EPRI Guidelines for Implementing Substation Automation Using IEC 61850

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Guidelines for Implementing Substation

Automation Using IEC61850, the

International Power System Information

Modeling Standard

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EPRI Project Manager L. van der Zel

Guidelines for Implementing

Substation Automation Using

IEC61850

, t

he International Power

System Information Modeling

Standard

1008688

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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(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, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION 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 Willow Way, 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 Power Research Institute, Inc. EPRI. ELECTRIFY THE WORLD is a service mark of the Electric Power Research Institute, Inc.

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CITATIONS

This report was prepared by

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

Principal Investigators F. Cleveland

R. 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 Power System 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 substation automation (SA) when IEC61850 standards are used.

Results and Findings

Substation automation is far more than just the automation of substation equipment. It is the first step 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 management necessary for cost-effective operations. Automation does not simply replace manual

procedures—it permits the power system to operate in an entirely new way based on accurate information provided in a timely manner to the decision-making applications and field devices. Substation automation would not have been feasible a few years ago. Communication

technologies simply were not available to handle the kinds of demands imposed by the

complexity of SA requirements. However, communication standards have now been developed that can address many of these demands. In particular, the international power system

information modeling standard IEC61850 provides solutions to automation issues using state-of-the-art object-modeling technologies. IEC6185 also provides the key capabilities needed for the increasingly sophisticated requirements of data management.

Challenges and Objectives

This report provides guidelines on the informational issues related to SA in regard to the use of IEC61850 standards. Substation automation is a new challenge for the utility industry. These guidelines provide the overall vision as well as the specific steps that should be taken for successful implementation of this new enabling capability.

The guidelines also build on the work undertaken in E2I’s (one of EPRI’s family of companies) IntelliGrid Architecture project by using specific examples from SA functions to show how these functional requirements drive the need for the capabilities provided by IEC61850.

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

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Applications, Values, and Use

It 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 the IEC61850 standards in more user-friendly terms and by identifying the available options for automation. 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 of how the various object models work together.

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

EPRI Perspective

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

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

Approach

These guidelines were developed to describe the overall vision of SA to help ensure that the paradigm 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. Keywords

IEC61850

IntelliGrid architecture Substation automation

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3.1 Purpose and Audience for This Section ... 3-1 3.1.1 Purpose ... 3-1 3.1.2 Audience ... 3-1 3.2 The Big Picture ... 3-1 3.2.1 Why a New Approach Is Necessary... 3-1 3.2.2 The Importance of Project Management ... 3-2 3.2.3 Project Scenarios ... 3-2 3.2.3.1 Pilot Projects ... 3-3 3.2.3.2 Production Deployments... 3-3 3.2.4 Strategic Approaches ... 3-3 3.2.4.1 Objectives and Priorities ... 3-4 3.2.4.2 Migration Strategy ... 3-5 3.3 Project Organization... 3-5 3.3.1 Identifying a Champion ... 3-5 3.3.2 Selecting a Project Manager... 3-5 3.3.3 Involving Stakeholders... 3-5 3.3.4 Creating Project Teams ... 3-6 3.4 The Project Team... 3-7 3.4.1 Project Management Team... 3-7 3.4.1.1 Team Composition ... 3-8 3.4.1.2 Responsibilities ... 3-8 3.4.2 Functional Requirements Team... 3-8 3.4.2.1 Functional Requirements Team Composition ... 3-9 3.4.2.2 Responsibilities of the Functional Requirements Team... 3-9 3.4.3 System Design Team ...3-10 3.4.3.1 System Design Team Composition...3-11 3.4.3.2 System Design Team Planning Responsibilities ...3-11 3.4.3.3 System Design Team Implementation Responsibilities...3-15 3.4.4 Technology Team...3-19 3.4.4.1 Technology Team Composition ...3-20 3.4.4.2 Technology Team Responsibilities ...3-20

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3.5.1 The Project Charter – Vehicle for Launching the Project...3-20 3.5.1.1 Purpose and Objectives...3-21 3.5.1.2 Critical Success Factors and Risks...3-21 3.5.1.3 Deployment Sites ...3-21 3.5.1.4 Expected Benefits...3-21 3.5.1.5 Constraints ...3-22 3.5.2 Management Dynamics ...3-22 3.5.2.1 Building Teamwork ...3-22 3.5.2.2 Delegation ...3-23 3.5.2.3 Fostering Good Communication and Problem Solving...3-23 3.5.2.4 Maintaining Project Documents ...3-23 3.5.2.5 Training ...3-24 3.5.2.6 Tracking Progress, Budgets, Schedules, and Resources ...3-24 3.5.2.7 Evaluating Project Work ...3-25 3.5.2.8 Arbitration ...3-25 3.5.3 Benefit/Cost Analysis...3-26 3.5.4 Risk Assessment and Risk Management...3-27 3.5.4.1 Risks for a Project in Progress...3-28 3.5.4.2 Risks After a System Has Been Placed Into Service ...3-29 3.5.4.3 A Description of the Risk Management Process ...3-29 3.5.4.4 Using a Formal Process ...3-29 3.5.4.5 Risk Mitigation Techniques ...3-30 3.6 The Roadmap to Design the Desired Substation...3-31 3.6.1 Basic Concepts...3-32 3.6.2 Business Processes ...3-34 3.6.2.1 Describing a Business Process ...3-34 3.6.2.2 Principles for Documenting Business Processes ...3-34 3.6.2.3 A Practical Methodology for Documenting Business Processes ...3-35 3.6.3 Substation Functions ...3-37 3.6.4 Software Application Modules...3-38 3.6.5 Application Functions...3-38 3.6.6 Logical Nodes and Information Flow...3-39 3.7 Project Documents...3-39

