Language (SCL)


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1.6 Implementing IEC61850 in Equipment and Systems

It is not easy to read the IEC61850 documents or to comprehend how the pieces all worktogether. This section is designed to describe the IEC61850 standards in more user-friendlyterms and to identify the available options (see Figure 1-6) for a high-level vision of IEC61850).

Section 6 first describes the concepts within IEC61850, which was developed explicitly forsubstation automation, although it also forms the basis for object model extensions. Section 6also addresses specific equipment, discussing the existing models that may be relevant and theneed for additional models. Finally, Section 6 identifies the conformance tables that must beagreed upon for specific implementations.

When implementing systems as complex and as new as SA, substation engineers will need towork closely together with the vendors of SA equipment and systems. Although the vendors willperform the detailed implementation of the IEC61850 object models and service models, thesubstation engineers must be able to decide what settings should be established for a particularsubstation. Therefore, substation engineers should develop a deeper understanding of IEC61850,of the potential benefits of the various features if they can be fully utilized, and of the issues thatmust be resolved as SA equipment and system are implemented for the utility.

Figure 1-6Suite of Components Within IEC61850


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1.7 Installing IEC61850 Equipment and Systems in Substations

The implementation and testing of a substation automation system involves multiple partners:integrators, substation engineers, utility operations, construction and asset managementpersonnel, information technologists, consultants, and multiple vendors. As discussed in Section

3, strong project management is required to facilitate these interactions. There are someinteractions that explicitly involve IEC61850. Therefore, this section focuses on the issuesassociated with installing and testing IEC61850 equipment and systems in substations (seeFigure 1-7).

Section 7 is intended to help the integrators who are involved in developing, implementing, andtesting SA systems. These integrators could be utility substation engineers, outside A&E firms,vendors, or a mix of these groups.

The implementation steps are discussed in Section 7.

Figure 1-7Architecture for Open Conformance Test

1.8 Key Points

Throughout this guide, key information is summarized in key points defined as bold lettered

boxes that succinctly restate information covered in detail in the surrounding text, making iteasier to locate.

By emphasizing vital information, key points enable personnel to take action for the benefit oftheir plant. The information included in these key points was selected by EPRI personnel,consultants, and utility personnel who prepared and reviewed this report.


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The key points in this report fall into one major categorykey technical points. Each key pointhas an identifying icon, as shown here, that draws attention to it, making it easy for personnel toquickly locate vital information.

Key Technical Point

Targets information that will lead to improved equipment reliability.

Appendix C contains a listing of all the key points contained in this document. The listingrestates each key point and provides reference to its location in the body of the report. Byreviewing this listing, users of this guide can determine if they have taken advantage of keyinformation that can benefit their plants.


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2THE VISION FOR SUBSTATION AUTOMATION

2.1 Purpose and Audience for This Section

This section discusses the overall vision for substation automation. It should be read by allreaders to set the stage for the remaining sections.

2.2 Thinking Outside the Box Paradigm Shift of Substation Automation

Gunpowder, the printing press, the commercial generation of electricity, the personal computer,and the Internet were all major paradigm shifts. Not surprisingly, they all swept away currentpractice or modified it significantly (not instantly, but quickly enough to indicate that somethingrather important had occurred). In each case, there was a present need, a confluence oftechnologies, and a vision of how to combine technology and need for economic gain andunprecedented advantage. Substation automation is not just the automation of a substationit ispart of a major paradigm shift for all power system operations.

Key Technical Point

Substation automation is not just the automation of a substationit is part of

a major paradigm shift for all power system operations.

Perhaps electric power transmission and distribution networks are ready for such a change. Theyrepresent the largest and most capital-intensive system devised by man. Yet, utilities leverage aremarkably small amount of information from this lifeblood of their business. As past and recentevents have demonstrated, the urgency to improve this situation is increasing. It is necessary toensure a secure national grid. As the amount of distributed energy resources (DERs) grows, itwill be necessary to accommodate a higher grid complexity. Improved efficiency, better powerquality, and deterministic power flow are necessary in support of a more competitive businessclimate. Technical, legal, and financial models of the power system must reinforce one another

to ensure accountability.

Mainstream technologies can already extract a wealth of information from the power deliverysystem, selectively delivering it to multiple utility departments according to need. Thistechnological infrastructure is shared so that all stakeholders have common access to station dataand functionality, subject to security safeguards, regulations, and corporate policy. Moderndevices and controllers can easily and cost-effectively provide exhaustive measurements ofpower system data with all its nuances. They can detect and measure system events and


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The Vision for Substation Automation

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conditions, and control the flow of power. They support the traditional protection of individualequipment as well as the development of strategies for protection of the system as a wholeagainst contingencies. The first (and most important) effort that must be applied to the powersystem today is to make it a digitally controlled system.

