substation automation systems...page 7-sa -1 pm5-0403-wbx substation automation systems based on the...

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SUBSTATION AUTOMATION SYSTEMS

Based on the IEC 61850 Communications Standard

A Technical Specification for Seven Substations and Three Terminal Stations

Prepared for

Metropolitan Electricity Authority

Prepared by Power System Maintenance Department

January 16, 2012

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TABLE of CONTENTS

1 SCOPE OF WORK..........................................................................................................6 2 SYSTEM ARCHITECTURE and HIERARCHY ................................................................9 2.1 BASIC ARCHITECTURE.................................................................................................9 2.1.1 Station Communications................................................................................................ 10 2.1.1.1 Substation LAN ............................................................................................................. 10 2.1.1.2 Gateway for Enterprise Communications....................................................................... 10 2.1.2 Station Level.................................................................................................................. 11 2.1.2.1 System Linchpins: Local Repository and System Logs.................................................. 12 2.1.2.2 Common IED Capabilities.............................................................................................. 13 2.1.2.3 Central Control Unit (CCU) ............................................................................................ 14 2.1.2.4 Operator Interface [MMI] ............................................................................................... 18 2.1.2.4.1 Three Platforms............................................................................................................. 18 2.1.2.4.2 Operator Interface Responsibilities................................................................................ 19 2.1.2.5 Print Server ................................................................................................................... 21 2.1.2.6 Time and Date Server (TDS) ......................................................................................... 21 2.1.3 Bay Level ...................................................................................................................... 22 2.1.3.1 Bay Control Units / IEDs................................................................................................ 22 2.1.3.2 Bay Control Units with Protection Relays (BCUs) .......................................................... 23 2.2 FAILURE and MAINTENANCE MANAGEMENT ........................................................... 33 3 FUNCTIONAL REQUIREMENTS.................................................................................. 37 3.1 SYSTEM CONFIGURATION......................................................................................... 37 3.1.1 IEC 61850 Configuration Tools and Process ................................................................. 42 3.1.2 Open System Provision ................................................................................................. 42 3.2 FILE MANAGEMENT .................................................................................................... 44 3.2.1 Objectives ..................................................................................................................... 44 3.2.2 An Approach.................................................................................................................. 44 3.2.3 File Agent Responsibilities............................................................................................. 45 3.2.4 File Transfer Initiators.................................................................................................... 48 3.3 DATA ACQUISITION..................................................................................................... 48 3.4 DATA PROCESSING.................................................................................................... 48 3.4.1 Data Quality................................................................................................................... 48 3.4.2 Event Processing .......................................................................................................... 49 3.4.3 Status Processing ......................................................................................................... 50 3.4.4 Measurement Processing .............................................................................................. 50 3.4.5 Control Command Processing....................................................................................... 51 3.4.5.1 Control Initiators ............................................................................................................ 52 3.4.5.2 Types of Control Operations.......................................................................................... 52 3.4.5.2.1 Control of Two-State Devices ........................................................................................ 52 3.4.5.2.2 Control of Three-State Devices ..................................................................................... 53 3.4.5.2.3 Control of Integer-State Devices.................................................................................... 53 3.4.5.2.4 Incremental Device Control (Jog Control) ...................................................................... 53 3.4.5.2.5 Integer-Controlled Step Position Devices ...................................................................... 53 3.4.5.2.6 Set-Point Control ........................................................................................................... 53 3.4.6 Calculations................................................................................................................... 53 3.5 PROGRAMMABLE LOGIC APPLICATIONS ................................................................. 54 3.5.1 Heartbeat Function........................................................................................................ 54 3.5.2 TRIP Counters for Circuit Breakers ............................................................................... 55 3.5.3 Rate of Change (ROC) Limit Checking .......................................................................... 55 3.5.4 Breaker Operating Time Checks.................................................................................... 56

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3.5.5 Feeder Fault and Breaker Lockout Recognition............................................................. 56 3.5.6 Automated Control Sequences...................................................................................... 56 3.5.6.1 Line Throw-over Scheme (LTO) .................................................................................... 56 3.5.6.2 Bus Throw-over Scheme (BTO)..................................................................................... 57 3.5.6.3 Bus Coupler Throw-over Scheme (CTO) ....................................................................... 57 3.5.6.4 Load Shed and Restoration ........................................................................................... 60 3.5.6.5 Voltage Selection (VS) .................................................................................................. 61 3.5.7 Protection Applications (Breaker failure protection, 50BF) .............................................. 61 3.6 HISTORICAL DATA ...................................................................................................... 62 3.7 OPERATOR INTERFACE [MMI] FUNCTIONS.............................................................. 63 3.7.1 General Requirements .................................................................................................. 63 3.7.1.1 Windows Usage ............................................................................................................ 63 3.7.1.2 User Interface Features................................................................................................. 64 3.7.1.3 Toolbars ........................................................................................................................ 64 3.7.1.4 Dialog Boxes ................................................................................................................. 65 3.7.1.5 Information Boxes ......................................................................................................... 65 3.7.1.6 HELP Function .............................................................................................................. 65 3.7.1.7 Display Capabilities (General) ....................................................................................... 65 3.7.2 Operator Functions........................................................................................................ 66 3.7.2.1 Display Call-Up.............................................................................................................. 66 3.7.2.2 Supervisory Control Procedures.................................................................................... 67 3.7.2.3 Device Tagging ............................................................................................................. 68 3.7.2.4 Placing Data and Command Points ‘In-Service’ and ‘Out-of-Service’ ............................ 68 3.7.2.5 Using Substituted Values............................................................................................... 69 3.7.2.6 Display Hard Copy......................................................................................................... 69 3.7.2.7 User Log-On.................................................................................................................. 69 3.7.3 Modes of Operation....................................................................................................... 69 3.7.3.1 Operator Mode .............................................................................................................. 70 3.7.3.2 Supervisor Mode ........................................................................................................... 70 3.7.3.3 Maintenance Mode........................................................................................................ 70 3.7.3.4 Programmer Mode......................................................................................................... 70 3.7.4 Event and Alarm Processing ......................................................................................... 70 3.7.4.1 Events ........................................................................................................................... 70 3.7.4.2 Definition of Alarms ....................................................................................................... 71 3.7.4.3 Alarm Processing .......................................................................................................... 72 3.7.4.4 Recording of Alarms and Events ................................................................................... 72 3.7.5 CompositeLog Capability............................................................................................... 73 3.7.6 Browsing to Capture Repository Data Components....................................................... 74 3.7.7 Displays......................................................................................................................... 76 3.7.7.1 Directories ..................................................................................................................... 76 3.7.7.2 Station Displays............................................................................................................. 76 3.7.7.3 Point Profile Displays..................................................................................................... 76 3.7.7.4 Communications Status / Operational Status Display .................................................... 76 3.7.7.5 Summary Displays......................................................................................................... 76 3.7.7.6 Log Displays.................................................................................................................. 78 3.7.7.7 Bulletin Board ................................................................................................................ 78 3.7.7.8 System Management Displays ...................................................................................... 78 3.7.8 Control Capabilities ....................................................................................................... 78 3.7.9 Other Capabilities.......................................................................................................... 79 3.8 REMOTE FILE MANAGER............................................................................................ 80 3.9 EQUIPMENT POWER SUPPLY.................................................................................... 80 3.9.1 Power Circuits within other Equipment .......................................................................... 80 3.9.2 Stand-Alone Power Units............................................................................................... 80 3.9.3 Wetting Voltage ............................................................................................................. 81 4 SYSTEM DESIGN CONSTRAINTS AND TESTING...................................................... 82

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4.1 GENERAL REQUIREMENTS........................................................................................ 82 4.1.1 System Design and Engineering.................................................................................... 82 4.1.2 System Reliability and Availability.................................................................................. 82 4.1.2.1 Critical Functions........................................................................................................... 83 4.1.2.2 Non-Critical Functions ................................................................................................... 84 4.1.3 System Security ............................................................................................................ 84 4.1.4 System Sizing................................................................................................................ 85 4.1.4.1 Initially Delivered Systems............................................................................................. 86 4.1.4.2 Expansion and Upgrading ............................................................................................. 87 4.1.5 Reference Standards..................................................................................................... 87 4.1.5.1 Standards Groups ......................................................................................................... 87 4.1.5.2 Specific Relevant Standards.......................................................................................... 88 4.2 SYSTEM PERFORMANCE REQUIREMENTS.............................................................. 90 4.2.1 The General Rule .......................................................................................................... 90 4.2.2 Time Synchronization and Time-Stamping .................................................................... 90 4.2.3 CCU .............................................................................................................................. 91 4.2.3.1 ‘System Log’ Entries...................................................................................................... 91 4.2.3.2 Backup of Real-Time Data............................................................................................. 91 4.2.3.3 Time Synchronization .................................................................................................... 91 4.2.4 Operator Interface [MMI] ............................................................................................... 91 4.2.4.1 Operator Request Completion Time .............................................................................. 91 4.2.4.2 Display Update Time ..................................................................................................... 91 4.2.4.3 MMI Boot-Up Time and Start-Up Time........................................................................... 92 4.2.4.4 System Restarts ............................................................................................................ 92 4.2.5 Communications............................................................................................................ 92 4.2.5.1 Network Associations .................................................................................................... 92 4.2.5.2 SubLAN Data-Interchange Failure between Station-Level and Bay-Level ..................... 93 4.2.5.3 Communication Errors................................................................................................... 93 4.3 HARDWARE REQUIREMENTS.................................................................................... 93 4.3.1 Equipment Power Supply .............................................................................................. 93 4.3.1.1 General Specifications................................................................................................... 93 4.3.1.2 System-Related Specifications ...................................................................................... 94 4.3.2 IED Clock Circuits and Time-Stamping Capabilities....................................................... 94 4.3.3 Substation LANs............................................................................................................ 95 4.3.4 CCU .............................................................................................................................. 95 4.3.5 Operator Interface [MMI] ............................................................................................... 96 4.3.5.1 MMI Units based on Desktop PC................................................................................... 96 4.3.5.2 MMI Units based on Notebook PCs............................................................................... 97 4.3.6 Time and Date Server ................................................................................................... 98 4.3.7 CGW: Communications Gateway .................................................................................. 98 4.3.8 Serial Communication Interfaces................................................................................... 99 4.3.9 Bay Control Units with Protection Relays (BCUs) .......................................................... 99 4.3.9.1 Installation Issues.......................................................................................................... 99 4.3.9.2 Interface, Electromagnetic, and Environmental Compatibility ........................................ 99 4.3.9.3 BCU I/O Point Types ..................................................................................................... 99 4.3.10 Printing Facilities ......................................................................................................... 100 4.3.11 I/O Point Types............................................................................................................ 100 4.3.11.1 Analog Inputs .............................................................................................................. 101 4.3.11.1.1 AC Analog Inputs (AC-AI) .................................................................................... 101 4.3.11.1.2 DC Analog Inputs (DC-AI).................................................................................... 102 4.3.11.2 Digital Inputs................................................................................................................ 102 4.3.11.2.1 Single Contact, Two-State ................................................................................... 103 4.3.11.2.2 Double Contact, Two-State.................................................................................. 103 4.3.11.2.3 Two-State with Memory (MCD)............................................................................ 103 4.3.11.3 Digital Outputs............................................................................................................. 103 4.3.11.3.1 ON/OFF Device Control....................................................................................... 105

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4.3.11.3.2 RAISE/LOWER Control ....................................................................................... 105 4.3.11.3.3 SET-POINT Control ............................................................................................. 105 4.3.11.3.4 Variable-Length Control ....................................................................................... 105 4.3.11.3.5 Direct-Operate (Pulse Output) Control ................................................................. 105 4.3.12 Control Circuit Requirements and Internal wiring Conductors...................................... 106 4.3.13 Console Furniture........................................................................................................ 106 4.4 SYSTEM SOFTWARE REQUIREMENTS ................................................................... 106 4.4.1 A Non-Comprehensive List of System Software .......................................................... 106 4.4.2 General Requirements ................................................................................................ 108 4.4.2.1 Operating Systems...................................................................................................... 108 4.4.2.2 Software Components ................................................................................................. 108 4.4.2.3 Software Interfaces...................................................................................................... 108 4.4.2.4 Programming Languages ............................................................................................ 108 4.4.2.5 Buffer Overflows.......................................................................................................... 109 4.4.2.6 System Loading........................................................................................................... 109 4.4.2.7 Unit Behavior............................................................................................................... 109 4.4.3 IEC 61850 Communications and Stack Software ........................................................ 109 4.4.4 Programmable Logic Control (PLC) Software .............................................................. 109 4.4.5 Configuration Software ................................................................................................ 109 4.4.5.1 Operational Parameters for IEC 61850 Information Models......................................... 109 4.4.5.2 User-Defined Parameters for Individual Software Components ................................... 110 4.4.5.3 Report Scheduling....................................................................................................... 110 4.4.5.4 Operator Permissions.................................................................................................. 110 4.4.6 Display / Report Generation and Editing Software....................................................... 110 4.4.7 DNP3 Protocol Software Implementation..................................................................... 110 4.4.8 Protocol Analyzer Software ......................................................................................... 112 4.4.9 Demo Software and Literature..................................................................................... 112 4.5 SYSTEM TESTING REQUIREMENTS........................................................................ 112 4.5.1 Testing Categories ...................................................................................................... 112 4.5.2 System Performance Testing Requirements................................................................ 114 4.5.3 Compatibility Test Criteria (for Type-Testing)............................................................... 115 5 TRAINING and SYSTEM MOCK-UP ........................................................................... 119 5.1 Training System .......................................................................................................... 119 5.2 Training Courses ......................................................................................................... 120 6 Simulation Test Tool and Multifunction Primary Test Set ............................................. 120

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1 SCOPE OF WORK

This technical specification describes requirements for a substation automation (SA) system to be placed in stations belonging to the Metropolitan Electricity Authority (MEA). Bidders must comply with the requirements in this specification. The successful bidder shall provide completely integrated, turnkey systems and accept responsibility for those systems successfully fulfilling the requirements and intent of this specification.

1.1 GENERAL INFORMATION

There are three types of facilities that interconnect and power MEA’s 24/12 kV distribution systems: Terminal stations, switching stations, and substations. Terminal stations are connection points to MEA’s generation and transmission supplier, EGAT. Terminal stations may directly feed MEA’s 24/12 kV distribution systems, as well as supply 69 or 115 kV power to substation sites. The sole responsibility of MEA substation sites is to power MEA’s 24/12 kV distribution systems. The 10 sites covered by this specification include both terminal stations and substations. Switching station is only used to manage the flow of power. MEA has only one switching station, and it is not involved in this specification.

To ensure there is no confusion concerning terminology, this specification applies the standalone word station in a general way, broadly including both terminal stations and substations. When discussion applies specifically to substations or terminal stations, as described above, those specific terms will be used.

The term substation automation refers to a general practice, described below, that may be applied to both substations and terminal stations. Similarly, the term Substation LAN is deeply rooted in industry literature and shall be understood as the networked communications facility deployed at both substations and terminal stations within MEA’s power system.

1.2 DELIVERABLES

The system deliverables comprise turnkey systems for multiple sites. The successful bidder shall act as general contractor to specify, deliver, install, configure, test, commission, and document these systems in accordance with these technical specifications and the accompanying commercial terms and conditions.

Work shall include all necessary site preparations and alterations. System deliverables shall include all hardware software, applications, tools, licenses, materials (e.g. wiring, cabling, connectors, trays), labor, governmental permits and clearances, procedures, methods, compliances, demonstrations, test results, documentation, training materials, approval submittals, and estimates required to complete the work, meet these specifications, and produce robust operational systems. Licenses for installed products shall (in effect) be perpetual, not requiring renewal. Future product upgrades will be treated as a separate issue; they will be considered according to their perceived value. The commercial terms and conditions that accompany these technical specifications may have other requirements.

1.2.1 Shipment Data and Time of Completion

Bidders must state their shipment schedule and time of completion of the work in the appropriate field in the Bid and Price Schedule, provide in calendar days to be counted from the Effective Date of Contract.

1.2.2 Milestones

The Time Schedule to be followed by the Contractor during the performance of the Contractor shall adhere to the following periods of time for completing the itemized milestones as measured from the Effective Date of the Contract :-

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• Submission of project plan: thirty (30) days.

• Submission of design and document for MEA approval: one hundred and twenty (120) days.

• Submission of IEC 61850 type test reports and DNP3 Subset level 2 conformance Certificate with conformance test reports: One hundred and eighty (180) days

• Successful Factory Acceptance Test: two hundred and seventy (270) days.

• Supply, install and commissioning entire SA : five hundred and forty (540) days

• Completion of all related works specified in the specification including of the submission of as-built drawings and all documents : six hundred (600) days

1.2.3 Penalty for Late Delivery

If the IEC 61850 type test reports and/or DNP3 Subset level 2 conformance certificate are submitted to MEA later than 180 (one hundred and eighty) days after the effective date of the Contract, the Contractor shall be penalized at the rate of 50,000 (fifty thousand) baht per day until the reports and certificate are submitted to MEA.

1.2.4 FAT Start Conditions

Before the Factory Acceptance Test starts, the Contractor shall proceed as follows:-

- Submit to MEA all type test reports and conformance certificate.

- Perform the pre-communication test at MEA’s SCADA/EMS control center by using the DNP3 protocol and after the test has been passed, the Contractor shall submit to the MEA the final test report.

1.3 OTHER RESPONSIBILITIES

1.3.1 Contractor Responsibilities

MEA or an MEA-authorized agent must approve all work plans and deliverables in advance; the contractor must submit supporting documents and/or other materials, in MEA-approved formats, that explain the work plans and deliverables to MEA’s satisfaction. No work may proceed without MEA’s written approval. Following award of contract, a Scope of Work document shall be created that describes deliverables (including all work to be performed), schedule milestones, the approval process, document formats, and other relevant content. Throughout the project, the contractor is responsible for clearing variances that MEA believes do not conform to the intended and/or specified requirements. An attachment to this document specifies MEA’s general equipment construction requirements.

1.3.2 MEA Responsibilities

MEA will support the approval process for proposed work and deliverables. Otherwise, MEA’s support of the contracted work is limited to (1) providing information about the existing station sites, (2) providing information about MEA’s work and material standards for station sites, and (3) coordinating necessary site outages for work in progress.

1.4 OBJECTIVES

MEA’s electric power system network serves Bangkok and the neighboring areas of Nonthaburi and Samut Prakarn. The network includes more than 148 substations and terminal stations. The equipment and facilities within each station can be conceptually divided into two interrelated systems:

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1. The primary system, which includes those components that carry, switch, isolate, transform, interrupt, and passively condition the flow of electric power

2. The secondary system, which includes those components that allow MEA to protect, control, monitor, and automate the primary system

This specification and the ensuing design and implementation efforts are primarily concerned with the secondary system. MEA wants to achieve a secondary system environment that will allow MEA to deploy substation automation solutions that are truly responsive to MEA’s business needs, both present and future. To be successful, this environment must satisfy the following important criteria:

1. Provide a single, common, open, technological infrastructure that accommodates all facets of substation automation: protection, control, monitoring, and automation. All intelligent station devices, all system processes, and all station applications must share this single system infrastructure.