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3.7.1.1 Project Request ...3-40 3.7.1.2 Project Charter ...3-40 3.7.1.3 Statements of Work ...3-41 3.7.1.4 Contracts ...3-41 3.7.1.5 Budgets ...3-41 3.7.1.6 Schedules...3-41 3.7.2 Working Project Documents – Project Deliverables in Process...3-42 3.7.2.1 Functional Requirements...3-42 3.7.2.2 Design Plans ...3-43 3.7.2.3 Design Implementation ...3-43 3.7.3 Other Documents Related to System Operation ...3-43 3.7.4 Tracking Documents...3-44 3.7.4.1 Progress Reports...3-44 3.7.4.2 E-mails and Correspondence ...3-44 3.7.4.3 Meeting and Teleconference Minutes ...3-44 3.7.4.4 Project Notes...3-44 3.7.5 Vendor Product Material ...3-44 3.7.6 Reference Documents ...3-45

4 DEVELOPING FUNCTIONAL REQUIREMENTS FOR SUBSTATION AUTOMATION

EQUIPMENT, SYSTEMS, AND APPLICATIONS... 4-1 4.1 Purpose and Audience for This Section ... 4-1

4.1.1 Purpose ... 4-1 4.1.2 Audience ... 4-1 4.2 Power System Functions That Drive the Requirements for Substation

Automation ... 4-1 4.2.1 Transmission Planning Functions ... 4-4 4.2.2 Normal Real-Time Transmission Operation ... 4-7 4.2.3 Emergency Real-Time Transmission Operation...4-11 4.2.4 Post Real-Time Transmission Operation ...4-16 4.3 Examples of Key Substation Automation Power System Functions Based on

the IntelliGrid Architecture ...4-20 4.3.1 Data Acquisition and Control (DAC) Functions Within Substation

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

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4.3.3 Substation High-Speed DAC – Direct Power Equipment Monitoring and Control in the Deterministic, Rapid-Response Intra-Substation

Environment...4-23 4.3.3.1 Description of Function – Direct Power Equipment Monitoring and

Control ... 4-23 4.3.3.2 IntelliGrid Environment of the Function – Deterministic Rapid

Response 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...4-25 4.3.4 Substation IED Interactions in the Deterministic, Rapid-Response

Intra-Substation Environment and the Critical Intra-Intra-Substation Environment...4-26 4.3.4.1 Description of the Function – Local Interactions Among Intelligent

Electronic Devices...4-26 4.3.4.2 Environments of the Function – Deterministic Rapid Response

Intra-Substation Environment and Critical Operations Intra-Intra-Substation

Environment...4-27 4.3.4.3 Requirements Defining the Critical Operations Intra-Substation

Environment...4-28 4.3.4.4 Recommended Standards and Technologies for the Critical

Operations Intra-Substation Environment...4-29 4.3.5 SCADA DAC Functional Requirements in the Critical DAC Environment...4-32

4.3.5.1 Description of the Function – DAC Functional Requirements for

SCADA Systems ...4-32 4.3.6 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 Center

Environment...4-35 4.3.6.3 Requirements Defining the Intra-Control Center Environment ...4-36 4.3.6.4 Recommended Standards and Technologies for the Intra-Control

Center Environment ...4-37 4.3.7 Protection Engineering Information Requirements in the Critical and

Noncritical Operations DAC Environments...4-40 4.3.7.1 Description of the Function – Protection Engineering ...4-40 4.3.7.2 IntelliGrid Environment of the Function – Critical Intra-Substation and

Critical Operations DAC Environments...4-41 4.3.7.3 Requirements Defining the Critical Operations DAC Environment ...4-41

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4.3.8 Mobile Operations and Maintenance Activity Requirements ...4-42 4.3.8.1 Description of the Function – Mobile Operations and Maintenance

Activity Requirements...4-42 4.3.8.2 IntelliGrid Environment of the Function – Field Equipment