Key Technical Point

The first and most important effort that must be applied to the power systemtoday is to make it a digitally controlled system.

When this integration of data and functionality is accomplished, the stage will be set for oneadditional huge benefitthe implementation of local and system-wide automation that deliverseconomic gains on many fronts. The result will be a reduction of nonproductive effort, theoperation of equipment assets at higher power levels (while also monitoring them for operationalsafety under current operating conditions), and the interactive use of equipment assets to affectvoltage and VAr control strategies. There are numerous applications that can be deployed to

economic and operational advantage.

Substation automation is far more than just the automation of substation equipment. It is one ofthe first steps toward the creation of a highly reliable, self-healing power system that respondsrapidly to real-time events with appropriate actions and that supports the necessary planning andasset management for cost-effective operations. Automation does not simply replace manualproceduresit permits the power system to operate in an entirely new way, based on accurateinformation provided in a timely manner to the decision-making applications and devices.

Why should an organization tolerate semi-informed decisions that may eventually costtremendous time and money, especially when the means are available to tightly justify (or

discredit) proposed improvements? These guidelines enable decentralized access to the stationresources. This approach enables each department to gain access to those allowed resources thatare most valuable for improving its process, cutting its cost, and exploiting new opportunitiesthat open up. It lets each group meet its own responsibilities, applying innovation to the area itknows most intimately. If the corporate staff meets its responsibilities to provide direction andleadership, there is no doubt that the whole utility enterprise can achieve significantadvancement. To summarize, these advantages can be used to transform how organizationsconduct business.


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Information has become the driving necessity in power system operations. In an interview onAugust 25, 2003 regarding the August 14

theast coast blackout, Kurt Yeager (CEO of EPRI)

made the following comments2:

The first, the most important factor that we have to apply to the power system today is to

make it a digitally controlled system. We have a digital economy and we're still trying toprovide power to it through a mechanical design system that was designed over 50 yearsago. Its a marvelous system, but we've been effectively borrowing against the future topay for the present, and the future has caught up with us; we need to build the system toserve the digital society of the 21st century. So that's the first step.

In so doing we can increase the efficiency and the capacity of the system we have. It willnot eliminate the need for some new lines, but certainly we, if we do it technically,capacity expansion, we can reduce the amount of new lines that have to be put in place.So it really fundamentally improves the efficiency.

And it's then the controllability of that system. Once we have those digital controls in, we

can instantaneously manage the power system so it is self-healing, that is it can detectinstantaneously a difficulty and correct for it locally so that cascading effects can beeliminated and fundamentally improve the reliability of the system so that computers andother sensitive equipment that has come in over the last decade is not upset by powerdisturbances.

Substation automation basically consists of implementing intelligent electronic devices (IEDs)using microprocessors to monitor and control the physical power system devices. These IEDscan make more data available in digital format. Having a large amount of data (in whateverformat) is not particularly good or bad in and of itself. However, these data can be turned intoinformation that is available in the right form, at the right place, and at the right time. It is thisinformation that is the true benefit of substation automation.

2.3 Enabling Information Technologies That Enhance SubstationAutomation Capabilities

Substation automation would not really have been feasible a few years ago. Communicationtechnologies simply were not available to handle the kinds of demands put on them by thecomplexity of substation automation requirements.

For example, one of the main enablers of substation automation was the recognition that the vastbundles of point-to-point wiring between the control house and the equipment in the substation

yard could be eliminated through the use of Ethernet networks. But Ethernet was only practicalafter the higher speed switching technologies were developed. When networking becamestandardized with highly reliable products available from multiple vendors, automation becamefeasible because data could be collected from multiple devices without the added expense ofrunning new wires.

2 Ibid.


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Key Technical Point

Recognition of the fact that vast bundles of point-to-point wiring could beeliminated through the use of Ethernet networks was one of the mainenablers of substation automation.

With this basic communications capability in place, other technologies commonly used in otherindustries could be easily adapted to the substation environment. Rather than just replacing wireswith Ethernet networks, the door would open to additional technologies to improve themanagement of data, the security of information, and the simplification of hardware and softwaremaintenance. The following list contains examples of the state-of-the-art technologies that mightthen be applied:

Industry-standard interface technology: Transition Control Protocol/Internet Protocol(TCP/IP) can be used through the Ethernet network to provide full routing capabilities.TCP/IP can also be used for engineering stations providing direct access over logical paths toIEDs in the substation for remote configuration and setting of parameters without the needfor separate physical links.