Of primary importance are the interfaces used for system, device, and application interoperability. These must be standard and representative of mainstream practice.

2. Support the flexible integration of devices, applications, and data into a functioning system, which will probably evolve as business objectives do.

In particular, system design shall maintain hardware and software independence, allowing either to be upgraded in the future without affecting the other.

3. The plans, non-recurring costs, and recurring costs associated with putting this environment in place, using it, maintaining it, and adapting it over time must be feasible and pragmatic for the power delivery stations in MEA’s system. Proposed implementation plans must address both new and existing station sites.

1.5 System Configuration

MEA has determined that the IEC 61850 communications standard and an Ethernet Substation LAN shall be used as the cornerstones of the technological infrastructure described above. This shall apply to all stations governed by this specification, except for those specifically identified by MEA as requiring a different treatment (i.e. by reason of small size or other special circumstance).

What is fundamentally required is a migration plan that allows MEA to begin reaping the benefits of an IEC 61850-based architecture, while recognizing that the realities of priorities and resource constraints will stretch the full conversion of these stations over a period of years. The full extent of this plan is illustrated by the block diagram in Figures 1

Figure 1 shows the scope of Substation Automation (SA) configuration governed by this specification. Bay Control Units, Protection Relays and IEDs are included, the core architecture for an IEC 61850-based system is introduced. Figure 1 illustrates the eventual goal: a flexible, capable secondary system environment that is fully networked and responsive to evolving business needs.

Related technologies, methodologies, tools, and procedures will be needed to complement and complete the presently planned IEC 61850-based environment. Each bidder needs to ensure its offerings address these to provide an attractive, well-defined environment and attractive, well-defined solutions within that environment.

The remainder of this specification addresses system architecture, functional requirements, design constraints, and test requirements. Collectively these reflect (1) the specific characteristics that MEA wants the station environment to incorporate and (2) how MEA wants to use this environment, including present capabilities and applications. As long as these requirements are satisfied, the internal design aspects of individual products are left to their suppliers. MEA retains the decisive power to alter these specifications or to reprioritize objectives, according to its judgment.

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Figure 1

2 SYSTEM ARCHITECTURE and HIERARCHY

This clause describes the architectural levels and components required to support the capabilities and responsibilities of a station’s secondary system. As long as bidders honor the intent and substance of requirements, they have the latitude to recommend implementations that vary from the ways they are portrayed in this specification.

2.1 BASIC ARCHITECTURE

The architecture and configuration of the system is guided by two high-level principles:

1. Use of a two-tier hierarchical control system

2. Distributed data processing

Both reinforce the same goal, which is to allow processing and data management to occur concurrently and independently at the station and bay levels of station operation. Use of these two principles helps organize the way system and application functions run, allows data processing and management to proceed productively in multiple devices, reduces overlapping communications traffic, and allows system failures to be addressed with less difficulty.

A consequence of this architectural approach is that conventional, concentrated, centralized systems are broken apart. The pieces are distributed across a site, regrouped, and reassembled in ways that reduce cost, simplify tasks, and provide continued flexibility. Overall, the approach must provide significant benefits for engineering, construction, procurement, installation, testing, operations, and maintenance.

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To preserve investment and promote system longevity, the system shall be designed with an emphasis on hardware and software independence, industry standards, mainstream products and toolkits, reusable methods, and applications supported by a common set of station functions. The block diagram presented in Figures 1 represent an acceptable system structure, in that they are conceptually compatible with the overall system architecture, capabilities, functions, and constraints described by this technical specification. Those objectives being met, a premium has been placed on tight integration of closely coupled system functions, segregation of independent system responsibilities, simplicity, elegance, synergy, flexibility, durability, improved value, etc … all hallmarks of good design. Bidders may propose alternatives or variations of Figure 1, which will be evaluated per the same criteria.

2.1.1 Station Communications

2.1.1.1 Substation LAN

Two redundant Substation LANs shall provide the principal means for data exchange among intelligent station components at both the station and bay levels. Each LAN shall consist of Ethernet network segments, Ethernet switches, and TCP/IP communications software that conform to the IEC 61850 network profile. Fiber-optic network media shall be used throughout the station facility. Copper media may be used within station level enclosures (CCU, CGW, MMI and DTS).

Each device connected to the network shall be specified to have one or two network ports, used as follows:

Where two ports are used, one shall be connected to each Substation LAN. The way these two connections are used is described under the ‘Dual Substation LAN Connections’ heading.

Where one port is used, it will be connected to an assigned Substation LAN, as determined by system design.

2.1.1.2 Gateway for Enterprise Communications

MEA has two SCADA/EMS systems that are presently the only enterprise clients that gather data from stations and provide control over their operation. Their primary objective is to provide operational reliability for the power system. They achieve this by monitoring power system data, status for various devices, events, counters that register energy transfer, and by controlling devices such as circuit breakers, disconnecting switches, and transformer OLTCs. Only one SCADA/EMS system has control and data acquisition responsibilities for any given station at any given time.

A SCADA/EMS system shall communicate with the stations covered by this specification using DNP3 over serial communication channels. These data communications shall be carried by MEA’s SDH, fiber optic WAN. The contractor shall provide a Fiber Optic Modem (FO Modem) at each station. The modem shall support bidirectional communications and provide an interface circuit between the SDH signal and a serial RS-232 data circuit. The RS-232 circuit shall be used to interface the FO Modem to a Communications Gateway module (CGW), which shall provide and support an Ethernet connection in compliance with the IEC 61850 Ethernet profile. The CGW module shall physically connect to both Substation LANs through a fiber optic interface, using either two Ethernet connectors (preferred) or a single connector equipped with a bifurcated adapter. Operation with the two connectors is explained elsewhere in this technical specification.

Other present and future enterprise clients shall be able to share use of the Communications Gateway to access the station. At present, access is limited to the two SCADA/EMS systems and a Remote File Manager, which is responsible for downloading product software and configuration updates.

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2.1.2 Station Level

The term station-level, used in the context of this specification, includes all station responsibilities and capabilities above bay-level. These include the following:

1. Substation LANs, providing the means by which devices and applications exchange data within the station

2. Station-level data management, data storage, and data retrieval mechanisms

Includes support for IEC 61850 information models, historical data, configurational data, diagnostic and maintenance data, and files (e.g. non-operational, configurational, application programs, software updates).

3. System functions required to implement and support the general secondary system environment (e.g. time and date synchronization services)

4. Application functions necessary to meet specified business and/or functional objectives

These may include functions that would normally be implemented at the bay-level, if the bay-level is not equipped to provide them

5. Station-wide, centralized, functional interlocking

6. Station-wide collection of maintenance data, diagnostic data, and statistical data for (1) primary system components, (2) secondary system components, and (3) application functions

7. Local control of the station for O&M purposes

8. Security

9. Support for MEA’s enterprise clients, residing outside the station (e.g. SCADA/EMS and Remote Operator Interface).

10. Gateways for legacy subsystems

Accordingly, MEA has defined several components for the station-level architecture. They are listed below, followed by a description of their specific system roles, responsibilities and capabilities. They are shown in the block diagram, Figure 1. Except for the constraints placed on their implementation, these may be regarded as black boxes. In other words, as long as the specified interfaces, capabilities, design constraints (e.g. performance), etc are honored, the internal design details are of no concern to MEA. The caveat, however, is that the integrated system design must meet all expectations, whether or not MEA recognizes all appropriate design constraints a priori.

Component Operating Level(s)

Substation LAN (SubLAN) Bay and Station

Centralized Control Unit (CCU) Station

Operator Interface [MMI] Station

Time and Date Server (TDS) Station

Communications Gateway (CGW) Station

Print Server (PS) Station

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2.1.2.1 System Linchpins: Local Repository and Syst em Logs

The following data structures form the core of the SA system. They include five system logs that chronologically capture the station’s operational history.

1. Local Repository

The Repository represents the present state of the station. It shall hold the IEC 61850-based information models for the primary system and secondary system components, including off-the-shelf and programmable logic applications.

2. StatusLog

The StatusLog is a chronological record of recent changes in either primary or secondary system status, either commanded or uncommanded. In particular, it shall include an entry for any station component power-fail, power-on, restart, or change in on-line/off-line status. Power supply failures shall also be captured.

The StatusLog shall not include control commands, although it shall include changes in status that result from those commands. The StatusLog shall not include configuration changes to parameters in the system information models. The StatusLog shall hold events for the most recent 100 days. It shall be backed up in archives, each archive containing events for a particular month.

All StatusLog entries shall include a time-stamp, identify the system item that changed, identify the new status, and identify the cause (or agent) of the change.

3. CommandLog

The CommandLog is a chronological record of recent control commands to station equipment (e.g. Trip, Close, Open, Close, Raise, Lower, Enable, Disable, and set-points) issued by System Clients. These may be initiated by a SCADA/EMS system, by a local Operator Interface [MMI] unit, or by off-the-shelf and programmable logic applications. The CommandLog shall hold commands issued during the most recent 100 days. It shall be backed up in archives, each archive containing control commands for a particular month.

All CommandLog entries shall include a time-stamp, identify the system item being controlled, identify the state being commanded, and identify the source of the control command.

4. ChangeLog

The ChangeLog is a chronological record of recent changes made by an Operator Interface [MMI] unit to system and device configuration parameters. The ChangeLog shall hold changes issued during the most recent 100 days. It is backed up in archives, each archive containing changes for a particular month.

All ChangeLog entries shall include a time-stamp, identify the system or IED parameter being changed, identify the new state, and identify the source (i.e. agent) of the change.

5. SubLog

The SubLog is a chronological record of changes made by clients using the IEC 61850 substitution services. The services allow clients to determine whether actual process values or substituted values are to be provided by a server IED or programmable application. The SubLog shall include all substitution events, including a return to process values, that have occurred during the most recent 100 days.

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6. FileLog

The FileLog is a chronological record of recent file transfers and file deletions involving any intelligent station device (e.g. BCU, CCU, Operator Interface [MMI]). The FileLog shall include all such file events that have occurred during the most recent 100 days. It shall be backed up in archives, each archive containing file events for a particular month.

All FileLog entries shall include a time-stamp, identify the file reference, identify the action taken, and identify the source (i.e. agent) of the action.

The Local Repository is the basis for normal system operation. The five system logs save the system’s recent operational history. They shall be used to bring a system client up-to-date after it goes on-line. As long as the integrity of the system logs is maintained, they provide assurance of operational continuity despite occasional failures and system maintenance actions. Integrity shall be maintained through use of a standby CCU.

System clients (e.g. the SCADA/EMS system or Operator Interface [MMI] unit) shall have the capability to construct a CompositeLog by chronologically interleaving entries from system logs (i.e. StatusLog, CommandLog, ChangeLog, SubLog, FileLog). The CompositeLog enables operators to understand what has happened over time. (See the more complete description found under the Operator Interface [MMI] heading.)

2.1.2.2 Common IED Capabilities

The following capabilities shall be supported by all IEDs, unless specific exceptions are noted:

1. The IEC 61850 communications standard

IEDs shall support applicable portions of the IEC 61850 communications standard. This includes the Ethernet network profile, applicable portions of the information models (including data quality), and all communications services (except as noted).

2. Time synchronization over the network

IEDs shall support time synchronization over the network by the CCU. Exception: The Time and Date Server is synchronized via a GPS source.

3. Remote or local configuration

IEDs shall support both remote and local configuration via file downloads over the network. Local configuration shall also be supported through a traditional, serial maintenance port.

4. Self-monitoring and Diagnostic Routines

Each IED shall continually conduct on-line tests to monitor its health, operating conditions, and performance to determine whether abnormal conditions or problems are present. It shall collect statistics on repetitive operations such as communications messaging to determine success/failure rates. Some of these conditions need to be reported in heartbeat messages; the others shall be reported as diagnostic status, measurements, or counters, which shall be entered into the Repository and subscribed by the Operator Interface [MMI] unit.

5. Programmable logic applications

All IEDs shall host the heartbeat function.

Other specific applications may be required for individual IEDs, as described elsewhere in this specification. Exceptions: Time and Date Server.

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6. Version Control

Each IED shall maintain version control for its software/firmware and configuration files.

2.1.2.3 Central Control Unit (CCU)

The CCU is the main station processor. It has several roles, as described below:

1. Principal Station Client

The CCU is the principal station client, meaning it is responsible for collecting and maintaining the various data and files that comprise the station information base.

Bay Control Units, Protection Relays, and perhaps other IEDs are expected to report a large amount of their data through use of IEC 61850 report services. The primary CCU will need to poll for any remaining data, using IEC 61850 services, or calculate it from other available data, using local automation applications. Data must be acquired and stored according to the System Performance Requirements.

2. Local Repository / Compatibility with IEC 61850

The CCU provides a Local Repository for the storage of station data. This is directly related to its role as principal station client. The information stored in the Repository shall include real-time data and closely related support data (e.g. operational parameters, configuration parameters, text-based descriptions), as provided by the IEC 61850 information models. Repository data may include diagnostic and maintenance data if it is included in the IEC 61850 information models. Files are handled in special manner, which is explained under the File Management heading.

IEC 61850 provides information models for most of the available system data, and those models can be extended to include new components. Although it is not desirable for the Repository to store all data available in the station, it must at least include all data subscribed by station or enterprise clients. Operator Interface(s) [MMI] are examples of station clients; they need station data for displays, alarm lists, logs, and local control operations. Other station clients are devices that require data to perform automation. The results produced by automation application functions will need to be stored in the Repository if other clients subscribe them. SCADA/EMS, on the other hand, is an enterprise client.

The Local Repository must have interfaces that are interoperable with all other system devices (i.e. servers and clients) using IEC 61850 communication services, information models, and object references. Where MEA applications use Logical Node and/or Common Data Class extensions, these shall be supported in the Repository as well. The Repository shall be configured to support any and all data available from station servers, including the CCU itself, subject only to any limitations stated under System Performance Requirements.

The CCU shall implement all of IEC 61850’s ASCI service models, with the following exceptions: GSSE Control Block and the Sampled Value Class Model. Clients and servers using the Repository shall find all of the other services available.

The Repository must be maintained in a replaceable flash memory module. Battery power is an unacceptable approach to maintaining non-volatile data memory.

3. Proxy Server

To avoid confusion, it must first be understood that the CCU plays both client and server roles in the station system. It acts as a client to populate the Repository with data from other server IEDs (e.g. Bay Control Units). In turn, it acts as a ‘proxy’ server by satisfying

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client requests with data directly from the Repository. The intent is (1) to prevent access contention and congestion that may potentially disrupt the operation of field IEDs, (2) to simplify access mechanisms, and (3) to provide accountability (i.e. an audit trail) for past operations.

The proxy services shall work the same way for enterprise and station clients, although the SCADA/EMS system does not currently support IEC 61850 communications. Current station clients include Operator Interface [MMI] units and programmable logic applications. The only current enterprise client is the Remote File Manager. Although its responsibilities are presently limited to file operations, it may emerge as a remote, fully operational Operator Interface [MMI] unit if performance considerations permit. This shall be determined later. When any of these requests server data, the CCU acts on it, providing data from the Local Repository’s ‘Proxy Client Views’. With rare exception, clients other than the CCU are not permitted to directly access the primary sources of station data (e.g. IEDs, Bay Control Units, etc).

Because the Repository is the primary source of system data for system clients, the CCU shall provide IEC 61850 report and log services for their benefit. The report services allow clients to subscribe and receive selective, real-time data updates from the Repository, so that clients can stay operationally up-to-date. The log services allow clients to chronologically reconstruct recent system history if they are new or have just returned on-line. The supported system logs shall be the StatusLog, CommandLog, ChangeLog, SubLog, and FileLog.

As part of its proxy role, the primary CCU has the following responsibilities:

Determining status changes in reported or polled data and updating the status data in the Repository. Status changes, both commanded and uncommanded, shall be recorded in the StatusLog.

Executing client commands to control system equipment (e.g. circuit breaker and disconnect switch Trip/Close, recloser Enable/Disable, transformer OLTC Raise/Lower). These control commands shall be recorded in the CommandLog. Clients authorized to initiate these commands include SCADA/EMS, Operator Interface [MMI] units, and programmable logic applications.

Making value substitutions in server IEDs, in conformance with the IEC 61850 substitution service model. These changes shall be recorded in the SubLog. Clients authorized to initiate value substitutions include SCADA/EMS, Operator Interface [MMI] units, and programmable logic applications.

Making changes to configuration parameters and descriptive text within Common Data Class (CDC) instances. These same changes must be made in the IED Servers to the data that is mapped to the altered parameters in the Repository. The changes made to the IED Servers must, in turn, be replicated in the Proxy Server Views within the Repository. These changes shall also be recorded in the ChangeLog. At some point, these changes have to be folded back into the SCL system configuration process, if appropriate. The Operator Interface [MMI] unit is the only client authorized to initiate these changes.

Executing file transfers and deletions. File transfers shall be supported between the CCU and other system IEDs. These actions shall be recorded in the FileLog. The only clients authorized to initiate file operations are the Operator interface [MMI] unit and Remote File Manager. This topic is addressed in more detail below, under the File Agent heading.

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4. Supporting SCADA/EMS Operations

Dispatchers shall be able to control station equipment and gather system data via DNP3 command and polling messages transmitted from the SCADA/EMS control center. Implementation of DNP3 protocol shall meet ALL requirements as specified in APPENDIX B.

The DNP3 Level 2 Conformance Certificate and a completed DNP3 ‘Device Profile Document’ and ‘Implementation Table’ shall be submitted to MEA within 180 (one hundred and eighty) days after the Effective Date of Contract. The Conformance Certificate shall be issued by one of the DNP Users Group’s ‘Authorized Testing Authorities’. If not already available, DNP requirements in Appendix B that transcend Level 2 shall be implemented by the contractor in the course of project execution.

DNP communications shall be supported by the CCU via a process that links and converts IEC 61850 data to the desired DNP values and formats. These resulting DNP data shall be stored and maintained in a separate DNP database that can be accessed by DNP data communication services. This approach provides two significant advantages: (1) the continual DNP data conversion process is independent of (i.e. not interrupted by) DNP message processing, and (2) the DNP database allows the CCU to quickly respond to message requests. DNP commands shall likewise be translated to use IEC 61850 control blocks and procedures for controlling system equipment.

The following appendices to this specification provide essential information for supporting SCADA/EMS operations:

Appendix A

Appendix A details DNP3 communications implementation for the front-end communications processors used in the two SCADA/EMS control centers. The material includes a ‘Device Profile Document’ and a ‘Master’s implementation Table’. These state the features and important parameters used in the implementation, including supported DNP objects, variations, qualifiers, and function codes.

Appendix B

Appendix B details the DNP3 objects, variations, qualifiers, and function codes that must be supported by the CCU in its DNP slave role.