Maintenance Environment...4-43 4.3.8.3 Requirements Defining the Field Equipment Maintenance

Environment...4-43 4.3.8.4 Recommended Standards and Technologies for the Field Equipment

Maintenance Environment...4-44

5 SPECIFYING FUNCTIONAL REQUIREMENTS AND IEC61850 FOR SUBSTATION

AUTOMATION... 5-1 5.1 Purpose and Audience for This Section ... 5-1

5.1.1 Purpose ... 5-1 5.1.2 Audience ... 5-1 5.2 Model-Based Development of Functional Requirements ... 5-2 5.2.1 Problems of Historical Concepts and Technologies ... 5-2 5.2.2 Benefits of Modeling Technologies ... 5-3 5.3 Use of Abstract Modeling Tools to Develop Requirements... 5-4 5.3.1 Abstract Modeling... 5-4 5.3.2 Information Exchange Interoperability... 5-4 5.3.3 Interworkability... 5-4 5.3.4 Interchangeability ... 5-5 5.4 Unified Modeling Language (UML) ... 5-5 5.4.1 Abstract Modeling in UML... 5-5 5.4.2 Use Cases... 5-6 5.4.3 UML Methodology ... 5-9 5.5 IEC61850 Information Exchange Configurations ...5-11 5.6 Procedure for Specifying IEC61850 ...5-12 5.6.1 Step 1 – Determine Functional Requirements ...5-13 5.6.2 Step 2 – Determine IEC61850 Logical Nodes and the Available Data ...5-14 5.6.3 Step 3 – Determine IEC61850 Data Exchanges Within the Substation...5-14 5.6.4 Step 4 – Determine IEC61850 Data Exchanges With External Systems...5-15 5.6.5 Step 5 – Specify Conformance Testing...5-15 5.6.6 Step 6 – Specify IEC61850 Configuration Tools ...5-15

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6 IMPLEMENTING IEC61850 IN EQUIPMENT AND SYSTEMS ... 6-1

6.1 Purpose and Audience for This Section ... 6-1 6.1.1 Purpose ... 6-1 6.1.2 Audience ... 6-1 6.2 IEC TC57 Architecture and the Components of the IEC61850 Standard... 6-1

6.2.1 Outline of the IEC61850 Document ... 6-3 6.2.2 Object Modeling... 6-4 6.2.2.1 Object Model Structure ... 6-5 6.2.2.2 Object Model Naming ... 6-7 6.2.3 Communication Services Modeling... 6-8 6.2.3.1 ACSI – Abstract Communication Services Interface ... 6-9 6.2.3.2 Implementation Settings and HMI...6-13 6.2.4 Mapping to Protocol Profiles ...6-14 6.2.5 Substation Configuration Language Modeling ...6-15 6.2.6 Power System Configuration Modeling ...6-16 6.3 Implementing IEC61850 Object Models ...6-18 6.3.1 Electric Power Measurements ...6-19 6.3.2 Switches, Circuit Breakers, and Reclosers ...6-20 6.3.3 Transformers and Tap Changers ...6-22 6.3.4 Capacitor Bank Switch Logical Nodes ...6-23 6.3.5 Protection Logical Nodes...6-24 6.3.5.1 Typical Protection Logical Nodes for a Transformer Relay ...6-28 6.3.5.2 Typical Protection Logical Nodes for a Line Distance Relay ...6-29 6.3.5.3 Typical Protection for a Feeder Relay...6-30 6.3.5.4 Typical Protection for a Generator Relay ...6-31 6.3.5.5 Typical Protection for a Bus Differential Relay ...6-32 6.3.5.6 Typical Protection for a Motor Relay ...6-32 6.3.6 Disturbance Recording Logical Nodes...6-33 6.3.7 Metering Logical Nodes ...6-34 6.3.8 Archiving, HMI, and Alarming Logical Nodes ...6-34 6.3.9 Power Quality ...6-34 6.4 Implementing Communications Service Models in Servers and Clients...6-35

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6.4.2 ACSI Models Conformance Statement ...6-38 6.4.3 ACSI Service Conformance Statement...6-44