Security through standards and role-based access control (RBAC): TCP/IP has well-established security mechanisms, and the IEC61850 security technologies are in the processof being standardized. Through RBAC, control centers can assign, monitor, and ensureindividual access rights to the information objects of the substation and subscribe toinformation objects.

Consolidation of hardware: Conversion of protocols and formats is avoided because thelocal communications platform within the substation (substation bus) and telecontrol is thesame. Instead of a gateway, a proxy can be used within the substation to present theinformation objects to the control center.

Object-modeling (Establishing standardized self-describing object names): By usingobject-modeling technology, IEC61850 established standardized self-describing objectnames for substation information instead of nondescriptive numerical addresses. This allowseach data item to be uniquely identified (similar to a person living at a unique address) andgreatly enhances the ability of systems to manage the data.

Key Technical Point

By using object-modeling technology, IEC61850 established standardizedself-describing object names for substation information.

Standardized naming and mapping to proprietary databases in proxy servers: Thedevice-oriented names of information objects can be mapped in the proxy server to process-oriented proprietary names and databases because the control center application is process-oriented and logical devices of the substation are, therefore, hidden.


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Data management: Data are becoming increasingly difficult to manage as the number ofdigital components increases within substations and as the amount of data from eachcomponent increases exponentially. With self-descriptive unique names, IEC61850 objectspermit systems to automatically manage the data without relying on data administrators tolaboriously follow a chain of nondescriptive numerical addresses (for example, point 12 on

card 5 should be mapped to the third item in column 39 in record 47 in database ABCD). Metadata management: Metadata, which is the information about data rather than the

dataset itself, can help establish interoperability among systems (just like a MicrosoftWindows

3system can detect and automatically install new hardware). This new concept of

metadata can be expanded to allow new substation devices to be detected and installed withminimal user support.

Designing toward a seamless architecture: In general, a seamless architecture leads topotential lower costs for design, configuration, installation, operation, and maintenancecombined with higher performance as compared to current solutions. Although much workstill needs to be done, the IntelliGrid Architecture has built the foundation for such aseamless architecture.

2.4 The Benefits of Substation Automation for Different Users

Having some information technology available does not necessarily mean that automation isuseful or justifiable. Data is not information. Therefore, it is vital to determine the true benefitsof substation automation to all stakeholders or users. In fact, not all benefits are cost-justifiedunder all conditions, so each situation must be evaluated individually. Nonetheless, manybenefits that were not initially obvious have become increasingly cost-justified, as automationhas moved from the simple replacement of existing processes to a more sophisticated interactionamong processes. The development of new functions that would have been impossible beforeautomation. For better or worse, automation leads to powerful new capabilities for users, which

in turn leads to the need for more automation.

Key Technical Point

Automation leads to powerful new capabilities for users, which in turn leads

to the need for more automation.

3 Microsoft Windows is a trademark of Microsoft Corporation.


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Some examples of the benefits of substation automation to different users are described brieflyhere:

Substation automation offers implementation benefits.

Reduced quantities of equipment: Through the use of shared technology for datasourcing, control, protection, station metering, processing, and communicationall forthe benefit of multiple utility departments and other clients.

Replacement of discrete station wiring with flexible communication networks: Toaccommodate continual system change and migration.

Networks implemented with fiber-optic cable: Mutually isolates pieces of connectedequipment to limit collateral equipment damage under adverse electrical conditions suchas faults and close-proximity lightning strikes.

Integration of digital informationand functionality: In disparate devices that currentlyoperate in separate realms such as fault recorders, protective relays, sequence of event

recorders, fault locators, network transducers, regulators, or controllers. Gradual displacement of analog devices: Typically less flexible in use, more difficult

to diagnose, and more costly to maintain.

New digital equipment capabilities: Such asdistance-to-fault locators and sag detectorscan easily be integrated with the other station equipment to provide new functionality andmore comprehensive system information.

Station HMI (human machine interface) consoles: Enables the displacement orreplacement of traditional station panels. Station information such as power system data,status of the local electrical network, and the diagnostics status of IEDs can be locallyconsolidated.

Substation automation benefits the utility staff.

Maintenance staff: Can remotely isolate and diagnose problems. This requires fewertrips to the station, saving time and money, resulting in typically shorter outages. Thiscapability is provided by microprocessor-based equipment supporting self-monitoringand self-diagnosis.

Planners, engineers, and asset management personnel: Can monitor and capture theoperational behavior of feeders and line equipment over time, profiling their servicecharacteristics against independent factors such as temperature, season, time of day, andtime of week. Statistical analysis can be used to distill useful information for planning.

Operators and operational planners: Additional real-time information for use inoperational planning (within the next hour or so).