Appendix C

Appendix C details certain higher-level implementation information for the individual Terminal Stations and Substations covered by this specification. The information includes initial and ultimate quantities of bay units (of different types), capacitor branches, bus ties, and CT-secondaries.

Appendix D

Appendix D details typical point types, point counts, and point identities for each type of station bay unit.

Appendix E

Appendix E provides a standard DNP3 RTU point list for MEA’s SCADA/EMS. The list is itemized by point type and point function for each type of station bay unit and function. These are the DNP points that need to be supported by data in the Repository and DNP database.

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5. Application Programs

The CCU must be capable of storing and executing application programs. These may be commercial programs or they may be implemented in programmable logic.

The scope and functions of these programs will typically be defined for CCU.

All application functions that must be implemented in the CCU are listed below. They are described in more detail under the specification heading titled Functional Requirements, Applications Support.

Heartbeat function [at all 10 sites]

Trip Counters for circuit breakers [at all sites]

‘Rate-of-change’ calculations for selected measurements [at all sites]

‘Breaker Operating Time’ checks [at all sites]

6. Communications Gateway

The CCU shall supply and receive all application data for the Communications Gateway. Lower-level communications functions are the responsibilities of the TCP/IP, Ethernet, and/or DNP communications software.

Communication parameters such as baud rates, number of data bits, parity, transmission retries, etc. shall be configurable. These shall be user-defined parameters that the operator can change through an MMI template.

This includes DNP data exchanged with SCADA/EMS control centers. In this case the CCU must be able to support the communications role of DNP / Level 2 Slave. DNP application data may be converted from contents of the Local Repository or maintained in a separate database. However supported, DNP response times cannot suffer.

The CCU shall be able to exchange files with enterprise clients and to store those files. They will typically be configuration, software, application, or non-operational data files (e.g. event or oscillography files from protective relays). The CCU does not need to interpret the file data. For transfers between the CCU and an enterprise client (except the Remote File Manager), FTP or COMTRADE services are preferred.

The CCU shall provide appropriate, application-level security services for information transported through Communications Gateway, including authentication and access control. The Communications gateway shall be designed to provide encryption, although it may not be used initially.

7. File Agent

The CCU shall include a File Agent utility that provides file management, performs file transfers and deletions, and maintains the FileLog (see above). The File Agent shall process all file transfers, which shall occur between the CCU and other IEDs. Files may include configuration files, application programs, software updates, and non-operational data (e.g. relay disturbance files and event reports). To maintain interoperability within the station, file services, attributes, references, and other characteristics shall comply with the IEC 61850 communications standard. File content does not need to be interpreted by the File Agent.

Since station IEDs and enterprise clients may currently support the COMTRADE standard [IEEE C37.111 (1999)] and/or FTP standard [IETF – RFC 542], MEA has an interest in applying them where IEC 61850 transfers cannot be supported. Potential applications may involve SDH WAN transfers involving the remote File Management Client.

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2.1.2.4 Operator Interface [MMI]

An Operator Interface [MMI] shall be the center for all O&M station activities. This includes the following categories of responsibilities:

1. ‘Local control’ over the primary power system. The facility shall provide all capabilities available to dispatchers at the SCADA/EMS control centers plus more.

Supervisory control capabilities through the Operator Interface require the MMI/SCADA switchover per field or system at the station to be in the MMI position, meaning the SCADA/EMS center and any other (future) enterprise clients must relinquish control for operational and safety reasons.

2. Displays and reports that inform the operator about what is happening in the station system.

3. Maintenance and testing of the station system. This includes maintenance of the data used to monitor, control, and configure the station’s operation.

The Operator Interface [MMI] displaces use of conventional hardwired control, metering, and annunciation panels for local operations requiring a station operator. Where these displaced facilities already exist, they may be used for backup, as permitted by MEA’s policies and procedures.

2.1.2.4.1 Three Platforms

Three platforms shall be used for the Operator Interface. One will be used at Terminal Stations, which are normally manned, two will be used for Substations which are normally unmanned, and the other for Portable interface. Both of them will use the same system and application software.

1. Terminal Stations

The Operator Interface shall be implemented with a workstation, 23” monitor, keyboard, mouse, annunciators, computer desk, and chair. The workstation shall provide dual Substation LAN connection ports with fiber optic adapters: one for Substation LAN A and the other for Substation LAN B.

Only one port shall be active at a time. Unlike other station IEDs, the operator forces the MMI unit to connect to Substation LAN A or Substation LAN B. The prevailing selection shall be displayed at the same screen location on all viewable displays.

2. Substations

The Operator Interface shall be implemented with a workstation, 20” monitor, keyboard, mouse, annunciators, computer desk, and chair, however the Operator Interface may be equipped in the Regional Control Center (RCC) outside the substations that are usually unmanned. The communication media (Optical Fiber Link) between Substations LANs and Operator Interface shall be provided by MEA, therefore all communication equipment for interfacing at the both end shall be provided by Contractor.

3. Portable

The Operator Interface shall be implemented with a portable notebook computer and mouse. The notebook shall provide one Ethernet connection port. The user shall manually connect the unit to either Substation LAN A or Substation LAN B. Because this unit does not provide dual Substation LAN connections, the MMI unit does not track or display which Substation LAN it is connected to.

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2.1.2.4.2 Operator Interface Responsibilities

The following are Operator Interface [MMI] unit responsibilities for both Terminal Station and Substation sites:

1. Primary On-Line Responsibilities

At start-up

At start-up, an Operator Interface [MMI] unit will have either no or out-dated information regarding the operational history of the station system to which it is connected. This means there is no basis for constructing an Alarm Summary or any other display that depends on past events. The MMI also lacks current real-time data needed to support displays and operator decisions.

To remedy this, the MMI unit shall read the system logs (i.e. StatusLog, CommandLog, ChangeLog, SubLog, FileLog) from the resident, primary CCU. The logs shall be read with IEC 61850 services. The system logs shall be processed to produce the Alarm Display and any other displayed data dependent on system history.

The MMI unit shall be able to interleave system logs to produce a CompositeLog, providing an integrated, chronological list of events. This is a very helpful tool that enables an operator to see time relationships. (See the clause heading Operator Interface [MMI], under Function Requirements, for a more complete description.)

To the extent necessary to support MMI display updates, the MMI client shall subscribe to IEC 61850 real-time data reports from the Repository.

The system logs, together with the real-time data, enable the MMI unit to capture both the current state of the system and 100 days of history. It can populate all its displays with data, enable the operator to make informed decisions, and act as though it had been connected to that site for three months.

Maintenance of the CompositeLog

The MMI unit shall use new entries from system logs (i.e. StatusLog, CommandLog, ChangeLog, SubLog, FileLog), provided by CCU(s), to maintain the CompositeLog.

Updating displays

The MMI displays are the operator’s principal means for staying abreast of the system’s operating condition. The operator can also perform primary system control, substitute values for process values, and make certain configuration changes.

Operational supervision of programmable logic appli cations

This shall be accomplished through the use of graphics to represent the application and the use of Repository subscriptions to observe inputs and outputs.

Initiating file transfers and deletions

This capability supports local, operator-initiated software, application, and configuration file downloads to IEDs through the CCU.

Browsing capability

This capability allows an operator to view the structure and contents of IEC 61850 information models within the Local Repository of the CCU. More importantly, it is the MMI’s principal tool for reading and storing the structure and content of the Local Repository in the CCU. This information is essential for building displays and reports, saving historical data, and maintaining the system.

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2. Displays

Station Status

Alarm Summary

CompositeLog

Abnormal Points Summary

Communications Status / Operational Status

Tagged Device Summary

Substituted Value Summary

Health, diagnostic, and on-line/off-line (in-service/out-of-service) status for each IED and application (i.e. technology monitoring and alarming for the secondary system)

Current file directory (for each IED)

3. Control capabilities

Primary Control: TRIP/CLOSE, RAISE/LOWER,

Device Tagging

Automatic acknowledgement

Recloser Mode Selection

Relay ‘Settings Group’ Mode Selection

‘Primary CCU’ Selection

Value substitution

CCU restart

Operator Interface [MMI] restart

4. Historical Data application

Hosted both Terminals Stations and Substations.

Allows the MMI operator to create Historical Points, which become periodic, saved recordings of data values for a specific variable.

Records minimum and maximum values for designated variables over designated time periods each day.

Provides reports that can be printed or displayed

5. Off-Line Responsibilities

IEC 61850-based configuration control, using the SCL tools provided by the contractor.

Creation and modification of displays

Creation and modification of system reports

Creation and modification of programmable logic applications

Creation and modification of all IEDs setting / configuration parameters

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Modification of system behavior and application behavior through the use of templates provided for user-defined parameters

Fault evaluation analysis (Disturbance waveform)

2.1.2.5 Print Server

The Print Server shall be provided at Terminal stations and substations. The Operator Interface [MMI] units shall host the Print Server via the Substation LANs. This will allow the portable notebook version of the Operator Interface to initiate print requests, regardless of its physical location.

A black-and-white laser printer shall be provided, so that printed material can be annotated and highlighted without smudging. The print facilities shall print excellent facsimiles of any of the following:

1. Any Operator Interface display *

2. Any defined system report *

3. Any file that M/S Windows is capable of printing without the use of special application utilities

Printouts for listed items listed above with an asterisk shall include the station name and the date and time when the print request is executed.

If the printer is off-line, out-of-paper, etc, printing shall be delayed until the printer is returned to service.

2.1.2.6 Time and Date Server (TDS)

The Time and Date Server is responsible for providing precision time and date data. The CCU shall periodically retrieve the time and date from the TDS unit and distribute it to all other intelligent system components that need it. The receiving components shall use this data in a timely manner to synchronize their internal clocks. This mechanism is the basis for establishing a common, absolute time basis by which all time-related applications can coordinate their time-stamping, protection, control, and automation activities.

The TDS shall use a satellite-provided GPS signal as its synchronizing source. It is assumed that all system components needing to receive precision time and date data reside on Substation LANs A and B. The CCU shall deliver this data over the Substation LANs using IEC 61850 time synchronization services.

The TDS design shall incorporate an internal clock circuit using a low drift, temperature compensated crystal oscillator, so that the unit can continue to provide reasonably accurate time synchronization for at least 5 minutes in the absence of a GPS signal. Under such circumstances, the unit shall continue to perform its normal functions, but it shall provide status indicating loss of the GPS source or other debilitating loss of function. This information shall be passed to the SCADA/EMS and Operator Interface [MMI] systems through the Local Repository. If IEDs are not synchronized within a specified time (e.g. two minutes), they shall report status indicating that they are not being synchronized.

The SCADA/EMS control center shall always provide an alternate source of time for the station, using the DNP time synchronization algorithm and delay measurement service (Function Code 23). In the event that either (1) the TDS reports loss of the GPS signal or (2), the CCU determines that the TDS module’s time and date are not credible, the CCU shall use the alternative source to synchronize IEDs after a user-defined delay has passed. (Refer to Clause IV for the default delay.) During the first hour or so, time precision is expected to be better maintained without using the

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alternative source, due to its inherently poorer precision. This approach also provides more grace time for recovery of a lost GPS signal.

2.1.3 Bay Level

The term bay, used in the context of this specification, refers to the practice of grouping certain secondary system equipment together to protect, control, monitor, and automate certain primary system equipment within the station. There may be numerous bays in a station, including different types (e.g. ‘feeder bay’, ‘transformer bay’) and multiple instances of the same type (e.g. ‘feeder bay’). For example, MEA standardized its station practice around certain proposed bay designs, where one or more IEDs (typically protection relays) and ancillary equipment are integrated together in the same package for a particular purpose. That package could be reused in multiple stations, saving non-recurring and recurring costs in engineering, installation, configuration, test, and so on.

2.1.3.1 Bay Control Units / IEDs

This specification refers to smart bay implementations as Bay Control Units. As such, they are assumed to have sufficient local processing, memory, programmable logic, and communication resources to support expanded responsibilities and capabilities. When these resources are combined with support for the IEC 61850 communications standard, Bay Control Units gain flexibility and power that can significantly elevate their system roles and provide enormous flexibility.

Since a number of capable protection IEDs now support the IEC 61850 communications architecture as well as mainstream protocols, the need for non-relay, bay-level processing is at best questionable. In all but the most demanding circumstances, protection IEDs are very capable of managing bay-level responsibilities in coordination with the station level, while taking care of their primary protection responsibilities.

The following are two examples of how MEA would like to apply bay-level processing at these 10 stations and beyond:

1. Bay-level IEDs can gather, pre-process, and store data locally. That same data can be selectively reported to the station level when triggered by the occurrence of defined events. The data may include power system measurements, status, and a variety of other candidates that surpass typical RTU capabilities. IEDs can also execute commands delivered from the station level.

This approach not only relieves the station level from performing these tasks for multiple bay units, it provides for graceful loss of functionality when a critical processing resource at the station level fails. Because IEC 61850 uses named data, represents it in engineering units, and hierarchically structures it within station information models, data management is simplified.

2. Certain applications may be deployed within a bay or among a group of cooperating bays spread conveniently across a site. In the latter case, we say the application is distributed. These applications may be implemented through commercially available software and/or programmable logic.

For distributed applications, the participating protection relays usually need to directly exchange interlocking signals (e.g. status and commands) with each other. For a protection application, these exchanges must be quick, perhaps within 4 ms to satisfy the timing requirements of the application. The IEC 61850 communications standard provides GOOSE messaging services for this purpose, using the Substation LAN in lieu of traditional hardwired connections. In support of a relatively simple migration strategy, IEC 61850-compatible relays can be used together with those that are not, combining use of GOOSE messaging and traditional hardwired connections.

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3. The BCUs and Protection Relays shall have been submitted/passed a test to certificate compliance with the IEC 61850 part 10 Conformance Testing such as the following :-

Basic Exchange Data Set Definition Unbuffered Report GOOSE Publish GOOSE Subscribe Time Synchronization File Transfer

The tests to certificate compliance with IEC 61850 part 10 have to be certified by international accredited testing laboratories which are independent of the Bidder and Supplier.

2.1.3.2 Bay Control Units with Protection Relays (B CUs)

Bay Control Units with Protection Relays that support the IEC 61850 communications standard will replace existing RTU units and Protection Relays. The field wiring for all points shall be provided to connect to the new BCU assemblies. MEA will provide marshalling cabinets for these field-wiring connections. The Bay Control Units with Protective Relays shall be fully numerical type, use solid-state analog converters, employing digital signal processing (DSP) techniques, to make analog measurements from proportional AC signals provided by system CTs and PTs. This approach will provide MEA with a greater variety of power system measurement data, while eliminating transducer maintenance costs.

There are a number of important issues related to the use of these new Bay Control Units with Protective Relays. They are summarized below, and discussed in more detail under the document headings for functional, performance, and testing requirements.

1. Implementation

The Bay Control Units with Protective Relays shall be provided as a single unit or as a collection of individual units that connect to the Substation LAN. All else being equal, since it provides more flexibility and improves system availability. Individual units shall be operationally independent.

2. IEC 61850 Support

Bay Control Units with Protection Relays shall represent all data as IEC 61850 object references, using Logical Nodes and Common Data Classes that are appropriate to the specific data sources. It is not acceptable for Bay Control Units with Protection Relay information to be grouped into generic Logical Nodes except where MEA agrees that it is the best course of action for specific points that otherwise have no standard representation within the IEC 61850 information models.

All of IEC61850’s ACSI service models shall be implemented and ready for use, with the following exceptions: the Setting Group Control Block, the GSSE Control Block, and the Sampled Value Class Model. In particular, it is expected that Bay Control Units with Protection Relay will use Report Control Blocks to send data subscribed by CCUs and Operator Interface [MMI] units. Report Control Blocks will be absolutely necessary for the transmittal of SOE data. Operator Interface [MMI] units will exchange data with IEDs only for maintenance, equipment mode control, and diagnostic purposes. No IEDs other than CCUs, Operator Interface [MMI] units, and the Time & Date Server shall exchange data with BCU IEDs on a client-server basis.

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Bay Control Units with Protection Relay shall need to transmit and receive GOOSE messages in support of the heartbeat application. (See Programmable Logic Applications under Functions.)

3. Data Maintenance Tools

Although the contractor is responsible for system integration of the delivered system, PC-based tools shall be provided that allow MEA personnel to reassign IEC 61850 object references to point data, to add new assignments and delete old ones, and to integrate the results into the system.

4. Data Quality

Each data component shall be accompanied by its associated data quality, as defined by the IEC 61850 Common Data Classes. All constituent bits of data quality shall be used and supported (as appropriate) by the Bay Control Units with Protection Relays.

5. System Configuration

Each Bay Control Unit with Protection Relay shall provide an IED Capabilities Description (ICD) file that describes the IEC 61850 information models, service models, and related communications capabilities supported by the device. It shall also fully support the SCL process described under the heading titled System Configuration. As the result of that process, a downloadable CID file shall be created for each BCUs.

6. BCU Point Interfaces and Circuits

Field connection circuits for I/O points, communications, and power require special consideration to protect equipment against damage and to protect I/O processes against corrupting influences. This is important for maintaining reliability and operational integrity. These issues are addressed by three standards listed under the Specific Relevant Standards clause: IEEE C37.1-1994, IEC 60870-2-1, and IEC 60870-2-2. System and circuit design related to field connection circuits shall comply with these standards. Where they overlap, the more stringent clause shall prevail.

In summary, I/O interfaces shall provide high integrity for the detection and measurement of acquired signals. They shall also prevent damage, maintain safe conditions for personnel, and prevent bad data caused by the secondary effects of lightning, operation of power switchgear, abnormal electrical power behavior, and so on. Under no circumstances shall these effects cause an unintended control action.

7. Serial Data Ports

Each Bay Control Units with Protection Relay shall provide at least two serial data server ports for gathering I/O data from other sources within the station or from satellite facilities. Bay Control Units with Protection Relay ports shall support IEC 61850 object references in the object base. A PC-based test set with software that supports this protocols shall be provided.

8. Maintenance Port

Each Bay Control Units with Protection Relay shall rely on a ‘maintenance port’ for configuration management (e.g. uploading and downloading), if those functions cannot be performed over the network. If this is the case, the supplier shall explain the necessity and whether a remedy is being prepared.

9. Testing

Convenient, rapid, and effective testing of I/O inputs and Bay Control Units with Protection Relay interface circuits is especially important. This capability is needed for

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verifying point connections, verifying object references against associated input points, system commissioning, and troubleshooting activities.

One of the general difficulties is that I/O points may arrive at the Bay Control Units with Protection Relay through terminal connections, through serial data ports, or from programmable logic outputs. Partly in the interest of simplifying testability, only connection-oriented I/O inputs are presently specified for use in the Bay Control Units with Protection Relays.