7 INSTALLING IEC61850 EQUIPMENT AND SYSTEMS IN SUBSTATIONS... 7-1

7.1 Purpose and Audience for This Section ... 7-1 7.1.1 Purpose ... 7-1 7.1.2 Audience ... 7-1 7.2 Evaluating and Selecting Equipment and Suppliers ... 7-1 7.2.1 Support for Functional Requirements ... 7-1 7.2.1.1 General ... 7-2 7.2.1.2 Application Functionality ... 7-3 7.2.1.3 Product Tools ... 7-3 7.2.2 Support for Substation Automation Communication Objectives ... 7-3 7.2.2.1 Network Support... 7-4 7.2.2.2 Support for Utility-Specific Object Models ... 7-4 7.2.2.3 Support for Utility-Specific Communication Services ... 7-4 7.2.3 Support for Collateral Communications ... 7-4 7.2.4 Technical Support and Commitment... 7-4 7.3 Monitoring and Managing System Development ... 7-5 7.3.1 Project Management ... 7-5 7.3.2 Meetings... 7-6 7.3.3 Change Order Management ... 7-6 7.4 Evaluation Process ... 7-7 7.5 Statement of Work ... 7-8 7.6 System Integration and Testing... 7-8 7.6.1 Specification ... 7-9 7.6.2 Vendor Selection ... 7-9 7.6.3 Certification ... 7-9 7.6.4 Factory Acceptance Test ... 7-9 7.6.5 Site Acceptance Test...7-10 7.6.6 What Is Tested and When ...7-10

7.6.7 Conformance Testing of OM-SA Products ...7-11 7.6.8 Test Plan Outline ...7-13 7.7 IEC61850 Testing ...7-14

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7.7.2 Conformance Test Process ...7-15 7.7.3 Standard Test Procedure Groups ...7-16 7.7.4 Control Test Example ...7-16 7.7.5 Sample Test Cases ...7-19 7.8 System Maintenance and Support...7-21

A GLOSSARY/ACRONYMS... A-1 B A BRIEF HISTORY OF UTILITY INDUSTRY STANDARDS DEVELOPMENT ... B-1 C LISTING OF KEY INFORMATION ... C-1

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LIST OF FIGURES

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

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

Substation, One Environment Between the Substation and the Control Center, and

One Environment Within the Control Center...4-21 Figure 4-2 Data Acquisition and Control for Distribution Operations (UML Use Case)...4-22 Figure 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 ...4-35 Figure 5-1 UML Use Case – Implementing Substation Automation ... 5-8 Figure 5-2 Basic Communication Services Concept Model ...5-12 Figure 6-1 Current Reference Architecture of IEC TC57 ... 6-2 Figure 6-2 Suite of Components Within IEC61850 ... 6-3 Figure 6-3 Object Model Hierarchy... 6-5 Figure 6-4 Example of the Relationship of Logical Device, Logical Nodes, Data Objects,

and Common Data Classes... 6-7 Figure 6-5 IED Object Naming ... 6-8 Figure 6-6 Setting Group Model ... 6-9 Figure 6-7 Buffered Reporting Model ...6-10 Figure 6-8 Unbuffered Reporting Model ...6-10 Figure 6-9 Log Model ...6-11 Figure 6-10 Substitution Model ...6-11

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

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LIST OF TABLES

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

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

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

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

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

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1

AN OVERVIEW OF IEC61850 SUBSTATION

AUTOMATION GUIDELINES

1.1 Identifying the Purpose, Scope, and Audience for IEC61850 Substation Automation Guidelines

1.1.1 Purpose

This report provides guidelines for project managers, substation planners and engineers, project engineers, vendors, and substation integrators on the informational issues related to

implementing IEC61850 in substation automation (SA). Substation automation is a new

challenge for the utility industry, particularly when the new capabilities of IEC61850 are utilized to 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 the paradigm 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 specifying and implementing IEC61850 in SA are discussed. The guidelines describe the functional

requirements that must drive the design of the information system, the methodology for utilities to determine the functions that are required in their specific situations, and the recommended information 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 is organized 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 the

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An Overview of IEC61850 Substation Automation Guidelines

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 of the 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 of interest, such as planning or deployment, and move directly to that section of the report. The document, therefore, is designed so that each section can stand alone.

Table 1-1

The Audience for Each Report Section

Section Title Audience

Section 1 “An Overview of IEC61850 Substation Automation Guidelines”

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 Substation

Allocation Equipment, Systems, and Applications”

Substation planners and engineers

Section 5 “Specifying Functional Requirements and IEC61850 for Substation Automation”

Information technology engineers

Section 6 “Implementing IEC61850 in Equipment and Systems” Substation engineers and vendors Section 7 “Installing IEC61850 Equipment and Systems in

Substations”

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An O ver vi ew of IEC 61850 Subs ta ti on Aut o m a ti on G u id el in es 1-3 re 1-1 ien ce f o r Each Sect io n o f t h e SA G u id elin es

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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 interview1 on August 14th, 2003 (during the east coast blackout),

Kurt Yeager, CEO of EPRI, stated “The first, the most important factor that we have to apply to the 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 of the first steps 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 management necessary for cost-effective operations. Automation does not simply replace manual procedures. It permits the power system to operate in an entirely new way based on accurate information 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 two infrastructures that must be managed—the power system infrastructure and the communications information infrastructure.

Substation automation was not feasible a few years ago. Communication technologies simply were not available to handle the kinds of demands put on them by the complexity of substation automation requirements. For instance, one of the main enablers of substation automation was the recognition that the vast bundles 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. Communication standards have now been developed that can address many of these demands. In particular, 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.