Operators: Additional alarming capabilities and alarm management (how important iseach alarm under certain conditions and who should see them); or multiple sources fordata and alarms to ensure no critical information is lost or unavailable to operators.

Protection engineers: Oscillographic information available for capture in real-timeduring normal operations.


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Protection engineers: Ability to change settings remotely in anticipation of changingconditions

Operations engineers: Additional information available for contingency analysis andidentification of potential problems; management during emergency conditions,emergency recovery, and post-emergency analysis.

Data administrators: Avoid time-consuming and error-prone tracking of chains of datalinks each time a change is made in the field.

Substation automation benefits control center operations.

SCADA/EMS systems: Additional data are available to be monitored if operators and/orSCADA/EMS applications need them. Alternatively, if the SCADA/EMS system doesnot need data that are required by another group, then the other group can collect the datadirectly from the substation master without burdening the SCADA/EMS system.

Contingency analysis (security analysis): Additional data from multiple sources forredundancy, thus increasing the reliability of the results.

Intelligent alarm processing: With the additional data, intelligent alarm processing canfilter out the less important alarms from the more important ones and can also analyzethese data to determine the true issue causing the alarm. These more important alarms canthen notify operators, and/or cause additional applications to execute (such ascontingency analysis).

Emergency response: Control commands, whether issued locally or remotely, canrespond rapidly to emergency situations in a coordinated manner, not only within asubstation, but also between substations and between utilities.

2.5 Information Technology Requirements That Drive SubstationAutomation Designs

These enabling information technologies can provide the means to enjoy major benefits.However, they also have requirements that must be managed.

Most substation designs also include a secondary system, comprising all components andsystems used to monitor, control, protect, and automate the substation. Because this informationinfrastructure is critical to human safety, equipment safety, and system reliability, it has alwaysbeen an essential part of substation planning and implementation. Examples of these componentsinclude PTs, CTs, transducers, control panels, protection relays, RTUs, serial communications,

and HMI. In recent years, we have seen the emergence of intelligent devices (such as IEDs),networked communications, programmable logic, and digital signal processing (DSP)capabilities for extracting a wealth of information from a simple 3-phase power connection.

To date, however, integration of the secondary system has been fragmented, composed ofseparate subsystems with little commonality. IEC61850 now provides the means to integratecommunications, information, and applications into a coherent, flexible, very powerfulframework for the secondary system. With its deployment, more information will be exchangedand more applications will be run within the substation. We will see that integrated, accessible


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information is truly the enabler of effective and economic substation automation. Power systemoperations can no longer be viewed as a single infrastructurein addition to the power systeminfrastructure, there is now an information infrastructure that overlays the power system.

Figure 2-1Power System Infrastructure and the Information Infrastructure

The extraordinarily complex power system, sometimes viewed as the largest machine in the

world, cannot function without this information infrastructure. Not only is this informationinfrastructure a tremendous enhancer of power system operations, but it is also a new burdenbecause it too needs to be designed, implemented, and managed.

Key Technical Point

Both the power system and the information infrastructure must be designedand managed.

The information infrastructure must be designed with the main focus of supporting power system

operations. Many different information designs have been used to meet this criterion. However,within recent years, information technologies have been evolving so that they are better atsupporting power system operations and better at managing their own infrastructure. Althoughthese information technologies are still evolving, it is crucial to use what technologies areavailable and to plan for incorporating new concepts as they are solidified and standardized.


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Figure 2-2

IntelliGrid Architecture Framework

2.5.2 Abstract Modeling

Typically, power system engineers describe a power system function in their own wordsthis

rarely includes the exact information need by the systems engineers who implement the function.In order to more accurately extract the information requirements for a power system function, itis best to ask the power system experts to develop a step-by-step analysis of each part of thesystem. An information expert can then model this analysis using tools such as the UnifiedModeling Language (UML). Power system experts can then review these models to determine ifthey truly represent the needed functions. When a model is correct, it can more easily andreliably be implemented in software and hardware.

Modeling is one of the most powerful tools available for understanding, documenting, andmanaging the complexity of the infrastructures required to operate the energy system of thefuture. It is far less expensive to construct a model to test theories or techniques than to construct

an actual entity, only to find out that one crucial technique is wrong and the entire entity must bereconstructed.

Models have been used extensively by many industries as the basis for analyzing and designingcomplex systems. The telecommunications industries have made extensive use of modeling todevelop the diverse communication infrastructure(s) in widespread use today. Physical modelsare used in many industries, ranging from airplanes and Mars Landers to circuit breakers andtransformers. Building architects use paper models (blueprints) to capture the complexity in a


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