One approach under consideration would provide the capability to temporarily force a point out of its normal operating state and into a test state, wherein the point would be represented by a selectable test value. For example, binary status points would have two possible test values (0 and 1), analog inputs might have five (i.e. one for each region), and so on. While in the test state, data quality for the point would be changed to ‘test’, as indicated through the use of that constituent bit. This test data could be viewed via an IEC 61850 browser. Alternatively, this testing could be manually or automatically run and verified, point-by-point, from a client application. The CCU and other system components would not process test data as valid real-time data, waiting until such points are commanded out of the test state and back into the normal operational state. The effectiveness of this approach, or any other recommended by the bidder, depends heavily on how well the whole I/O path within the Bay Control Units with Protection Relays is tested. Bidders are welcomed to submit alternative approaches.

10. Programmable Logic

Bay Control Units with Protection Relays shall provide programmable logic capabilities and tools.

All application functions that must be implemented in the BCUs are listed below. They are described in more detail under the specification heading titled Functional Requirements, Applications Support. Note that protection functions are presently included.

Heartbeat function [at all sites]

Bay and inter-bay interlocking [at all sites]

Bus coupler throw-over scheme (CTO) [at selected sites]

Line throw-over scheme (LTO) [at selected sites]

Bus throw-over scheme (BTO) [at all sites]

Load shedding and restoration scheme (ALS/ALR) [at all sites]

Breaker failure protection (50BF) [at all sites]

Voltage Selection (VS) [at all sites]

Automatic Transformer Restoration (ATR) [at selected sites]

Capacitor Control [at all sites]

11. Mounting and Power

The Bay Control Units with Protection Relays shall be provided as 19”, rack-mountable units, suitable for an open relay rack. They shall be powered from station battery, and include appropriate provisions for fusing, grounding, lighting, heating and power distribution.

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Each panel shall be supplied with 240Vac single phase strip or tubular space heater with on-off switch and 240Vac single phase interior light controlled by door switch. The heater shall have moisture control unit with a main switch placed in the bus coupler/bus section panel.

12. Protection Functions

The rate of sampling for A/D converters shall vary between 1000 Hz and 2000 Hz. The representation inside the protection relays of currents between 0.1 and 120 x rated current requires the use of a microprocessor with at least 12 Bit word length. Numerical protection shall always display the latest event.

Reset of the display shall be possible on the relay front without opening the cover. Reset shall not erase the memory of the relay. On the panel front in a visible place a label with the particular designation of each LED in the contractual language is required. The software version shall be displayed if manually requested.

The operational indication shall be saved in a non-volatile ring buffer, a four digit resettable counter shall identify the individual faults by a number, the date of the internal fault shall be saved for each fault.

The recording shall be started by a external signal e.g. CB closing related to an alarm relay and wired to the binary input and all internal protection functions. At least the four latest fault events shall be loaded into the memory of the Protection relay (BCU).

Numerical protection shall be designed in such a way that in case of a failure of DC-auxiliary infeed the full information need to be maintained during 24 hours. After a recovery of the DC-auxiliary infeed the last information and alarms will be displayed and the alarm failure of DC-auxiliary infeed released.

For critical alarms, the alarms are sent through ports per IEC 61850 and nearby BCU binary input to CCU and MMI.

At least 75% of the alarms shall to be programmable and able to be related to output contacts of the Bay Control Units with Protective Relays. Through this serial interface the CCU and/or MMI shall be able to retrieve the following minimum information, archive set or modified. The data integrity for data transfer inside the substation control unit shall be assured by a Hamming distance 4.

Disturbance fault recording, Fault Location and Accumulation fault (current) Event Records On line analog fault currents and voltages Retrieval, analysis of service and fault annunciations Parameterizing of protection devices On-line acquisition of measured process values (rms. or peak values) of currents,

voltages, active and reactive power Marshalling of binary input, output, LEDs Configuration of protection functions

12.1 Distance Protection 115/69 kV (21/21N, Separated unit)

The distance protection scheme shall be used as first main protection device. The design of this protection device shall fulfil at least the following requirements:

Numerical full line protection scheme designed for high-speed discriminative protection of lines and cables in transmission systems applicable to all neutral grounding possibilities

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Suitable for the protection of long or short overhead lines or cables, double circuit lines, heavily loaded lines, lines with weak infeeds

A mho or Polygon characteristic for faults between phases and preferable polygon characteristic for fault between phase and earth.

To guard against incorrect tripping caused by magnetising inrush currents when in-zone power transformers are present, a selectable magnetising inrush guard feature shall be fitted.

At least four (4) distance stages with a independently set polygon characteristics for forward and reverse measurement shall be implemented.

It will be possible to store at least four complete different groups of setting in a non-volatile (EEPROM) memory, unaffected by loss of DC supply. The active group of setting can be selected via menu, combination of contacts or via serial communication from MMI according to IEC 61850 standards. All settings and records are accessible from the integral user interfaces, also will be possible to communicate with the MMI via Substation LAN and also will be possible to relays office.

To ensure correct measurement under earth fault conditions, the relay needs to be earth compensated with both residual and a angular compensation for the proposed scheme OHL or cable.

VT supervision shall be included. VT supervision will block the trip of the distance protection. The logic for this feature if based on zero component voltage and current shall not be influenced by magnetising inrush current during energization of power transformers and during starting of motors.

The power swing blocking feature shall be able to be selected for blocking or tripping at selected zones and able to be overridden under the presence of a earth fault.

System logic for switch onto fault protection (SOTF) shall be implemented. The SOTF feature will be enabled in between a settable time 100…200 ms after the relay detects the local circuit has opened. This feature will block the autoreclosure scheme and the tripping will always be on the first setting time. Any starting, measuring via distance comparators or any current level detector, will initiate the tripping in this logic.

A logic for tele-protection schemes shall be regarded including the following topics :

Permissive underreaching (PUTT) Permissive overreaching (POTT) with weak infeed logic and

communication channel failure and reversal of fault energy direction Zone 1 extension coupled to the autoreclosure scheme in case of a

faulty communication channel Blocking scheme Sensitive directional earth fault in a directional comparison scheme. Weak infeed logic shall be able to select the proper autoreclosure

selection by means of the phase selection Open terminal echo and current reversal logic will be supplied with all

the overreaching schemes The logic scheme of the supplied tele-protection logic needs to be

submitted in block diagrams with clear indication of the send logic, trip logic, open terminal end and weak end logic.

Autoreclosure schemes for single and multiple faults with single and multiple shots shall be taken into account.

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The distance from the relaying point to the fault location will be measured and displayed by the incorporated fault locator units. The algorithm in this case shall take into consideration the pre-fault load current and the selected mutual coupling.

In case of fault the relay shall store four cycles of pre-trip and at least ten cycles of post-trip data. This includes as well the voltages and currents as internal relay information.

The scheme is equipped with two interfaces for the connection to a local PC and to remote communication with the Central Control Unit. Integral user interface form allows easy access to relay setting and fault recorded parameter and binary commands.

Interfaces modules/boards shall provide a galvanic isolation to 5 kV peak and filter out high frequency common mode and transverse mode noise signal.

At least two line by 16 character liquid crystal display (LCD), a key path, and ten programmable light emitting diodes (LED) for the several alarms, additional three LEDs for the relay should be available, alarm and trip shall be delivered for the main relay interfaces.

Visual indication of service parameters like voltages, currents, active and reactive power, maximum load, and other selectable parameters to be visualised in case of faults shall be included.

The EEPROM is a non volatile area of the memory, and will fulfil the storage and maintain the information within it even if the DC supply is removed. This area of the memory is copied to the working RAM after a DC power up, but only written to and read from, if setting changes are updated or a fault condition occurs.

At least the last three fault signals, alarms as well as the voltages, currents, tripping time, effective currents, setting group will be loaded into the EEPROM able to be restored, and loaded in a PC and be analysed by the protection service software as mentioned on this specification.

The synchronisation from a common remote clock and locally through the Central Control Unit (CCU) by means of a general synchronising signal or by a manual menu guided instruction is possible.

The contractual language i.e. English shall be used for setting and data input menus as well as for the description of all the main relay interfaces.

12.2 Undervoltage Protection (27)

Undervoltage protection shall be provided built-in Distance Protection and BCUs with a definitive time characteristic 0.1 till 1.2 in steps of 0.1 and a timer settable between 0.1 till 5.0 sec. Undervoltage protection will be used to initiate Programmable Logic Applications, Automated Control Sequences Scheme such as LTO, CTO, BTO and ALR.

12.3 Directional Overcurrent and Earth Fault Protec tion (67/67N)

The directional overcurrent and earth fault protection device shall be provided built-in BCUs with phase and earth fault elements. This relay shall be segregated measuring, alarms, annunciations and settings. Directional elements for both phase and earth fault scheme. At least four selectable characteristics for the phase elements shall be included according to IEC 60255-4 and BS 142:

normally inverse characteristic very inverse characteristic extremely inverse characteristic definite time characteristic

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additional long time characteristic for the earth element

Instantaneous trip order for the phase and earth element with a implemented timer and a set position to block their trip shall be provided.

12.4 Underfrequency Protection (81U)

Underfrequency protection shall be provided built-in BCUs for load shedding function for tripping the outgoing 24/12 kV feeders, acting on underfrequency in five programmable steps. The setting range for both steps shall be 50-47 Hz in increments of approximately 0.03 Hz. Time delay to allow a co-ordination between the different steps, settable between 0 - 120. sec for each step will be provided. The function must be guaranteed with voltage levels of +10% to -50% of the rated voltage. The function shall be blocked if the voltage is less than 80% of the rated voltage.

12.5 Transformer Differential Protection (87, Separ ated Unit)

The transformer differential protection device shall be able to protect 2 and 3-winding transformers. The protection principle is the comparison of currents of the different voltage levels to detect any difference i.e. fault condition. The measured current values are changed to restraining and differential currents. Tripping takes place if the comparison of the couple restraining /differential current is within the tripping zone (exception inrush). Faults within the protection range e.g. phase faults, earth faults and interturn faults shall be recognised.

The analogue input signals of the relay are sent through a RC lowpass filter to suppress high frequency parts ("aliasing"). The sampling rate shall not be less than 12 samples/period. This means a minimum sampling rate of 600 Hz for 50 Hz systems.

The input signals are digitalized by A/D converter. The transformer vector group will be compensated. The CT ratio fault is to take into account by program. Digital filtering leads to the harmonic contents of the differential (basic and second harmonic) and the restraining current (basic harmonic). The content of the second harmonic is used to restrain tripping during inrush conditions. The tripping characteristic has to be stabilised against external faults to avoid false tripping.

The relay shall be able in case of tripping events to store the input data for 1 s with 2 periods prefault data. The digital relay shall be controlled by self control routines (e.g. every 10 s) to avoid false function and to permit early detection of any fault inside the relay.

The Parameterizing of the relay shall be able by local control by keyboard or PC and on the other hand by MMI from the station or network control level.

The measured values are compared phase by phase. If there is one phase faulty the tripping takes place. If in only one phase inrush conditions are detected tripping is restrained. The command time of the relay shall not be higher than 35 ms.

The differential protection device shall provide the possibility of external binary signal acquisition for the purpose of indication and fault recording. Interposing CT's included on the relay. Tripping and Lockout relays should be provided to prevent re-closure, both manual and automatic, until the lockout relays are reset (shall be electrical reset).

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12.6 Overcurrent Protection (50/51, 50/51N)

The overcurrent protection device shall be provided built-in BCUs with phase and earth fault elements. This relay shall be segregated measuring, alarms, annunciations and settings. At least four selectable characteristics for the phase elements shall be included according to IEC 60255-4 and BS 142 :-

normally inverse characteristic very inverse characteristic extremely inverse characteristic definite time characteristic additional long time characteristic for the earth element

Instantaneous trip order for the phase element with a implemented timer and a set position to block their trip shall be provided.

12.7 Breaker failure protection (50BF)

Breaker failure protection (50BF) shall be provided built-in for all BCUs and Distance Protection. The phase currents of the feeders shall be monitored for each phase.

The overall reset function of the 50BF system shall not be slower than 25 ms. It shall be sensitive to detect from 0.2 to 2.0 times the rated feeder current, adjustable in steps of less or equal to 0.2 times of this current and being able to be operated continuously at 1.2 times the rated current.

12.8 Feeder Protection 24/12 kV

The overcurrent protection device shall be provided with phase and earth fault elements.

Overcurrent protection Overcurrent Earth Fault protection 3 phase overcurrent with the same characteristics as directional overcurrent

protection

At least four selectable characteristics for the phase elements shall be included according to IEC 60255-4 and BS 142:

normally inverse characteristic very inverse characteristic extremely inverse characteristic definite time characteristic additional long time characteristic for the earth element

All setting will be entered by means of a built-in keypad and a external software. Comprehensive data accumulated in the memory for post fault analysis retrieved through the serial interface into a personal computer.

Instantaneous trip order for the phase and earth element with a implemented timer and a set position to block their trip if necessary.

A sensitive earth fault relay (0.02 - 0.8 In) shall be provided. A extensive timer 0.1 - 6.0 sec shall provided the co-ordination with the down stream overcurrent relays.

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The Earth Fault protection shall be controlled “ON” and “OFF” by BCU internal S-R Flip-Flop which can be operated by a manual switch on the panel or through the SA control command. One lamps, LED, marked “OFF” shall be fixed on the panel near the double throw switch to indicate the status of earth fault protection.

12.9 Auto-Reclosing for Feeder 24/12 kV

Auto-reclosing function shall be provided at least 3 shots. The auto-reclosing function shall be started from overcurrent and earth fault protections and shall operate in the following manner : After being started by either protection, and after the circuit breaker has tripped, the first auto-reclosing shot shall be 0.2- 4 seconds(adjustable) dead time, a second shot after 15-60 seconds(adjustable) dead time, and the third and last shot after another 30-180 second(adjustable) dead time. After closing circuit of the circuit breaker has been energized , the auto-reclosing shall start reclaim time for 15-180 seconds(adjustable) to start an autoreclosing sequence, in case of close on to fault the reclaim time shall be stopped immediately by tripping command of protection functions. In addition to after first re-closing, the instantaneous overcurrent and instantaneous earth fault functions shall be blocked, in order to allow coordination of protection functions with downstream protections devices. The auto-reclosing shall be provided with an operation counter according to auto-reclosing sequence timing diagram. The auto-reclosing function shall be controlled “USE” and “LOCK” (meaning “in use” and “blocked”) by BCU internal S-R Flip-Flop which can be operated by a manual switch on the panel and through the SA control command. Two lamps, LED, marked “USE” and “LOCK” shall be fixed on the panel near the double throw switch to indicate the status of auto-reclosing function.

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Auto-reclosing Sequence Timing Diagram

12.10 Trip Circuit Supervision (74)

The trip circuit supervision circuits shall be provided to monitor the continuity of the circuit breaker tripping circuit at both close and open conditions from relay output to two trip coils in the CB. Trip circuit supervision shall be included the Distance Protection and all BCUs. All Distance Protections and all BCUs shall be provided two contacts for annunciator and nearby BCU, for SA alarm is sent through ports per IEC 61850

12.11 List of Approved Manufacturers

Protection relays acceptable to MEA shall be from manufacturers listed below :-

ABB

ALSTOM GRID UK LIMITED

GE

Siemens

Schweitzer (SEL)

SEG

I>,Ie>

AR Close Command

Lockout

Dead Time 3th shot Dead Time 1st shot

Dead Time 2nd shot

Reclaim Time

CB open

CB Close

CB Status Reclaim Time

Reclaim Time & Lock out Time

I>>,I>,Ie>>,Ie> Protection Tripping Command

I>,Ie> I>,Ie>

1st shot 2nd shot 3thshot

1st Trip 2nd Trip 3thTrip Final Trip

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Schneider Electric

2.2 FAILURE and MAINTENANCE MANAGEMENT

Using a network-based system configuration offers numerous opportunities for elevating the station’s business value, but it also requires consideration of how potential failures or scheduled maintenance activities may affect system operation. Since a Substation LAN is shared for all information-related processes, any failure or disruption that significantly impairs network communications has the potential for bringing down a critical portion of the whole system. Other factors can also cause such a problem. It is very important to anticipate these situations and to mitigate the overall risk to an acceptable level. Failure and maintenance management is the means employed to achieve this, and it is intimately involved with system reliability and availability, which are addressed in the clause titled System Design Constraints.

The objective of failure management is to provide a set of resources and mechanisms that can automatically isolate the system from the effects of otherwise critical failures. This is not to say that all situations can be so managed, or that system operation can be fully restored. It is rather the capability to perform damage control, limiting the loss of system functionality to non-critical functions whenever possible and diminishing the overall risk of critical failures occurring.

The objective of maintenance management is similar. There will surely be occasions when personnel need to take a system resource off-line for maintenance, updates, or testing. Although these are not failure scenarios, they can potentially have the same effects on system operation. Fortunately, these situations are planned and generally under utility control. The same resources and mechanisms used for failure management may be applied here. In addition, the Operator Interface [MMI] may be a valuable asset, allowing the operator to intelligently prepare the system for the scheduled activity in an advantageous way.

Resources and mechanisms for failure and maintenance management are listed below. Think of these as countermeasures. One or more of these will be incorporated into system design for reasons that go beyond failure and maintenance management; they are marked with an asterisk. Others are simply candidates that seem to offer advantageous capabilities. This specification does not presume to state how these ought to be specifically applied in a bidder’s system proposal, but it is expected that such applications will be imaginative and effective. Bidders are encouraged to add to the list. Bottom line, straight redundancy has its place but is a brute force approach. System proposals shall describe the measures to be used, how they would be applied, and why they are effective. It is recommended that bidders consider the system availability requirements and critical outage definitions when responding.

In all this, remember that Terminal Stations will normally be manned and have permanent Operator Interface MMI] facilities. Substations will normally be unmanned, and the Operator Interface [MMI] is outside at RCC, a portable resource that has to be brought to the substation.

1. Two redundant Substation LANs

There are two principal reasons for the use of two Substation LANs: (1) MEA’s standard protection practice already uses two independent sets of relays, an A-set and a B-set. As relay IEDs are deployed, it is natural to associate Substation LAN A with the A-set of protection devices and Substation LAN B with the B-set of protection devices. (2) The A-set and B-set devices work completely independently of each other, racing to complete protection actions when faults occur. If one fails, the other can be expected to perform the required functions. This works well and provides high system reliability as long as failures are repaired promptly, ensuring that both sets are normally operating. Other types of IEDs can reside on each Substation LAN alongside the relay IEDs.

2. Dual Substation LAN Connections

Certain critical IEDs shall be connected to both Substation LAN A and Substation LAN B. These include the CCU, CGW, MMI and TDS. In all cases, only one

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connection shall be active at a time. Normally, it is the primary connection. Where these IEDs are not equipped redundantly, the primary connection shall be Substation LAN A. Where they are, the primary connection for the second IED shall be Substation LAN B. Note that redundantly equipped IEDs must use different IP addresses.

If an IED determines that its primary connection has an operational problem, it will switch to its standby connection until such time as the primary connection is restored. These dual connection provisions protect system availability and offer a measure of operational resilience when network switch failures and certain other types of failures occur.