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Figure 1-2

Two 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 than simply implementing a new substation using the traditional approaches. It is, therefore, very important for a substation engineer to fully appreciate the different steps required, even though these steps must be tailored to each individual situation.

Planning for substation automation requires a different approach than substation planners have typically used in the past. In addition to the design of physical and electrical requirements, SA also 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 the learning 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: a

functional 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 supporting stakeholder needs. This includes reaching out to stakeholder groups to determine what they need from SA systems.

4. Develop system management requirements that include security, performance, and other functions 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 do not over-specify by identifying the specific hardware. The specifications must cover the substation equipment as well as the communication systems, including the object models defined 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 systems

are 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 1-3

Organization of Project Teams

1.4 Developing Functional Requirements for Substation Automation Equipment, Systems, and Applications

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

support to substation planners. The IntelliGrid Project was funded by the Consortium of Electric Infrastructure to Support a Digital Society (CEIDS) for E2I, one of EPRI’s family of companies, to provide a framework of communication and information standards to meet the needs of

existing and future power system functions. The IntelliGrid Architecture (see Figure 1-4) derived the communication and information requirements of power system functions by first creating a comprehensive list of functions, analyzing the needs of these functions, and refining these needs by in-depth analysis of some of the key functions.

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

Figure 1-4

IntelliGrid Architecture Framework

1.5 Specifying Functional Requirements and IEC61850 for Substation Automation

Specifying the functional requirements for substation automation requires a different approach than substation engineers have used in the past to construct new substations. The functional requirements must encompass far more than just purchasing equipment—they need to describe the requirements of all stakeholders in taking advantage of the capabilities of SA based on the state-of-the-art technologies of IEC61850. These stakeholders include operations, protection,

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By definition, functional requirements should focus on what rather than on how. The most effective way to develop these functional requirements is to use modeling techniques. These modeling techniques allow functions to be described with their interactions illustrated through formalized 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 be refined as requirements are better understood and finalized into formal functional specifications before actual designs are created and long before any hardware or software is purchased. Substation automation involves not only equipment, but also the communications infrastructure to monitor and manage the equipment, particularly when all of the IEC61850 capabilities are to be utilized. Therefore, in addition to the design of physical and electrical requirements,

substation automation also requires the analysis of information requirements and a determination of the flow of information between equipment and systems. Modeling techniques can also be used to develop the best infrastructure or these communication information requirements. A brief overview of some key modeling techniques, a discussion of the use of IEC61850 substation 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 Substation Configuration 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 work together. This section is designed to describe the IEC61850 standards in more user-friendly terms 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 for substation automation, although it also forms the basis for object model extensions. Section 6 also addresses specific equipment, discussing the existing models that may be relevant and the need for additional models. Finally, Section 6 identifies the conformance tables that must be agreed upon for specific implementations.

When implementing systems as complex and as new as SA, substation engineers will need to work closely together with the vendors of SA equipment and systems. Although the vendors will perform the detailed implementation of the IEC61850 object models and service models, the substation engineers must be able to decide what settings should be established for a particular substation. 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 that must be resolved as SA equipment and system are implemented for the utility.

Figure 1-6

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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 management

personnel, information technologists, consultants, and multiple vendors. As discussed in Section 3, strong project management is required to facilitate these interactions. There are some

interactions that explicitly involve IEC61850. Therefore, this section focuses on the issues associated with installing and testing IEC61850 equipment and systems in substations (see Figure 1-7).

Section 7 is intended to help the integrators who are involved in developing, implementing, and testing 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 1-7

Architecture 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 it easier to locate.

By emphasizing vital information, key points enable personnel to take action for the benefit of their 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 category—key technical points. Each key point has an identifying icon, as shown here, that draws attention to it, making it easy for personnel to quickly 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 listing restates each key point and provides reference to its location in the body of the report. By reviewing this listing, users of this guide can determine if they have taken advantage of key information that can benefit their plants.

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2

THE 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 all readers 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 current practice or modified it significantly (not instantly, but quickly enough to indicate that something rather important had occurred). In each case, there was a present need, a confluence of

technologies, and a vision of how to combine technology and need for economic gain and unprecedented advantage. Substation automation is not just the automation of a substation—it is part of a major paradigm shift for all power system operations.