Operator Interface [MMI] units located at Terminal Stations are equipped with dual Substation LAN connections. These operate in a similar manner, except that the operator shall simply force the connection to either Substation LAN A or Substation LAN B. For MMI units, the concept of primary and standby connections does not apply. In other words, the Operator Interface [MMI] will not automatically switch from one connection to the other. This protects the operator against unexpected switching while he is working and provides him with additional flexibility that he may need in unusual situations. In all cases, the Operator Interface [MMI] shall continuously show the connection status (Substation LAN A or B) in the same location on all system displays. Portable MMI units, which are notebook-based, only support one Substation LAN connection, so this capability description is not applicable to them.

But using any MMI unit, an operator can temporarily lock any other IED having dual connections to either Substation LAN A or Substation LAN B. The intent is to place and maintain the system in a state that is under the operator’s control while he is isolating or resolving a problem. This status shall be shown on the ‘Station Status’ display as an abnormal state, shown on the ‘Abnormal Points Summary’ display, shown on the ‘Communications Status / Operational Status’ and cause an ‘Alarm Summary’ entry. These actions shall be taken to ensure the lock is manually removed before the system is returned to normal service.

3. Redundant CCUs

The CCU is a critical system resource. If the CCU is lost, the system goes down and the system logs are at least temporarily (perhaps permanently) lost. When the CCU is restored, the system will begin operation anew with no recorded history to rely on. For sites where this is unacceptable, a standby CCU is required. This is also a sure way to increase system availability.

When there are two (i.e. redundant) CCUs in a system, the MMI operator shall designate one as the primary CCU, and the other assumes the standby role. These terms are not to be confused with primary and standby connections, as described under the ‘Dual Substation LAN Connections’ heading above. These concepts, however, do work in tandem.

The primary CCU actively runs the system. When a standby CCU goes on-line, the system will have been operating for an indefinite period of time (which may be no time at all). The standby CCU is not aware of the system’s recent operational history or its current operational state. To the extent they exist, they are maintained in the primary CCU’s system logs (e.g. StatusLog, CommandLog, ChangeLog, SubLog, FileLog) and Local Repository. Consequently, the standby CCU shall read and replicate the system logs, and then enter a listening mode. In listening mode, the standby CCU shall monitor and process all system communications that affect the content of its Repository or system logs, ensuring that it updates them in the same manner performed by the primary CCU.

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These actions prepare the standby CCU for reassignment as the primary CCU, should the need arise or a test be conducted.

Control commands, configuration changes, value substitutions, file transfers and deletions, and reports, are only executed through the primary CCU. The standby CCU only makes system log entries and Repository updates that result from these actions.

The standby CCU shall become the primary CCU if any of the following occurs:

The Operator Interface [MMI] unit designates it as the primary CCU.

The primary CCU is not issuing heartbeat messages or indicates that it has serious health problems. In this case, the switchover shall be automatic.

In this case, the system temporarily promotes the standby CCU to primary. When the failed CCU is restored on-line, the system will want to again make it the primary CCU, per the operator’s standing preference. This shall not occur until the restored CCU has read and processed the system logs from the other CCU. In addition, a user-defined delay interval (e.g. 30 minutes) shall be imposed to give the restored CCU a reasonable time to update its Repository.

Current thinking is that redundant CCUs shall be used at all sites as a defense against critical system failures, since the CCU is responsible for a number of critical functions and resources (e.g. the Local Repository).

4. The Portable Operator Interface [MMI]

It has been noted elsewhere that Terminal Stations shall have a permanent, desktop-based Operator Interface [MMI], whereas Substations, being normally unmanned, shall not. When Substations require the use of an MMI unit, a portable, notebook-based unit shall be taken to the site for temporary use. This portable MMI concept also provides a ready solution to the problem of backup, should an Operator Interface [MMI] unit fail at any site, whether Terminal Station or Substation. For Terminal Stations, it means that a permanent backup MMI is not required.

The one problem that needed to be solved, however, is how to bring a portable MMI into a station site and make it aware of the system’s operational history. Otherwise, the operator cannot see anything more than the system’s current state. The solution, in line with the groundwork laid in this specification, is to enable the MMI unit to read and process the system logs resident in the primary CCU. This is discussed more fully under the Operator interface [MMI] heading.

5. Redundant Power and Converters

The following groups of equipment shall be powered separately from station battery using independent converters, so that no power failure can bring down more than one group:

IEDs and equipment normally associated with Substation LAN A

IEDs and equipment normally associated with Substation LAN B

6. Redundant IEDs

Redundant IEDs (e.g. CCUs, as described above) can lower the risk associated with certain kinds of system failures, since their functions continue to operate when one of the pair fails.

7. Use of Contingent Peers

It is frequently the case that IEDs work interdependently to implement some distributed, programmed logic application. In such cases, each IED depends on its peers to keep the

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application working properly. If one of these IEDs detects that the heartbeat of one of its dependent peers is not being broadcast, it may use a contingent peer to substitute for the non-operational one. (Refer to the description of the heartbeat function under the heading titled Programmable Logic Applications.) Use of contingent peers requires planning, of course, and would generally be used only for critical functions. This approach has been successfully applied in an operating station in Tennessee.

8. Managed Ethernet Switches

Managed switches can provide capabilities that deal with communications network faults, different classes of IEDs, and priority issues. Some of these capabilities and related industry standards are bulleted below:

IEEE 802.1p: Prioritization to allow real-time, critical messages to get through

IEEE 802.1Q: VLAN to allow isolation of critical IEDs from non-critical IEDs

IEEE 802.1w: Rapid Spanning Tree to allow fault-tolerant ring architectures with rapid reconfiguration times

Managed Ethernet Switches acceptable to MEA shall be from RuggedCom Inc. or equivalent. Each Managed Ethernet Switch shall be provided with a minimum of at 20 % spare communication ports.

For Bay level (all BCUs and Protection relay), Integrated Ethernet Switches is also accepted.

9. Redundant Systems Testing and Demonstration

All Redundant Systems shall be tested and demonstrated during FAT and SAT.

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3 FUNCTIONAL REQUIREMENTS This clause describes the functions to be supported by the delivered systems. These functions shall enable dispatchers from the SCADA/EMS control center and substation operators to monitor and control MEA’s station systems and shall fully support advanced applications specified in this specification.

The SA system shall incorporate hardware and software interlocks to ensure that substation plant controls can only be affected from one location at any time.

3.1 SYSTEM CONFIGURATION

The following represent important implementation issues for the station systems:

1. SCL-Compliance

Not only shall all IEDs supplied for this bid be compliant with the IEC 61850 communications standard, but they shall be configured using SCL-compliant tools, files, and procedures as described in IEC 61850, Part 6.

2. Remote Configuration and File-Based Maintenance

All system software, applications, and devices (e.g. IEDs) shall be designed to facilitate easy re-configuration and program updates via remote file downloads. Some proprietary files may be required for an entity to operate as intended, but this is not a problem as long as the content of those files does not adversely affect IED or system communications interoperability, as defined by IEC 61850.

3. Structure and Content of the Local Repository

The structure, information models, interfaces, and services of the Local Repository shall comply with the IEC 61850 communications standard.

As shown in Figure 2, the Repository shall contain two sets of IEC 61850-compatible schemas: Proxy ‘Server Views’ and Proxy ‘Client Views’. Design implementation shall not limit the growth of the Repository over time, as some sites may appreciably increase in scope. No programming or system regeneration shall be necessary for adding or modifying components; reconfiguration through the SCL configuration process shall be used.

Proxy ‘Server Views’

These replicate the actual Server Views held in IEDs, to the extent their use is contemplated by MEA.

As a minimum, all Logical Devices (i.e. domains) belonging to those IEDs need to be shown. This is important, because files related to server IEDs are referenced through their associated Logical Devices. Because of the way file transfer functionality is specified, files need to be referenced in both IED ‘Server Views’ and Proxy ‘Server Views’.

Proxy ‘Server Views’ shall only be used to support browsing, so that operators and system designers can determine what data is available from each IED Server and how that data is structurally organized. This means that all defined Logical Nodes, and the data they contain, shall be replicated from the IED Servers to the Proxy Server Views. The only exceptions are data that MEA agrees will never be used. IEDs shall not be directly browsed during normal system operation.

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Any time a related configuration file is updated and downloaded to a CCU or IED, the affected schemas shall be automatically updated. Given the way file management is specified, any reconfiguration of IED ‘Server Views’ shall automatically result in an identical reconfiguration of the corresponding Proxy ‘Server Views’ in both the primary and standby (if present) CCUs. Reconfiguration of Proxy ‘Client Views’ does not affect any IED besides CCUs, unless changes to structure and data affect existing client subscriptions. Such issues are generally handled by the SCL configuration process.

Proxy ‘Client Views’

While IED Server Views tend to be product-oriented, Client Views tend to be application-oriented. Client Views rearrange the way information is grouped and organized. This is done to suit the convenience and viewpoint of the client. In this specification, MEA is primarily focused on an operations viewpoint.

For example, MEA may wish to use Logical Device ‘XB_691’ to represent a transformer bay. The desired information content for this bay may include (1) breaker control and status, recloser status, and lockout status for two circuit breakers, (2) control and status for disconnect switches, (3) various transformer data and LTC control, (4) status for earthing switches, and (5) power system measurements at more than one point. Other views could be designed to suit maintenance, power quality, or station metering, or engineering perspectives. Each client is typically interested in a different slice of the available data and would like to see it represented in a way that best meets their needs. It frequently depends on the work culture of the group.

The desired content may be provided by several IEDs, each having a portion of the required data, so those various pieces need to be mapped to the content of XB_691 in the Client Views.

As shown in Figure 3, each Logical Node in a Client View may draw its data from one to several IEDs. Logical Nodes in the IED Servers may send different pieces of their data to different Logical Nodes in the Client Views. This requires a mapping process that links IED Server components with Client View components. SCL tools provide this capability. Note that this is a ‘pick-and-choose’ process that begins at the Logical Device level, and proceeds down through IEC 61850’s data modeling hierarchy:

Logical Device

Logical Node

Common Data Class

Data

Data Attribute

Some components at the lower end are mandatory, some are optional, and some involve interdependencies. The mapped linkages determine how data from the IED Servers is used to keep the Client Views up to date.

All data that the CCU selectively acquires (e.g. subscribes, polls) from IED Servers shall be stored in the Local Repository under both Proxy Server Views and Proxy Client Views. Related support data (e.g. operational parameters, configuration parameters, text descriptions) specified by the IEC 61850 data models shall also be included, except for those items that both optional and of no interest to MEA. Other categories of data to be represented within Client Views include the following, as long as they serve a defined purpose for MEA:

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Calculated data

Data generated by application programs

Diagnostic data (e.g. operational status) and system performance statistics

These are to be represented in a manner consistent with standard IEC 61850 information models and application usage.

The contractor shall consult with MEA and recommend schema for IEDs and client applications installed at the individual stations. The Repository structure and content shall be designed according to these specifications, documented by the contractor, and presented for MEA’s approval.

Per the IEC 61850 standard, real-time data values stored in the Local Repository are represented in engineering units. Where there is latitude in how those units are expressed (e.g. Volts or kV), the contractor shall propose choices for MEA’s approval.

4. Things to Avoid

Delivered equipment shall not use DIP switches, connection jumpers, wire-wrap techniques, or any similar technique for user-defined parameters.

5. Contractor Responsibilities

The contractor shall be responsible for integrating and configuring all required system software, applications, and equipment. These shall all be reconfigurable by MEA, using tools and procedures provided by the contractor, so that evolving operational requirements can be met.

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IED Server A

Server Views

IED Server B

IED Server C

IED Server D

…


IED Server A


IED Server B

IED Server C

IED Server D

…

LOC

AL

RE

PO

SIT

OR

Y

The structure and content of Proxy Server Views must be identical to the corresponding IED Server Views, to the extentthat the Proxy Server Views show Server View information. As a minimum, all Logical Devices (i.e. domains) must be shown.

Any file associated with a Server View is referenced through its associated Logical Device directory.

Any file associated with a Proxy Client View is referenced through its associated Logical Device directory.

Server Views and Proxy Client Views are created through the system configuration process.

‘Ser

ver V

iew’ con

tent is

selec

tively

used

with

in

‘Clie

nt View

s’,whic

h use

diffe

rent

‘Logic

al Devic

es’

IED ‘Server Views’ are replicated

in the Local Repository

These views

reflect the way

one or more

system clients

(e.g. operations)

see the

substation.

There may be

different views

for di fferent

clients.

IED Server A

Server Views

IED Server B

IED Server C

IED Server D

…

IED Server AIED Server A

Server Views

IED Server BIED Server B

IED Server CIED Server C

IED Server DIED Server D

…


IED Server AIED Server A


IED Server BIED Server B

IED Server CIED Server C

IED Server DIED Server D

…

LOC

AL

RE

PO

SIT

OR

Y

The structure and content of Proxy Server Views must be identical to the corresponding IED Server Views, to the extentthat the Proxy Server Views show Server View information. As a minimum, all Logical Devices (i.e. domains) must be shown.

Any file associated with a Server View is referenced through its associated Logical Device directory.

Any file associated with a Proxy Client View is referenced through its associated Logical Device directory.

Server Views and Proxy Client Views are created through the system configuration process.

‘Ser

ver V

iew’ con

tent is

selec

tively

used

with

in

‘Clie

nt View

s’,whic

h use

diffe

rent

‘Logic

al Devic

es’

IED ‘Server Views’ are replicated

in the Local Repository

These views

reflect the way

one or more

system clients

(e.g. operations)

see the

substation.

There may be

different views

for di fferent

clients.

Figure 2: Structure of the Local Repository

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IED Server B

IED Server A

IED Server C

LD root

Domain ALD_A

LN_1

LN_3

LN_2

Domain CLD_C

LN_7

LN_9

LN_8

LN_10

LD root

Domain DLD_D

LN_11

LN_13

LN_12

LN_14

LD root

Client

Domain ELD_E

LN_15

LN_17

LN_16

LD root

Domain B1LD_B 1

LN_4

LN_5

LD_B 2

LN_6

Domain B2

IED Server B

IED Server A

IED Server C

LD rootLD root

Domain ALD_ALD_A

LN_1LN_1

LN_3LN_3

LN_2LN_2

Domain CLD_CLD_C

LN_7LN_7

LN_9LN_9

LN_8LN_8

LN_10LN_10

LD rootLD root

Domain DLD_DLD_D

LN_11LN_11

LN_13LN_13

LN_12LN_12

LN_14LN_14

LD rootLD root

Client

Domain ELD_ELD_E

LN_15LN_15

LN_17LN_17

LN_16LN_16

LD rootLD root

Domain B1LD_B 1LD_B 1LD_B 1

LN_4LN_4

LN_5LN_5

LD_B 2LD_B 2LD_B 2

LN_6LN_6

Domain B2

Figure 3: Mapping Data between IED and Client Schem as

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3.1.1 IEC 61850 Configuration Tools and Process

The IEC 61850 communication standard provides a System Configuration Language (SCL) that can be used to configure communications for both IEDs and the entire system. It involves the use of several types of files, created for different purposes, and two levels of tools for creating and managing those files. The files are represented in XML (Extensible Mark-up Language), enabling the interoperable exchange of configuration and capability information between supplier tools. The semi-automated process (i.e. people still need to enter design intentions), illustrated in Figure 4, virtually eliminates hand-entry of information and manual configuration of equipment.

The four types of files that comprise SCL, listed roughly in the order they are used to produce a configured system, are the following:

1. ICD: IED Capabilities Description

This file describes the communications capabilities of an individual IED, and it is typically installed in the IED before shipment from the factory. The file can be extracted from the IED at any time. It contains no information about how the device is to be used in a target system, but does fully describe what communication services and information models can be supported by the IED.

2. SSD: System Specification Description

This file describes the functional specification of the whole secondary system at the station, including the communications system. Among other things, it captures a one-line diagram of the targeted system. It allows Logical Nodes [LNs] (i.e. functional pieces of the whole IEC 61850 information model) to be assigned to the various IEDs according to their functional roles and capabilities. These actions are typically performed using a single System Configuration Tool, selected from among those offered by IED manufacturers.

3. SCD: System Configuration Description

This file is created using the System Configuration Tool, the SSD file and ICD files for all IEDs used in the system. The result is a complete ‘process configuration’ for the secondary system, with IEDs bound to individual process functions, primary equipment, and client-access privileges. It also includes all predefined network associations and all client-server connections with LNs on a data level.

4. CID: Configured IED Description

When the SCD file has been created, it is used to create an individual, downloadable Configured IED Description file for each IED in the secondary system. This is achieved using the IED Configuration Tool provided by each manufacturer. As long as these tools have an interoperable SCL interface, as described by the IEC 61850 standard, they may be proprietary. This is often necessary, so that the tools can download additional IED configurational data that is proprietary in nature, but which does not affect system interoperability.

3.1.2 Open System Provision

Although these systems will be provided through a turnkey project, it is imperative that the resulting systems be open. It is not acceptable that MEA be locked into one or even a limited number of IED suppliers for future upgrades. Therefore, a special provision is required: The contractor shall demonstrate that two additional IEDs, each of different manufacture and approved by MEA, can be integrated into these systems using the SCL tools, files, and process described by the IEC 61850 communications standard. The open system demonstration shall be done during FAT and SAT. The open system experience/reference list of the supplier in supplying SA shall be submitted with the bid.

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Figure 4: The SCL Configuration Process

SystemConfiguration

Tool

‘IED Capabilities Description’ for every IED ( ICD Files )

‘System Specification Description’( SSD File )

SystemDatabase

IEDConfiguration

Tools

‘System Configuration Description’( SCD File )

‘Configured IED Description’( CID File ) for each IED

Different manufacturershave different tools

IED #1

IED #2…

IED #n

The CID file (or a vendor-specific file ) maybe used to configure the corresponding IED(via network download)

All files are stored in a‘substation database’ for record keeping and ongoing use

6666

An IED-independent,system-level tool

SystemConfiguration

Tool

‘IED Capabilities Description’ for every IED ( ICD Files )

‘System Specification Description’( SSD File )

SystemDatabaseSystem

Database

IEDConfiguration

Tools

‘System Configuration Description’( SCD File )

‘Configured IED Description’( CID File ) for each IED

Different manufacturershave different tools

IED #1

IED #2…

IED #n

IED #1

IED #2…

IED #n

The CID file (or a vendor-specific file ) maybe used to configure the corresponding IED(via network download)

All files are stored in a‘substation database’ for record keeping and ongoing use

6666

An IED-independent,system-level tool

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3.2 FILE MANAGEMENT

File management is concerned with the use, control, and organization of files in a system environment, so that required objectives are met.

3.2.1 Objectives

Files of various types are used with the IEDs of these systems. They include configuration files, software files, user-application files, and IED-generated data files. These files need to be managed and occasionally transferred, so that the system operates properly, reliably, and efficiently. MEA’s specific objectives include the following:

1. Download Capability: Devices need all their software, application program components, and configuration files if they are to work properly. Even if they are preloaded when the system is first commissioned, they will very likely need to be updated or replaced in the future.

MEA needs to be able to accomplish these changes via file-download procedures over the network, initiated from a remote location or at the station site, per MEA’s discretion on each occurrence. File services are needed to perform these downloads and to delete files that are no longer relevant.

2. Upload Capability: Sometimes, during system operation, IEDs may generate data files (e.g. disturbance files). These files need to be uploaded to a higher system level and then directed to one or more clients for analysis. The IEDs that generate these files have limited resources, and they may need to get the current file uploaded relatively quickly, so that they have freed resources (e.g. memory) to accept the next file, whenever it may be generated. So a mechanism is needed for the responsible system component to recognize when a new data file is present and a file-upload service is needed to transfer the file.

3. File Attribute and Directory Services: The file management procedures must be relatively simple and foolproof, to avoid confusion and ensure reliable results. And because operators occasionally need to check their assumptions, they will want confirm that files reside where they are expected and that the files have the proper attributes (e.g. last-time-modified). So file services are needed to provide these capabilities.

4. Audit Trail for File Transfer Activity: From a system perspective, it is important to keep an audit trail of significant occurrences. File transfers are always important, as personnel need a reliable record of past transfers. Such information may be needed at a future time when analyzing a problem and deciding how to proceed. An audit trail should create a record each time a file is transferred or deleted, recording the file name, its attributes, where it was transferred from and to, and what party (or client) authorized the transfer.

3.2.2 An Approach

The selected approach to file management is based on the IEC 61850 communication standard’s file services. These five services are combined with the creation of a File Agent application that runs on the CCU. Unlike programmable logic applications, which are typically applied to implement user-related functions, the File Agent is a software utility that performs a general system function. The File Agent performs file transfers when necessary, sometimes automatically and sometimes when a system client initiates the action. The way this happens is shown in Table 1 for the various file transfer scenarios. The File Agent does not need to interpret file content.

The File Agent also creates and maintains a chronological FileLog, which records information about each transfer and thus provides an audit trail for file transfers. The FileLog is available to system clients at any time and can be read selectively, using IEC 61850 log services. System

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clients shall use the FileLog, StatusLog, CommandLog, SubLog, and ChangeLog to reconstruct recent system history when necessary.

Note: Initiated by using SetFile service to place the target file into the target IED directory of the Local Repository.

Table 1: File Management

3.2.3 File Agent Responsibilities

The File Agent’s specific responsibilities include the following:

1. Process all File Transfers

The File Agent shall process all file transfers between clients and servers, with support from the Local Repository.

2. Use IEC 61850 Specifications

File-Related System Capability

IEC 61850 Service IEC 61850 Service Model

File Types Affected

Target IEDs Authorized Initiating Client

Configuration

Software

BCU, TDS, CCU

Op. Interface [MMI]

Prot. Relays

Remote File Mgr

Op. Interface [MMI]

Download files to IEDs

(via File Agent)

SetFile

File

User Apps BCU, CCU

Op. Interface [MMI]

Prot. Relays

Remote File Mgr

Op. Interface [MMI]

Configuration

BCU, TDS,

Op. Interface [MMI]

Prot. Relays

Remote File Mgr

Op. Interface [MMI]

Upload files from IEDs to CCU

(via File Agent)

GetFile File

Data Prot. Relays (future) File Agent (CCU)

Configuration

Software

User Apps

BCU, TDS, CCU

Prot. Relays

Remote File Mgr

Op. Interface [MMI]

Data Prot. Relays Remote File Mgr

Op. Interface [MMI]

Delete files from IEDs

(via File Agent)

DeleteFile File

Configuration

Software

User Apps

Op. Interface [MMI] Remote File Mgr

Configuration

Software

User Apps

BCU, TDS, CCU,

Op. Interface [MMI]

Prot. Relays

Remote File Mgr

Op. Interface [MMI]

Read file attributes

(file name, size, time-last-modified)

GetFileAttributeValues File


Op. Interface [MMI]

Configuration

Software

User Apps

BCU, TDS, CCU,

Op. Interface [MMI]

Prot. Relays

Remote File Mgr

Op. Interface [MMI]

Read file directory

GetServerDirectory

(Files)

Server


Op. Interface [MMI]

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The File Agent shall use the file services, file structure, file attributes, and other file characteristics specified (or recommended) by IEC 61850 to maintain interoperability within the station.

For example, file names shall use extensions to differentiate the various kinds of files (e.g. programs, configuration, disturbance records). All files shall use a single file format: sequential unstructured binary. All files shall carry three attributes: File name, file size, and last-time-modified.

Per IEC 61850-8-1, Clause 23.1: Files names may be constructed as file name references, beginning with a sequence of directory names (separated by a ‘slash’ delimiter) and ending with the actual name-of-a-file. The sequence of directory names always begins with a LogicalDevice directory under the LD root directory of the Server (i.e. server IED). This is because IEC 61850 requires every file to be contained within an associated LogicalDevice. This file naming convention shall be universally used in the delivered systems, because it is necessary for the capabilities described in item 3 below.

IEC 61850 services shall be used to implement all file services for transfers within the station. These can be found in IEC 61850-7-2 under Server Class Services (GetServerDirectory) and File Services (all the others). These services shall operate over MEA’s Substation LANs (as specified by the IEC 61850 network profile) and MEA’s fiber optic SDH WAN. File transfers shall be segmented and transferred with low priority to prevent contention with higher-priority transfers.

3. Synchronize File Presence between the Local Repo sitory and Server IEDs

As the System Configuration clause describes, IED ‘Server Views’ and Proxy ‘Server Views’ shall be identical. In particular, this means they both contain the same set of Logical Devices. This is an important issue, because it affects how files are stored and managed, as described below:

When an authorized system client uses the SetFile service to send a file to the CCU, the File Agent shall ensure that files associated with Server Views are written in two places: (1) the associated IED and (2) the CCU(s). In both cases, the targeted location is provided by the file name reference, which always begins with a Logical Device name. If the downloaded file has the same name as an existing file, the File Agent shall replace the existing file with the new one in both places.

Similarly, if an authorized system client applies the FileDelete service to a file associated with a Server View, the File Agent shall ensure the file is deleted from two places: (1) the associated IED and (2) the CCU(s). As before, the targeted location is provided by the file name reference, which always begins with a Logical Device name. See Figure 5.

Files associated with Proxy ‘Client Views’ are similarly written or deleted, but only in the CCU(s).

If an authorized system client uses the GetFile service to fetch a file, no collateral action is required. If the file is associated with a Server View, the File Agent shall use the CCU source.

4. Transfer Only One File at a Time

The File Agent shall enforce the rule that only one file can be transferred at a time.

5. File Transfer Blocking Option

The File Agent shall allow the SCADA/EMS system to block file transfers altogether in periods of high stress, using an SBO-controlled File Transfer Mode Switch (FTMS).

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6. FileLog Maintenance

The File Agent shall create and maintain a chronological FileLog. A new FileLog entry shall be made when each file transfer has been completed. The recorded information shall include the date and time, all file attributes, where it was transferred from and to, and what party (or client) authorized the transfer.

LD_A/FileDir1/AllanAllan

Boris

Charles

names-of-files

IEC 61850 ‘File References’

LD_A/FileDir1/Boris

LD_A/FileDir1/Charles

LD_B/FileDir2/DerekDerek

Ernest


names-of-files

LD_B/FileDir2/Ernest

Logical Nodes

Logical Device A

Logical Device B

Logical NodesDomain B1

LD_B

LD root

LNs

FileDir2

FileDir1

LNs

LD_A

LD_A/FileDir1/AllanAllan

Boris

Charles

names-of-files


LD_A/FileDir1/Boris

LD_A/FileDir1/Charles

LD_B/FileDir2/DerekDerek

Ernest


names-of-files

LD_B/FileDir2/Ernest

Logical Nodes

Logical Device A

Logical Device B

Logical NodesDomain B1

LD_BLD_B

LD rootLD root

LNsLNsLNs

FileDir2FileDir2

FileDir1FileDir1

LNsLNsLNs

LD_ALD_A

Figure 5: Every IEC 61850-Compatible File is Assoc iated with a Logical Device

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3.2.4 File Transfer Initiators

Only the following clients shall be authorized to initiate the file transfer services shown in Table 1:

1. Any Operator Interface [MMI] client at the station (assuming the operator has authorization to perform file management).

2. A File Management Client at a remote location (assuming the operator has authorization to perform file management).

3.3 DATA ACQUISITION

The CCU is responsible for collecting the data that populates the Local Repository. In general, this includes all data that is being subscribed by client applications (e.g. SCADA EMS, Operator Interface [MMI] units, and automation programs, as well as any other classes of data that MEA wants to see included. Most of the data is expected to be spontaneously sent to the CCU via IEC 61850 reporting services. Reports are set up for each system client via IEC 61850’s SCL configuration tools. The CCU needs to poll for any remaining data.

The principal sources of data in the systems covered by this specification are BUCs, Protection Relays, the CCU itself (from automation programs, which are generally realized with programmable logic), the Operator Interface [MMI] units, which may change settings for devices, applications, and system processes, and their future presence shall be anticipated in these systems to the extent possible.

In many ways, the real-time data acquisition and control responsibilities of these systems are similar to those of traditional RTU systems: Status and SOE inputs, measurement inputs, counter inputs, and control outputs. But in forward-looking ways, there are tremendous differences. The IEC 61850 communications standard provides tremendous flexibility and information support that places such systems in a different league. Data naming, structural relationships among data within hierarchical information models, text fields for self-description, consistent but flexible operational configurability, data management tools, browsing, and SCL configuration tools for IEDs and the system are all far beyond traditional practice. All these affect what information must be stored in the Local Repository and the communication services that must access and manage that information. Data acquisition of real-time data represents only a part of the information flows that will circulate through the Repository.

3.4 DATA PROCESSING

3.4.1 Data Quality

Every data value, whether a field value, calculated value, or pseudo-value, has an associated data quality, as defined by the IEC 61850 Common Data Classes. The data quality attribute has a number of constituent bits. When none are asserted, the data quality attribute is considered to be normal, meaning no special considerations need to be made when processing its associated data value. When any of the quality bits is asserted, it can mean various things, such as the data is bad, the data is a test value, the source of the data is operator-blocked, and so on. In general, it’s up to each application that uses the data to decide what course of action to take regarding asserted quality bits. In any case, data quality needs to accompany data values in the Local Repository and in individual IEDs, meaning that data quality always needs to always accompany a data value.

Depending on circumstances, what starts out as a good data value with normal data quality may be adversely affected as it travels the system. System applications need to know this information and IEC 61850 has provided a standardized means to track it. The IEC 61850 data quality definitions shall be invoked wherever possible. If a serial data communication port hands off its

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data for conversion, the data quality conversion to IEC 61850 shall follow, in the best way it can be mapped. The same goes for data derived from a legacy source. If no data quality is available for a value, look for criteria to assess it and fold those criteria into the IEC 61850 data quality scheme.

3.4.2 Event Processing

This specification considers an event to be any monitored, time-tagged occurrence that represents a change in system state. Such events may result from status changes, control commands, changes to operational parameters, use of substitution services, or file transfers and deletions. This expanded view of event data is a consequence of the IEC 61850 standard’s communication capabilities. SOE data, as defined for a certain subset of system events, retains its original meaning.

1. Event Sources

The following represent the types of events that may occur in a system. Each event type is followed by a list of the IEC 61850 Common Data Classes (CDCs) that may be used with that type.

Changes in status for protection relay funtions, auxiliary breaker contacts, and contacts of other primary and secondary sources; changes in computed status; changes in integer status; changes in controllable status: CDCs SPS, DPS, ACT, ACD, SEC, or BCR.

Changes in integer status: CDC INS.

Changes in status associated with controllable status information: CDCs SPC, DPC, INC, BSC, or ISC.

Movement of measurement values from one user-defined operating region to another: CDCs MV, CMV, WYE, DEL, or SEQ.

2. Use of IEC 61850 Range Limits for Measurements

The IEC 61850 range limits for measurement values shall be applied as follows:

‘Normal’ Operating Region: The ‘high’ and ‘low’ limits shall be used to define this region. Values for power system variables are expected to fall within this region.

‘Warning’ Operating Region: The ‘high-high’ and ‘low-low’ limits shall be used to define this region. Values in this region indicate that some kind of operational correction is required.

‘Emergency’ Operating Region: The ‘min’ and ‘max’ limits shall be used to define this region. Values in this region indicate exceptional conditions requiring immediate attention.

Out-of-Range: ‘Min’ and ‘max’ represent the boundaries for measurements within process limits. Data outside these limits is questionable and may indicate equipment failure. Accordingly, data quality shall be marked ‘questionable’ and ‘out-of-range’.

When an analog data value transitions into an out-of-range region, the last reasonable value shall be retained in the Repository. It shall not be updated again until the value leaves the out-of-range region.

3. Processing

All events shall be time-tagged at the time of occurrence, as detected/determined by the monitoring/processing source (e.g. BUC or other IED)

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Time-tagging resolution shall be a maximum of 1 ms, relative to the internal clock of the monitoring/processing source.

Event records can be cleared at the source once successfully reported. Reports use confirmed services, which ensure that the server is notified whether each transfer is successful. Pending events at a server shall not be lost.

Contact inputs: Changes in signal state shall be time-tagged at the time of transition, although such changes must be validated before they can be accepted, processed, and reported.

Validation shall be achieved by applying digital filtering to ensure changes persist for at least a user-defined period of time before they are accepted as genuine.

IEDs shall be able to detect a quick sequence of multiple changes in status for the same point and ensure that all those changes are reported. This assumes that individual status transitions persist sufficiently long to qualify for validation.

These sequences of changes may arise, for example, from breaker TRIPs alternating with RECLOSE operations.

Server IEDs shall support both buffered and unbuffered IEC 61850 event reporting. It shall include integrity reporting, set at a user-defined interval. Buffered reports for any server shall be capable of supporting 10 times the number of reportable entities; this minimizes the chances of data loss if reporting capabilities are temporarily disabled. Event buffer overflows shall be reported to the CCU.

The contractor shall recommend which optional and/or new attributes to support in each CDC placed into service for the delivered systems.

3.4.3 Status Processing

Status processing is identical to event processing. If client applications don’t want the time-tag, they can ignore it.

3.4.4 Measurement Processing

1. Power System Measurements

The following power system measurements shall be available in the Local Repository. If they cannot be acquired from an IED server (e.g. BCU), the CCU shall derive them by calculation, using a system utility or programmable logic application.

Phase-to-ground RMS voltages

Line-to-line RMS voltages

Phase RMS currents

Neutral RMS current

Power direction

kW, kVA, kVAr (per phase and total)

kWh, kVArh (input, export, net)

Power factor (per phase and total)

Minimum, maximum, and average RMS values for the following shall be acquired or calculated over user-specified intervals, and saved in the Repository:

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Voltage

Current

Apparent power (VA)

Real power (W)

Reactive power (VAr)

2. Sources

Mainly CTs and PTs connected to and processed by BCUs (i.e. no DC transducers).

Measurement values are used in IEC 61850 CDCs MV, CMV, SAV, WYE, DEL, SEQ, HMV, HWYE, and HDEL.

DC transducers (perhaps a few, if necessary)

3. Processing

Measurement values shall be reported when changes since the last report exceed a user-defined deadband

Deadbands and operating regions shall be user-defined for each individual measurement. Deadbands shall be specified in 1% steps. These capabilities are supported by the IEC 61850 standard.

Measurement values shall be reported after device power up, after power recovery, or when the device is returned to on-line status.

DC Analog Inputs: Analog input modules shall be regularly checked against a stable reference voltage for linearity and DC-offset at zero volts. Encountered problems shall be recorded in data quality, causing the data to be marked invalid, and this can be returned to the SCADA/EMS control center and MMI workstations.

3.4.5 Control Command Processing

The CCU is responsible for coordinating the execution of all control commands initiated by system clients. This shall ensure that the Local Repository and system logs are kept up to date for system clients.

Only one control command at a time shall be executed. All attempted control operations, whether successful or not, shall be entered into the CommandLog. IEC 61850 enables all control operations to be tracked to the initiating party; this information shall be made part of each CommandLog entry.

MEA requires that all control operations be completed with confirmation that the desired device status has been achieved within a user-specified ‘completion period’. Control operations that fail to complete within the assigned time period shall result in ‘Control Failed to Complete’ alarms. Control failures shall not be automatically re-attempted. Jog controls shall be similarly alarmed if they do not result in a user-defined amount of position change within their assigned ‘completion period’.

The duration of operational contact closures is not controlled by IEC 61850 configuration tools. This shall be independently configured for the station’s various control points. An MMI template shall allow an operator to make user-defined assignments of contact closure time for applicable control points. The duration shall be adjustable for individual points, ranging from 100 ms to 60 s in steps of 100 ms. The template shall also allow the operator to change control time-out periods, ‘control completion periods’ (2 s to several minutes), and minimal jog-control travel within an assigned ‘completion period’ (for applicable points).

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A supervisory control request shall be rejected if any of the following conditions exists for the targeted control point:

1. The device is not subject to supervisory control of the type being attempted.

2. Another control operation is in progress.

3. The requested control operation is inhibited by a tag.

4. The point has failed or is otherwise out-of-service, or if an associated status point is represented by manually substituted data.

3.4.5.1 Control Initiators

A control operation can be initiated by any of the following station and enterprise clients:

1. A SCADA/EMS control center, where commands are issued by dispatchers

2. An Operator interface [MMI] unit, where commands are issued by operators

3. Applications that are designed to use control operations to fulfill their operational objectives. In these systems, they may be installed on the EMS/SCADA control center, an Operator interface [MMI] unit, or on other IEDs. They typically evaluate process inputs and perform calculations to determine when to issue control commands. When installed in the station, they are likely to be implemented with programmable logic.

3.4.5.2 Types of Control Operations

The IEC 61850 control model enables a wide range of control modes, which cover virtually all traditional utility control practices. These shall all be supported by the delivered systems. The various types of control operations are summarized below. They are described in more detail than other topics in this specification, because control usage is generally a sensitive topic and it is desirable to make the various IEC 61850 control capabilities visible for application considerations. Because of the breadth of control possibilities offered by IEC 61850, it would be less straightforward to lay out the desired range of control functionality in traditional terms.

3.4.5.2.1 Control of Two-State Devices

These operations use a two-state control variable to switch devices to one of two possible states. They are supported by the SPC (Controllable Single Point) CDC (Common Data Class). In all cases, a control point must be selected before a command can be executed. Individual instances of use can be configured to use either SBO or direct control mode, to operate once or possibly many times per selection, and to operate with normal security or enhanced security. Enhanced-security requires that a control operation be confirmed by a change in status for the controlled device; normal-security does not … status is reported independently. If SBO control mode is used, device selection is required before the control can be executed, and the selection status can be validated by the CCU. These control operations permit a time-of-operation to be assigned (optional), for applications where synchronization to a particular time is necessary. A configurable SBO time-out period is provided. Provisions allow use of pulse trains and variable length pulses.