Substation automation is not just the automation of a substation—it 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. They represent the largest and most capital-intensive system devised by man. Yet, utilities leverage a remarkably small amount of information from this lifeblood of their business. As past and recent events have demonstrated, the urgency to improve this situation is increasing. It is necessary to ensure a secure national grid. As the amount of distributed energy resources (DERs) grows, it will be necessary to accommodate a higher grid complexity. Improved efficiency, better power quality, and deterministic power flow are necessary in support of a more competitive business climate. 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 delivery system, selectively delivering it to multiple utility departments according to need. This

technological infrastructure is shared so that all stakeholders have common access to station data and functionality, subject to security safeguards, regulations, and corporate policy. Modern

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The Vision for Substation Automation

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

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

When this integration of data and functionality is accomplished, the stage will be set for one additional huge benefit—the implementation of local and system-wide automation that delivers economic gains on many fronts. The result will be a reduction of nonproductive effort, the operation of equipment assets at higher power levels (while also monitoring them for operational safety under current operating conditions), and the interactive use of equipment assets to affect voltage 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 of the first steps 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 necessary planning and asset management for cost-effective operations. Automation does not simply replace manual procedures—it permits the power system to operate in an entirely new way, based on accurate information provided in a timely manner to the decision-making applications and devices. Why should an organization tolerate semi-informed decisions that may eventually cost tremendous time and money, especially when the means are available to tightly justify (or discredit) proposed improvements? These guidelines enable decentralized access to the station resources. This approach enables each department to gain access to those allowed resources that are most valuable for improving its process, cutting its cost, and exploiting new opportunities that open up. It lets each group meet its own responsibilities, applying innovation to the area it knows most intimately. If the corporate staff meets its responsibilities to provide direction and leadership, there is no doubt that the whole utility enterprise can achieve significant

advancement. To summarize, these advantages can be used to transform how organizations conduct business.

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Information has become the driving necessity in power system operations. In an interview on

August 25, 2003 regarding the August 14th east 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 to provide power to it through a mechanical design system that was designed over 50 years ago. It’s a marvelous system, but we've been effectively borrowing against the future to pay for the present, and the future has caught up with us; we need to build the system to serve 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 will not 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 detect instantaneously a difficulty and correct for it locally so that cascading effects can be eliminated and fundamentally improve the reliability of the system so that computers and other sensitive equipment that has come in over the last decade is not upset by power disturbances.

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

2.3 Enabling Information Technologies That Enhance Substation Automation Capabilities

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

For example, one of the main enablers of substation automation was the recognition that the vast bundles 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 practical after the higher speed switching technologies were developed. When networking became standardized with highly reliable products available from multiple vendors, automation became feasible because data could be collected from multiple devices without the added expense of running new wires.

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Recognition of the fact that vast bundles of point-to-point wiring could be eliminated through the use of Ethernet networks was one of the main enablers of substation automation.

With this basic communications capability in place, other technologies commonly used in other industries could be easily adapted to the substation environment. Rather than just replacing wires with Ethernet networks, the door would open to additional technologies to improve the

management of data, the security of information, and the simplification of hardware and software maintenance. The following list contains examples of the state-of-the-art technologies that might then 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 to IEDs in the substation for remote configuration and setting of parameters without the need for 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 process of being standardized. Through RBAC, control centers can assign, monitor, and ensure individual access rights to the information objects of the substation and subscribe to information objects.

• Consolidation of hardware: Conversion of protocols and formats is avoided because the

local communications platform within the substation (substation bus) and telecontrol is the same. Instead of a gateway, a proxy can be used within the substation to present the

information objects to the control center.

• Object-modeling (Establishing standardized self-describing object names): By using

object-modeling technology, IEC61850 established standardized self-describing object names for substation information instead of nondescriptive numerical addresses. This allows each data item to be uniquely identified (similar to a person living at a unique address) and greatly enhances the ability of systems to manage the data.

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

• Standardized naming and mapping to proprietary databases in proxy servers: The

device-oriented names of information objects can be mapped in the proxy server to 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 of

digital components increases within substations and as the amount of data from each component increases exponentially. With self-descriptive unique names, IEC61850 objects permit systems to automatically manage the data without relying on data administrators to laboriously 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 Microsoft

Windows3 system 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 with minimal user support.

• Designing toward a seamless architecture: In general, a seamless architecture leads to

potential lower costs for design, configuration, installation, operation, and maintenance combined with higher performance as compared to current solutions. Although much work still needs to be done, the IntelliGrid Architecture has built the foundation for such a seamless architecture.

2.4 The Benefits of Substation Automation for Different Users

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

Automation leads to powerful new capabilities for users, which in turn leads to the need for more automation.

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

• Substation automation offers implementation benefits.

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Reduced quantities of equipment: Through the use of shared technology for data

sourcing, control, protection, station metering, processing, and communication—all for the benefit of multiple utility departments and other clients.

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Replacement of discrete station wiring with flexible communication networks: To

accommodate continual system change and migration.

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Networks implemented with fiber-optic cable: Mutually isolates pieces of connected

equipment to limit collateral equipment damage under adverse electrical conditions such as faults and close-proximity lightning strikes.