MEA’s typical usage of this kind of control will be applied to circuit breakers and certain other switches that switch very quickly. They shall use Select-Before-Operate (SBO) control mode, operate-once control mode, and enhanced-security mode (in support of monitoring ‘control completion’).

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3.4.5.2.2 Control of Three-State Devices

These operations are identical to that of two-state devices, except they are typically applied to slowly switching devices like motor-operated disconnect switches. The status of these devices may be open, closed, or in-transition, which requires three possible states. These operations are supported by the DPC (Controllable Double Point) CDC. A two-bit binary status is provided, with the fourth state interpreted as invalid.

3.4.5.2.3 Control of Integer-State Devices

These operations are very similar to that of two-state devices, except they allow a very large number of control states (as many as can be expressed with a 32-bit integer). For application convenience, a step-size can be configured that defines the step between successive control values. Issuing a control value of zero resets the controlled device.

Pulse capabilities are not applicable. Otherwise, the same control modes and comments apply. These operations are supported by the INC (Controllable Integer Status) CDC.

3.4.5.2.4 Incremental Device Control (Jog Control)

These operations are used for applications requiring incremental step control, as with LTC control. The three control states are ‘higher’, ‘lower’, and ‘stop’. A maximum of 128 positions can be accommodated. A step-size can be configured that defines the step between successive control values. The status for these control points shows the current position and can also show when the state is in-transition (i.e. between positions). An option allows this command to be ‘persistent’ until deactivated. This feature may be intended for devices that need a persistent value to be applied while the device mechanism responds.

Pulse capabilities are not applicable. Otherwise, the same control modes and comments discussed for two-state devices apply. These operations are supported by the BSC (Binary-Controlled Step Position Information) CDC.

3.4.5.2.5 Integer-Controlled Step Position Devices

These operations are for device applications requiring variably-sized steps. Unlike incremental device control, new control positions are achieved through a single command that immediately switches the device from the old position to the new. A step-size can be configured that defines the step between successive control values. The status for these control points shows the current position and can also show when the state is in-transition (i.e. between positions).

Pulse capabilities are not applicable. Otherwise, the same control modes and comments discussed for two-state devices apply. These operations are supported by the ISC (Integer-Controlled Step Position Information) CDC.

3.4.5.2.6 Set-Point Control

A set-point control operation provides an analog value to the controlled device. In general, the device uses the analog value as a target value for some process-related control variable. For example, a substation application providing voltage control would interpret the set-point as the target voltage to be maintained. The application may use OLTCs and capacitor banks to regulate the voltage to the desired set-point.

3.4.6 Calculations

Calculations shall be supported as necessary to derive values that are not directly acquired by the secondary system. Calculations may be required in BCU, CCU, and MMI units as part of their core or programmable logic responsibilities. In all cases, the data types for calculated variables shall be

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consistent with the data types used in the IEC 61850 information models for the same or similarly defined data. If the calculated variable is available for use by subscribing clients, it shall be maintained in the Local Repository in a structural location that is consistent with IEC 61850’s established information models. Its value shall be updated at a rate that supports the application requirements that depend on it.

3.5 PROGRAMMABLE LOGIC APPLICATIONS

The SA systems shall perform enhanced automation functions, including the following:

1. Heartbeat function for IED health and on-line status monitoring

2. Maintenance of TRIP Counters for breakers

3. Rate-of-change calculations and alarming for selected analog input variables

4. Breaker operating time checks

5. Substation-wide, automated control sequences: CTO, LTO, BTO, load shedding / Load Restoration, and Voltage Selection

6. Station-wide interlocking

7. Protection applications (Breaker Failure Protection)

8. Voltage Selection (VS)

9. Automatic Transformer Restoration (ATR)

The contractor shall be responsible for the creation, design, implementation, configuration, installation, testing, and documentation of logical control sequences for the above tasks for each station’s ultimate configuration. The contractor shall consult with MEA regarding the various design and planning issues and submit the finalized plans for MEA’s approval. All Programmable Logic Control (PLC) software and source code shall be included in the deliverables, so that MEA can use them for future modifications. These applications shall be verified during the Factory Acceptance Tests (FAT), using an I/O simulation panel provided by the contractor.

The closing of circuit breakers shall be supervised by appropriate interlocking. For example, a circuit breaker shall only be closed if its two disconnect switches are already closed and the ground switch is in the ungrounded position. Abnormal conditions such as ‘low air’ or ‘low gas lockout’ in the breaker, etc, shall inhibit the control operation. These procedures represent standard station practice, and MEA expects them to be incorporated into applications without explicit direction. Other situations involve other interlocks or permissive signaling, and practice may differ among utilities. Where MEA’s operational practice is unclear, the contractor shall submit the issues for written clarification. Generally speaking, applications shall monitor their operations and avoid situations that can damage equipment, pose safety hazards, or lead to unsatisfactory results.

Applications shall be configured to subscribe the input data they need from the Local Repository. If station or enterprise clients need the results generated by the application, then those data also need to reside in the Repository.

3.5.1 Heartbeat Function

All IEDs shall support the heartbeat function. Each IED broadcasts a GOOSE message over its Substation LAN every 10 seconds to indicate that it is healthy, on-line, and performing its responsibilities without any significant impairment. If that isn’t true, it doesn’t broadcast the message. Every IED in the system monitors these heartbeat functions to determine whether any of its peers has a problem or is off-line. An IED is deemed by its peers to be off-line or malfunctioning if a GOOSE message is not received from it within an interval of 25 seconds. If an IED is

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dependent on a non-operational peer, it may use a contingent peer to complete its responsibilities, if that contingency has been provided in its programmable logic or through other means.

In particular, the Operator Interface [MMI] units shall monitor heartbeat messages to determine which IEDs are operational and which are not. This information shall be displayed, logged, and reported to the SCADA/EMS system.

Heartbeat messages from the various IEDs shall be offset in time by some mechanism that prevents all system heartbeat messages from being issued simultaneously.

3.5.2 TRIP Counters for Circuit Breakers

This application shall run in the CCU and be responsible for maintaining the values of TRIP Counters, one for each circuit breaker in the station. Each TRIP Counter keeps track of the number of times its associated breaker trips. It doesn’t matter whether the breaker is tripped by command, by protection logic, or by other means; the TRIP Counter shall be incremented by +1 for each trip occurrence. The TRIP Counters will principally be used to keep track of breaker usage for maintenance purposes. They may also be used to understand operational patterns over a long period of time.

The TRIP Counters eventually roll over. By default, the roll-over value is the decimal equivalent of a 32-bit value. However, it shall be possible to configure the roll-over value on a point-by-point basis. It shall also be possible to pre-set TRIP Counters, so that the counts can be synchronized with prior records or external equipment.

The implementation of this application shall support the inclusion of each TRIP Counter in the Local Repository, accompanied by a configuration parameter for the roll-over value. One approach would be to create a new LN called STRC (Sensor Group: TRIP Counter), containing an INC CDC to represent the TRIP Counter. This would provide all the tools needed to manage the counter per the discussion above. The INC CDC supports data type INT32 for the controllable integer status, allowing it to be operated as a 32-bit counter. The application itself would need to subscribe to breaker status events for the breakers to be monitored, preferably from the Repository. The application would normally respond to each trip event by incrementing the appropriate TRIP Counter. Once in a great while, it would reset the counter if the roll-over value was attained. The application should perform the incrementing or resetting via a direct control operation, with the ctlClass configured for ‘operate-once and ctlModel configured for ‘direct-with-normal-security’.

3.5.3 Rate of Change (ROC) Limit Checking

This application shall run in the CCU and be applied to selected analog input variables that are acquired from IEDs and maintained in the Local Repository. For these variables, the application shall divide the change in value for successive value reports by the difference in time-tags. Filtering shall be applied so that single scan excursions do not cause an alarm. The calculated rate-of-change shall be compared against a limit, and shall create an alarm if the rate-of-change exceeds that limit.

To support the implementation of this capability, analog input values shall be reported using IEC 61850 report services, ensuring that their reported values are time-tagged. Care needs to be taken that deadbands for the analog input values are set sufficiently small to support effective calculations by the CCU. The calculated ROC variables shall be modeled as instances of either the MV (Measured Value) or CMV (Complex Measured Value) CDC (Common Data Class), as appropriate. The MMXU (Measurement) LN (Logical Node) can be extended to include the desired ROC variables as ‘optional’ components. This is the way the ROC variables would be represented and stored in the Local Repository. Once the range limits are configured for the individual ROC MV or CMV instances, IEC 61850 change-of-range events will occur naturally and can be processed as alarms by an Operator Interface [MMI] unit or the SCADA/EMS system.

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3.5.4 Breaker Operating Time Checks

This application shall run in the CCU and be applied to all circuit breakers at the station. The objective is to determine how long it takes each breaker to TRIP, from the time that the tripping mechanism starts to work to the time that the tripping action is complete. The results are used to direct breaker maintenance, and they need to be stored in the Local Repository for each breaker.

Breaker operating times can be calculated by monitoring ‘a’ and ‘b’ auxiliary contacts on the breaker. The interval begins at the instant when both ‘a’ and ‘b’ contacts are open; the interval ends the instant the ‘b’ contact is closes (with the ‘a’ contact remaining open).

‘Breaker Operating Time’ measurements shall be included in the Local Repository, associated with other data related to the circuit breaker (e.g. the TRIP Counter).

3.5.5 Feeder Fault and Breaker Lockout Recognition

Feeder protection relays shall provide starting signal that indicates a downstream fault has been detected, tripping the feeder breaker. A second signal shall indicate a breaker lockout condition if re-closing has not been successful, indicating that the fault may still persist.

For all distribution breakers, a programmable logic application in the CCU or BCU shall detect starting signal, delay for a user-defined period, and then (1) check the status of the second signal or (2) check the status of the breaker. If the second signal indicates lockout or if the breaker is OPEN, breaker lockout shall be inferred. If the second signal indicates no lockout or if the breaker is CLOSED, a transient fault and successful re-closing shall be inferred.

In the case of a transient fault with successful re-closing, the operator shall reset the relay target that indicated a downstream fault, and the resulting status change shall consequently reset the programmable logic application for that breaker. In the case of lockout, the operator shall reset both relay targets (i.e. downstream fault and lockout, if the lockout target exists) when the fault has been cleared. Again in this case, resetting the downstream fault target shall consequently reset the programmable logic application for that breaker.

3.5.6 Automated Control Sequences

The following automated control sequences are currently used at selected stations within MEA’s power delivery system, these applications shall all run in the Bay Control Units and Protection IEDs.

3.5.6.1 Line Throw-over Scheme (LTO)

Under certain operating conditions, MEA will operate its HV line circuit breakers in a “PREFERRED LINE” mode, with only one of an incoming pair of circuit breakers energized, the bus coupler/bus section closed, and the other line in standby mode. Refer to Figure 6A.

If the preferred line voltage is lost, and the standby line remain healthy, the LTO logic shall open the preferred line circuit breaker and check whether the line circuit breaker of the preferred line is open. If it is open, the LTO logic shall implement a switchover to the standby line after a user definable time delay of 0.2 seconds (total dead time). Time delay shall be able to adjustable in range of 0 to 10 seconds.

The LTO functions shall be blocked if the preferred line breaker is tripped by over-current, breaker failure, or bus differential protection, In addition, if both lines voltage is lost the LTO logic shall not operate.

When the preferred line voltage returns to normal, the LTO shall switch back to this line after a user definable time delay of 60 seconds. Time delay shall be able to adjustable in range of 0 to 180 seconds.

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It must be possible to enable or to inhibit the LTO application, and to select the preferred line, from the Operator Workstation, and (subject to Station Level interlocking) from the SCADA/EMS control center.

3-phase voltage relays (U<) for lines voltage supervision shall be provided built-in both Distance protections and line BCUs.

The LTO shall be controlled “AUTO” and “MANUAL” by BCU internal S-R Flip-Flop which can be operated by a manual switch on the panel and through the SA control command. One lamps, LED, marked “OFF” shall be fixed on the panel near the double throw switch to indicate the status of LTO function. Preferred Line key switch shall be provided. LTO functions for 3 incoming lines much more complex than LTO functions, the Contractor shall consult MEA for detail description before implementation.

3.5.6.2 Bus Throw-over Scheme (BTO)

Under normal operating conditions, each of the station transformers will be operated individually, with the bus section of the MV distribution board open and each transformer supplying up to 7 or 8 feeders. Refer to Figure 6A.

If a transformer supply is lost and the adjacent transformer remains healthy, the BTO logic shall open the incoming MV circuit breaker and check whether the incoming MV circuit breaker is open. If it is open, the BTO logic shall close the bus section circuit breaker after a user definable time delay 5.0 seconds (total dead time). In addition, the time delay shall be able to adjustable in range of 0 to 10 seconds.

The BTO functions shall be blocked if the incoming circuit breaker is tripped by over-current, breaker failure, or bus differential protection. In addition, if both of transformers supply is lost the BTO logic shall not operate.

When the lost transformer supply has been restored the BTO logic shall automatically close the incoming MV circuit breaker and then open the bus section circuit breaker to restore normal operation without interrupting power supply. The restoration delay shall be a user definable time delay of 60 seconds. Time delay shall be able to adjustable in range of 0 to 180 seconds.

In case of there are two or three adjacent bus section, it shall be possible to implement the BTO functions. The BTO1 shall be used to switchover between Transformer No.1 and Transformer No.2. and BTO2 shall be used to switchover between Transformer No.2 and Transformer No.3. The operating sequence for both BTO1 and BTO2 functions more complex than BTO functions, the Contractor shall consult MEA for detail description before implementation.

It must be possible to enable or to inhibit the BTO application from the substation MMI, and (subject to Station Level interlocking) from the SCADA/EMS control center.

3-phase voltage relays (U<) for transformer voltage supervision shall be provided built-in incoming feeder BCUs or separated UV/OV protection units.

Some substations have only single phase VT. (24/12kV line VT), the separate unit single phase undervoltage relay shall be provided.

The BTO shall be controlled “AUTO” and “MANUAL” by BCU internal S-R Flip-Flop which can be operated by a manual switch on the panel and through the SA control command. One lamps, LED, marked “OFF” shall be fixed on the panel near the double throw switch to indicate the status of BTO function.

3.5.6.3 Bus Coupler Throw-over Scheme (CTO)

Under certain operating conditions, MEA will operate two HV line circuit breakers simultaneously, However each busbar is energized by one HV line. So the bus coupler is open. Refer to Figure 6B.

If the line voltage is lost and the other line remain healthy, the CTO logic shall open the line circuit breaker (line voltage is lost) and check whether the line circuit breaker is open. If it is open, the

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CTO logic shall close the bus coupler to receive electric power from the healthy line after a user definable time delay of 0.2 seconds (total dead time). Time delay shall be able to adjustable in range of 0 to 10 seconds.

The CTO functions shall be blocked if the any line breaker is tripped by over-current, breaker fail or bus differential protection. In addition, if both lines voltage is lost the CTO logic shall not operate.

When the unhealthy line voltage returns to normal, the CTO shall switch back to this line and open the bus coupler after a user definable time delay of 60 seconds. Time delay shall be able to adjustable in range of 0 to 180 seconds.

It must be possible to enable or to inhibit the CTO application from the substation MMI, and (subject to Station Level interlocking) from the SCADA/EMS control center.

3-phase voltage relays (U<) for lines voltage supervision shall be provided built-in both Distance protections and line BCUs.

The CTO shall be controlled “AUTO” and “MANUAL” by BCU internal S-R Flip-Flop which can be operated by a manual switch on the panel and through the SA control command. One lamps, LED, marked “OFF” shall be fixed on the panel near the double throw switch to indicate the status of CTO function.

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Figure 6A: Line Throw-over (LTO) & Bus Throw-over (BTO) / Normal Operational Configuration (There are other variations with this same basic theme)

HV HV

M

LTO LTO

Incoming HV

Line Bays

TransformerBays

HVBusbar

Motor-OperatedBus Switch

Distribution Busbar & Feeders(12kV or 24kV)

MV MVBTO

… …

Red zones are normally closed

Green zones are normally open

HV HV

M

LTO LTO

Incoming HV

Line Bays

TransformerBays

HVBusbar

Motor-OperatedBus Switch


MV MVBTO

… …



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Figure 6B: The Bus-Coupler Throw-over (CTO) / Norm al Operational Configuration (There are other variations with this same basic theme)

3.5.6.4 Load Shed and Restoration

The SA shall provide an accurate frequency measurement for the voltage on each of the MV bus sections. The under-frequency load shedding application shall provide for up to five (5) stages of load shedding, at user definable pre-set frequencies, with minimum increments of 0.03 Hz over an operating range of 50 to 47 Hz, and with user-definable pre-set time delays within a range from 0 sec through 120 sec, with increments of 0.1 sec in range from 0 sec through 1 sec, and with increments of 1 sec in range from 1 sec through 120 sec.

An under-voltage function for blocking load shedding application shall provide for up to five (5) stages of load shedding at user definable pre-set voltages, with minimum increments of 1% over an operating range within 50% through 95% of nominal voltage, and with user-definable time delay from 0 sec through 60 sec in 0.1 sec increments.

Feeder trip-groups and trip-points shall be user definable to ensure maximum flexibility of the application. Each of the outgoing feeders shall be assignable to trip at any of the five (5) pre-set under-frequency levels.

Incoming HV

Line Bays

TransformerBays

HV Busbar

Motor-OperatedSwitch


MV MV

M

M

HV

M

M

M

M

M

M

M

M

M

M

M

M

HV

M

M

HV Busbar

BUS A

BUS B

Bus Breaker

CTO



MM

Bus CouplerBay

……

Incoming HV

Line Bays

TransformerBays

HV Busbar

Motor-OperatedSwitch


MV MV

M

M

HV

M

M

HV

MM

MM

M

M

M

M

MM

M

M

MM

M

M

HV

MM

MM

HV Busbar

BUS A

BUS B

Bus Breaker

CTO



MM

Bus CouplerBay

……

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The load shedding application shall block any auto-reclosing functions. The under-frequency application shall be enabled or disabled from the Operator Interface [MMI]or (subject to Station Level interlocks) from the SCADA/EMS control center.

The under-frequency load shedding application shall be guaranteed to run at user definable voltage limits between +10% to –40% of rated voltage, and shall be blocked if the voltage is less than a user-definable level.

Load restoration of a trip-group shall be manually initiated from the Operator Interface [MMI] , or (subject to Station Level interlocks) from the SCADA/EMS control center. Restoration of any trip–group shall be by single command and the programmable logic applications shall automatically sequence closing of the feeders so as to avoid troublesome load initiation surges.

Load restoration application shall switch an auto-reclosing function in ON position after feeders circuit breaker have been closed. Auto-reclosing function shall be switched ON only feeders were tripped by load shedding function).