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Integration of digital information and functionality: In disparate devices that currently

operate in separate realms such as fault recorders, protective relays, sequence of event recorders, fault locators, network transducers, regulators, or controllers.

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Gradual displacement of analog devices: Typically less flexible in use, more difficult

to diagnose, and more costly to maintain.

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New digital equipment capabilities: Such as distance-to-fault locators and sag detectors

can easily be integrated with the other station equipment to provide new functionality and more comprehensive system information.

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Station HMI (human machine interface) consoles: Enables the displacement or

replacement 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 locally consolidated.

• Substation automation benefits the utility staff.

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Maintenance staff: Can remotely isolate and diagnose problems. This requires fewer

trips to the station, saving time and money, resulting in typically shorter outages. This capability is provided by microprocessor-based equipment supporting self-monitoring and self-diagnosis.

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Planners, engineers, and asset management personnel: Can monitor and capture the

operational behavior of feeders and line equipment over time, profiling their service characteristics against independent factors such as temperature, season, time of day, and time of week. Statistical analysis can be used to distill useful information for planning.

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Operators and operational planners: Additional real-time information for use in

operational planning (within the next hour or so).

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Operators: Additional alarming capabilities and alarm management (how important is

each alarm under certain conditions and who should see them); or multiple sources for data and alarms to ensure no critical information is lost or unavailable to operators.

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

conditions

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Operations engineers: Additional information available for contingency analysis and

identification of potential problems; management during emergency conditions, emergency recovery, and post-emergency analysis.

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Data administrators: Avoid time-consuming and error-prone tracking of chains of data

links each time a change is made in the field.

• Substation automation benefits control center operations.

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SCADA/EMS systems: Additional data are available to be monitored if operators and/or

SCADA/EMS applications need them. Alternatively, if the SCADA/EMS system does not need data that are required by another group, then the other group can collect the data directly from the substation master without burdening the SCADA/EMS system.

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Contingency analysis (security analysis): Additional data from multiple sources for

redundancy, thus increasing the reliability of the results.

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Intelligent alarm processing: With the additional data, intelligent alarm processing can

filter out the less important alarms from the more important ones and can also analyze these data to determine the true issue causing the alarm. These more important alarms can then notify operators, and/or cause additional applications to execute (such as

contingency analysis).

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Emergency response: Control commands, whether issued locally or remotely, can

respond rapidly to emergency situations in a coordinated manner, not only within a substation, but also between substations and between utilities.

2.5 Information Technology Requirements That Drive Substation Automation 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 and systems used to monitor, control, protect, and automate the substation. Because this information infrastructure is critical to human safety, equipment safety, and system reliability, it has always been an essential part of substation planning and implementation. Examples of these components include 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 of separate subsystems with little commonality. IEC61850 now provides the means to integrate

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

Figure 2-1

Power 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 information infrastructure a tremendous enhancer of power system operations, but it is also a new burden because it too needs to be designed, implemented, and managed.

Both the power system and the information infrastructure must be designed and 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 at supporting power system operations and better at managing their own infrastructure. Although these information technologies are still evolving, it is crucial to use what technologies are available and to plan for incorporating new concepts as they are solidified and standardized.

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The IntelliGrid project developed an architecture that addresses these information infrastructure requirements. An overview of the key issues of the IntelliGrid Architecture follows. (More detail

can be found at http://IntelliGrid.info.)

2.5.1 IntelliGrid Architecture Framework Contents

The IntelliGrid Architecture Framework was constructed based on the previously mentioned concepts. It is based on an architecture framework bounded by the information infrastructure requirements of the power system industry. The framework includes:

• The business needs of the power system industry, as captured in the power system operations

functions and categorized into the IntelliGrid Environments

• Strategic vision based on the high-level concepts of distributed information

• A tactical approach based on technology-independent techniques of common services,

information models, and interfaces

• Standard technologies and best practices that can be used in the power industry

• Methodology for automation architects, power system planners, project engineers,

information specialists, and other IntelliGrid Architecture users to quickly identify the exact parts of the IntelliGrid Architecture that are directly relevant to them and access the

IntelliGrid Architecture recommendations

The IntelliGrid Architecture framework generalizes and extracts the architecturally significant requirements by cross-cutting energy industry requirements involving distributed information, and provides a technology-independent architecture for project engineers to use as they

determine solutions for specific implementations. Figure 2-2 depicts the IntelliGrid Architecture Framework and clearly identifies how these concepts fit together.

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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 words—this 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, it is best to ask the power system experts to develop a step-by-step analysis of each part of the system. An information expert can then model this analysis using tools such as the Unified Modeling Language (UML). Power system experts can then review these models to determine if they truly represent the needed functions. When a model is correct, it can more easily and reliably be implemented in software and hardware.

Modeling is one of the most powerful tools available for understanding, documenting, and managing the complexity of the infrastructures required to operate the energy system of the future. 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 be reconstructed.

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

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modern high-rise building. Virtual models are increasingly being used to model even more complex concepts such as weather patterns and cosmology, and of particular interest to the IntelliGrid project, to information management.

The following abstract modeling methodologies and concepts were incorporated into the IntelliGrid Architecture:

• Reference model for open distributed processing (RM-ODP) and the Unified Modeling Language (UML): Years of engineering have been invested in defining how enterprise-level

architecture should be defined. RM-ODP is an international standard (ISO/IEC 10746) prescribing a methodology for architectural development. The methodology provides guidance on breaking the problem into understandable pieces and helps to ensure that important design details are not forgotten.

By design, RM-ODP provides the methodology, but does not include a recommended

notation for documenting an architecture. The most popular standardized notation for system modeling is UML, which provides a standardized way to graphically document the systems and components of an architecture. RM-ODP provides the architectural guidance and UML provides the standardized notation. It should be noted that as this document was being prepared, the standards for applying UML to RM-ODP concepts were under development. As the energy industry moves forward in the development of advanced automation systems, the adoption of these sophisticated methods should be encouraged.

• Object-modeling and information models: These information models define data names

and structures. They can be described informally as consisting of nouns. Nouns consist of data names and their structure. A noun can be a simple data point (such as a point called State) that consists of one 8-bit integer, or more complex data points that include the value, the quality of the value, and the description of the point. Nouns can also be complete descriptions of a utility’s power system (for example, ABCPowerSystem) that consist of thousands of components in some well-known structure. There can be millions of nouns in any system.

In the power industry, IEC61850 includes such a model, which is focused on field device characteristics. Another information model is IEC61970 Common Information Model (CIM), which is focused on modeling the information about the power system structure that is to be exchanged among application programs. It has been expanded to model other types of

information to be exchanged among application programs. As an information model specifies what information is exchanged, it is part of an RM-ODP information view.

• Abstract service/interface models: A service model describes the functionality that a

software application provides. IntelliGrid Architecture’s common services describe the common functionality needed to operate a utility. For example, the common service of Logon specifies the common function of initiating a secure session with a software application.

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• Interface model: This model defines the mechanics of how data are passed to get the right

information to the right destination at the right time. Interface models can be described informally as consisting of verbs. Verbs are the abstract services used to exchange the nouns, such as request, send, report if changed, or add to log. Although different verbs/services are used in different environments, the number of different types of abstract verbs/services generally ranges from 10–20.

In the power industry, IEC61850 includes such a model, which is focused on field device operation. Another service model is IEC61970 Generic Interface Definition (GID), which is focused on how information about the power system structure is to be exchanged among application programs. An interface model specifies how information is exchanged and is part of an RM ODP computational view.

• Naming and avoiding ambiguity (name collisions): One aspect of information models is

the need to uniquely identify all objects within the model. In addition, as the number of names being used proliferates, there is a need to avoid name collisions (that is, the same name used with two different meanings). This is handled by namespace allocation.

Namespace allocation is a very simple concept—different groups can have the authority to name their own objects as long as those names are unique within the group’s domain.

However, it is not necessary for them to be universally unique. This permits different groups (entire industries, standards organizations, types of products, or departments within a

company) to define their own terminology and abstract model names and structure. Namespace allocation for the electric power industry should be performed in a top-down manner that clearly captures the different arenas. Although some namespaces should be as broad as possible (that is, valid across the entire electric power industry), additional

namespaces should be allowed as part of a formal scheme to permit specific utilities, specific vendors, specific functions, and other groups to apply for and register their own namespaces. Examples of namespaces within the IEC TC 57 are the allocation substations to the

IEC61850 namespace and the allocation of transmission power system applications to the IEC61970 namespace.

• Self-description and discovery: Future advanced automation systems must have more

capable methods for managing networks, connected equipment, and the applications that run on this equipment. This will require more sophisticated systems to assist system

administrators in managing large-scale networks and massively distributed equipment. Concepts such as self-description and discovery will become a necessary part of future systems or maintenance could easily become unwieldy.

Self-description and discovery is a fancy title for describing what happens when a new printer is plugged into a PC: Consider the following example:

–

First message: “New hardware detected.”

–

Second message: “Driver xxx is being installed.”

EPRI Guidelines for Implementing Substation Automation Using IEC 61850

Guidelines for Implementing Substation

Automation Using IEC61850, the

International Power System Information

Modeling Standard

Guidelines for Implementing

Substation Automation Using

IEC61850

, t

he International Power

System Information Modeling

Standard

CITATIONS

PRODUCT DESCRIPTION

CONTENTS

LIST OF FIGURES

LIST OF TABLES

1

AN OVERVIEW OF IEC61850 SUBSTATION

AUTOMATION GUIDELINES

2

THE VISION FOR SUBSTATION AUTOMATION

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