A second alternative for the load shedding and restoration scheme using the dry contact from the under frequency/under-voltage relays at the substation. Provision for a selection of each alternative and the reset of the under-frequency/under-voltage tripping relay from the Operator Interface [MMI] shall be provided. In addition, automatic PT voltage selection function for frequency-voltage measurement shall be provided to switchover to the other PT in case of the main MV busbar PT supply is lost.

3.5.6.5 Voltage Selection (VS)

Busbar voltage simulation which displays simulated bus voltage according to the bus selector switch and input voltage for HV Transformers BCUs is available from the line voltage transformer at the incoming lines. Voltage selection scheme (VS) shall be provided for voltage circuit switching to the appropriate line voltage transformer.

Suitable low voltage circuit breaker shall be supplied.

3.5.7 Protection Applications (Breaker failure prot ection, 50BF)

Breaker failure protection (50BF) shall be provided. The phase currents of the feeders shall be monitored for each phase. The overall reset function of the 50BF system shall not be slower than 25 ms. It shall be sensitive to detect from 0.2 to 2.0 times the rated feeder current, adjustable in steps of less or equal to 0.2 times of this current and being able to be operated continuously at 1.2 times the rated current. The 50BF relay has to be provided for each individual CB. It shall be initiated by all other protection devices tripping commands. The starting and tripping provided from a protection to be infeed from the same DC auxiliary circuit. Starting from protection relays with single pole tripping shall be transferred segregated per phase. All lock-out functions provided by the CBs i.e. SF6 underpressure, N2 and oil monitoring shall be incorporated to the BFR tripping logic. In case one of these lock-out functions is activated the trip signal to the remote CB shall be sent or performed without delay. External signal inputs provided for non-current sensing elements e.g. Buchholz performed via binary inputs shall be incorporated in a tripping logic with an auxiliary contact of the CB. A software matrix shall allow to use the 50BF in different tripping configurations, send signals and combination with several timers. Trip cut out switches shall be provided as required. All such switches shall provide with suitable nameplate stating the device number and function.

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One lamps, LED, marked “OFF” shall be fixed on the panel near the double throw switch to indicate the status of breaker failure protection.

3.6 HISTORICAL DATA

An application shall be provided for periodically saving real-time data in records that can be later retrieved to support station troubleshooting and planning. This application shall run on the Operator Interface [MMI] platform in Terminal Stations and substations.

The capabilities and procedures associated with this application shall be reasonably simple to use and intuitive, requiring only a small amount of training (i.e. a half-hour). The capabilities that shall be provided include the following.

1. Acquired Historical Points

A historical point is defined as a set of periodically recorded data values for a specific variable. The operator shall be able to select (or deselect) variables (one at a time) from a template containing candidates supported by the station’s Local Repository.

For each historical point, the operator shall be able to select a periodic rate. The following rates shall be available: 1, 5, 15, 30, or 60 minutes (synchronized to the hour); daily, weekly, monthly (at the end of each period).

Each historical point shall take the name of the variable used. For each historical point, the operator shall be able to enable or suspend operation (i.e. data collection and recording) or delete the historical point completely.

At any time, the operator shall be able to display this template to view his selections for existing historical points and to make any changes. An ‘Enter’ button shall be used to signal that changes or additions are ready to be processed by the system.

2. Calculated Historical Points

The operator shall be able to specify a formula for calculating a historical point. This shall work the same way as before, except that the formula may reference one or more candidate variables from the same template used for acquired historical points. Formula-creation shall be supported by an unambiguous syntax for arithmetic operators, a list of useful functions (e.g. square root; trig functions, etc), and precedence. Calculated historical points need to have a name assigned.

3. Retrieval of Historical Point Records

The operator shall be able to enter a report mode, wherein he can set up an Excel spreadsheet for presenting the recorded data he wants. He shall be able to specify several conditions concurrently, such as the following:

Start date and end date

Historical point names (or wildcard)

Values exceeding x, less than x, or equal to x

If the application is unsuccessful in finding requested data, it shall respond with an appropriate message, providing the operator with information that is helpful.

Aside from the data loaded into the spreadsheet from historical points, the operator shall be able to enter supporting text and other content as he would in any Excel spreadsheet. All spreadsheet functions shall be available to total columns of figures, and so on.

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The operator shall be able to print the report or to temporarily display fields of data graphically (e.g. a trend graph, displayed against a time-marked axis). The amount of data in a report shall only be limited by available data and the size of an Excel worksheet.

4. Predefined Historical Points

The contractor shall provide the following historical points, already set up in the delivered systems:

Hourly snapshots of all status, analog, and counter values.

Daytime maximum values of all analog and counter readings collected during the time interval 06:00 to 17:00, along with the date and time of the maximum reading.

Nighttime maximum values of all analog and counter readings collected during the time interval 18:00 to 05:00, along with the date and time of the maximum reading.

MEA shall be able to alter these predefined points (e.g. changing the time intervals; adding more historical points, or deleting historical points.

5. Archives

All historical data shall be saved and available on-line for the present month plus the prior three months. Older data shall be archived on an end-of-the-month basis. Archives shall be stored on disk and retrievable on a read-only basis for queries.

3.7 OPERATOR INTERFACE [MMI] FUNCTIONS

3.7.1 General Requirements

The details of the proposed MMI shall be included in the bidder’s proposal. The detailed design of all user interfaces, including navigation trees and menu bars; the format and contents of dialog menus; the colors of display features such as menu bars, window borders, display background; and operational procedures shall be subject to MEA's approval. The following MEA preferences shall be incorporated.

3.7.1.1 Windows Usage

Windows shall be provided to allow the partitioning of the monitor so that several displays and information from several programs can be viewed simultaneously.

At any time, there shall be one and only one active window at the MMI. The active window shall be the focus of all user interactions such as display call-up, navigation through displays, program execution, and dialog interactions. A window shall become active by clicking within its boundary.

In general, all windows shall have the same basic structure, and include the following:

1. Window Border

2. Title Bar

3. Maximize. Minimize, Restore and Close buttons

4. Scroll Bars, when the display spans beyond the window. The magnitude and position of the slider of the scroll bar shall represent the size of portion of the display that is currently being shown relative to the full size of the display and the position of the shown portion within the display.

5. Mode/Case Identification: The operational mode of the function running in the window shall be very distinctly shown.

6. A Toolbar from which pull down menus can be called.

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7. Application Area: The main area of the window, from the SA system functions and applications are operated.

It shall be possible to change the size of windows by dragging edges, and to drag the complete window to any position on the screen.

3.7.1.2 User Interface Features

1. Date and Time

The date and time shall be shown on the MMI monitor. Date shall be presented in the format DD /MM/YYYY. Time shall be presented in the format HH:MM:SS with a resolution of one (1) second and shall be updated once per second.

2. Pushbuttons (Soft Keys) and Function Keys

In the context of this specification, the term push-button (or simply button) refers exclusively to icons on a display from which functions can be initiated or displays can be called by clicking them.

3. Function Keys

The term function key (or simply key) refers to a physical key on the keyboard. The following frequently used functions shall be assigned function keys: SILENCE, ACK, DEL. They shall be labeled as such. Others may be proposed.

4. Keyboard Functions

MEA shall be able to assign and reassign combinations of keys of the MMI's keyboard (e.g. Control-Alt-P) for the activation of specific functions and calling up of frequently used displays. The changing of these assignments shall be allowed only from the MMI in the Programmer Mode. The following keyboard selectable functions shall be included in the delivered SA systems.

SILENCE: Silence the audible alarm.

CANCEL: Has the same effect as a "CANCEL" button shown in a currently displayed menu.

DISPLAY: Call up a display by entering its mnemonic. See Sub-Clause !

ก.

ALARM SUMMARY: Display the Alarm Summary.

HELP: Show a menu of topics related to the active display from which further information or instructions can be selected.

3.7.1.3 Toolbars

Toolbars with pull-down menus shall provide fast navigation to functions and displays. It shall be possible to navigate to functions and displays by clicking the toolbars and entries on their pull-down menus. The layout of toolbars and the rest of the navigation schemes shall be developed in consultation with MEA and shall be subject to MEA’s approval. Provisions are required for programmers to edit the toolbars and the navigation trees, and to construct new ones, through an interactive procedure and without programming.

1. A main toolbar shall appear near the top of each display. The main toolbar and pull-down menus initiated from it shall provide fast navigation to frequently used SA system functions and displays, and to functions that have to be quickly accessible for handling emergencies.

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2. One or more application toolbars shall be provided for application displays to facilitate navigation to functions and displays that belong to the application itself or are used in conjunction with it. Each application’s toolbar shall provide fast and convenient access to HELP information associated with the specific application.

3.7.1.4 Dialog Boxes

Dialog Boxes shall be displayed when it is necessary to present the user with further information, or to allow the user to choose among several alternatives, or to enter data. Alternatives, which are not currently valid, shall be displayed in lower intensity and shall be inactive. A dialog box shall be placed close to the object from which it was initiated, but shall not to cover it, and it shall be possible for the user to drag a dialog box to any part of the window. Dialog Boxes shall be able to include static textual information, pushbuttons, data entry fields, pushbuttons and check boxes as appropriate.

It shall be possible for the user to cancel a dialog at any time by selecting a CANCEL push-button in the dialog box or using an assigned keyboard function.

3.7.1.5 Information Boxes

Information Boxes shall be used to annunciate occurrences that require user attention, such as failures to successfully complete a supervisory control request, receipt of a message from a substation, or errors reported by other applications. Messages that are displayed in response to substation operator actions, such as notification of failure of supervisory control, shall be displayed in an information box that pops up on the screen from which the request was issued. Other messages, such as an error message from an application, shall be posted on the MMI monitor in order to report the problem to the substation operator.

Information Boxes shall remain on the screen until they are closed by a user, and shall not be overlaid by other windows.

Multiple information boxes shall be able to be present at the same time, and users shall be able to drag information boxes to other parts of the screen.

3.7.1.6 HELP Function

The SA system shall include a “HELP” function of sufficient scope to instruct users on normal operation of the SA system and each of its applications without having to resort to a printed user’s manual. The HELP function shall include both text and drawings.

The SA system shall include tools that enable MEA programmers to edit and add "HELP" text and screens.

3.7.1.7 Display Capabilities (General)

1. Fonts

Both fixed size fonts and vector fonts that change with zooming shall be available.

2. Data Display

Any attribute of any data contained in the SA system Repository, whether the point is telemetered, calculated, or produced by an application, shall be available for presentation at any screen location of the display.

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No artificial restrictions as to the placement of data or the format of its presentation shall limit the way in which displays can be defined. It shall be possible to access every attribute of any point or object in any database of the SA system in order to dynamically control its appearance in displays. The presence, appearance and location of quality indicators, tags, alarm inhibit indications, and any other indications or display features that depend on point attributes shall be defined via the Display Editor during display creation/modification.

3. Graphical Display Capabilities

The capability to include bar charts, x-y plots and pie charts shall be available.

3.7.2 Operator Functions

In this sub-clause, the following required operator functions are specified:

1. Display call-up

2. Supervisory control

3. Device tagging

4. Placing data and command points ‘out-of-service’ or ‘in-service’

5. Display hard copy

6. User log-on

Other operator functions are specified elsewhere in the context of the required applications.

Messages shall be displayed to advise the user of the disposition of his request after each action. Appropriate dialog menus or pushbuttons shall automatically be displayed to guide the substation operator through operating procedures. Error messages shall explicitly identify the encountered problem or reason for which a user request was rejected.

Operational requests shall be validated and accepted (or rejected, if not authorized) according to the user’s log-on. Requests shall also be rejected if parameters or other data entered by the user are not valid or are unreasonable. An acceptable, alternative approach is to not make functions available to users who are not authorized to perform them. The user shall be notified of the rejection of requests through an information box with a message that states the reason for rejection.

Several operator functions, such as Supervisory Control and Out-of-Service/In-Service Commands, require a point to be selected. Point selection shall automatically be canceled when the last step of an activity concerning a point is completed. Point selection shall also be canceled for multi-step procedures if the time between two consecutive steps of the procedure exceeds a pre-defined, system-wide selection-timeout period. The selection timeout period shall be adjustable by programmers in the range of 10 - 120 seconds.

3.7.2.1 Display Call-Up

It shall be possible to call up a display using any of the following methods:

1. By clicking a pushbutton in a directory display. These displays shall be organized in a hierarchical order.

2. By clicking on an entry in a pull-down menu selected from a toolbar.

3. By clicking on a pushbutton that may be included in any display for the purpose of calling up a related display.

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4. Using function keys or keyboard functions (defined earlier) that may be designated for the selection of frequently-called displays.

5. By entering a short display mnemonic in a location reserved for this purpose on the screen.

6. It shall be possible to call an Alarm Summary display by clicking a data point on any substation display where it appears.

If there is an entry for the selected point in an Alarm Summary, that portion of the summary which includes the entry, shall be shown. The point’s alarm entry shall be highlighted by scrolling the Alarm Summary down to where the entry appears at the top of the display.

If no such entries appear in the Alarm Summary, a message confirming that fact shall be presented to the user.

Methods shall be provided to call displays within the active window or within a new window.

3.7.2.2 Supervisory Control Procedures

This Sub-Clause specifies the substation operator procedures for supervisory control; functional requirements for supervisory control are specified under the Functional Requirements heading. The station operator shall be able to control two-state devices such as breakers and switches, three-state devices such as motor-operated switches, and multi-state (RAISE/LOWER) devices such as tap changers.

If the user does not perform the next step of a control procedure (or other point-oriented procedure) within the selection time-out period, the point's selection shall automatically be canceled. A system-wide, user-defined time-out period shall be used with a default value of 30s.

Rejection of a control request shall occur at the procedure step at which it is detected and, in any event, before the request is sent to the CCU. The user shall be notified of the rejection and of its reason.

1. Control of the State of Devices

Supervisory Control of two-state devices and three-state devices such as breakers and switches shall involve the following consecutive actions:

The substation operator shall select the device for control by clicking the dynamic presentation of a control point.

When the device is selected, the device symbol shall flash and a pop-up menu with the device name and available operations shall be displayed. Operations that are not applicable or currently available shall be dim and inactive. This menu shall not obscure the selected device.

The station operator shall select a control operation (TRIP, CLOSE, etc). Users shall be permitted to control devices into any state, including the current state of the device.

A message shall be placed in the pop-up menu identifying the device and the selected control operation. The pushbuttons EXECUTE and CANCEL shall be placed in the window.

The station operator shall initiate the control action by selecting the EXECUTE function.

Successful completion of the control request shall be recorded as an event. Failures to complete shall be handled as specified under the ‘Control Command Processing’ heading.

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Control requests shall be canceled and the selection of the point shall be terminated when the user cancels a request, does not perform the next step of the control procedure within the selection time-out period, or the request is rejected.

2. Incremental (RAISE/LOWER) Control

Supervisory control of RAISE/LOWER control devices shall involve the same set of consecutive actions as specified above for device state control, with the following exceptions:

Only RAISE and LOWER control operations may be selected.

The command shall be issued as soon as RAISE or LOWER is selected, without an EXECUTE step. It shall be possible for substation operator to initiate control repeatedly without reselection of the controlled point, provided that the execution of the previous control command has successfully been completed.

A separate timeout period shall be provided for incremental control points. This selection timeout period shall be user-defined within the range 10 - 120 seconds. The timer shall reset and start counting again whenever a RAISE or LOWER command is issued.

3.7.2.3 Device Tagging

A station operator shall be able to place a combination of up to ten (10) or more tags on any controllable station equipment appearing on the one-line diagram. There are three (3) types of tags, which are listed in the order of diminishing severity:

Clearance Tag (T)

All control commands shall be rejected for devices with a Clearance Tag.

Hot-Line Tag (H)

Only OPEN/TRIP commands shall be permitted for devices with Hot-Line Tags; CLOSE commands shall be rejected.

Warning Tags (W)

These tags shall not impose any control restrictions on devices, but a comment box with a standard warning message shall be displayed when they are selected for control.

The tag symbol shown in parentheses shall be displayed for tagged devices. Provisions to define and use graphic icons in lieu of these textual symbols shall be provided. For devices with several tags, the symbol for the most severe type of tag that presently applies to the device shall be shown.

A station operator shall be prompted to enter a comment of up to one (1) line that will be shown in the tag summary entry. A station operator shall be able to edit the comment later. It shall be possible to remove individual tags from the tag summary display and station displays. The placing and removal of tags shall be recorded as events in the CommandLog.

3.7.2.4 Placing Data and Command Points ‘In-Service ’ and ‘Out-of-Service’

The station operator shall be able to place individual data points, control points, and IED servers out-of-service (i.e. deactivate them) or in-service (i.e. activate them). These actions remain in effect indefinitely, although deactivation is typically used temporarily while there is a malfunction of some type.

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Incoming data shall not be processed for a deactivated point. A deactivated point shall retain the last value or state that was successfully retrieved before being deactivated, and shall be assigned an appropriate IEC 61850 data quality code corresponding to DEACTIVATED. Upon reactivation, the SA system shall resume processing of data reported for the point from the field. The data quality of a reactivated point shall be set to FAILED (or an equivalent IEC 61850 data quality) until up-to-date data is successfully received for it.

When an entire IED server is deactivated, the SA system shall stop processing any control command for the IED and mark the IEC 61850 data quality for all points belonging to the IED as DEACTIVATED (or equivalent). Supervisory control requests, issued by either the station operator or applications, shall be rejected for deactivated control points of the IED; the reason for the rejection shall be noted in a message displayed to the station operator or reported to the requesting application. When the IED is reactivated, the associated quality codes shall be set to FAILED (or an equivalent IEC 61850 data quality) until up-to-date data is received from the IED. However, points that had been individually deactivated, either before or after the IED was deactivated, shall remain in the DEACTIVATED state.

3.7.2.5 Using Substituted Values

Rather than deactivating a data point, the operator may choose to substitute a chosen value for the process value at the IED server where the point is located. This capability relies on use of the IEC 61850 substitution services. While the point remains in service, the IED provides the substituted value in lieu of the process value until the use of process values is reinstated. Using the IEC 61850 substitution services to move to use of substituted data for a point shall cause an entry to the SubLog. Similarly, a return to the use of process values shall also cause an entry to the SubLog.

The data quality for the point indicates whether the source is process data or substituted data. This information needs to be used by clients (e.g. SCADA/EMS or MMI) to annotate presented values that are in fact substituted values.

3.7.2.6 Display Hard Copy

The MMI operator shall be able to request printing of copies of any display, if the station is equipped with a printer. The station operator shall be able to choose either the active window or the complete display screen for printing.

3.7.2.7 User Log-On

Users shall be required to log-on to gain access to the SA system. The log-on procedure shall require entering an associated password. A list of authorized users shall be maintained, and a default operation mode shall be assigned to each user. Upon log-on, the MMI shall be put into the user’s default mode. In order to facilitate the transition between station working shifts, it shall not be required for the current user to log-off before a new user logs on.

Logging on and off shall be recorded in the ChangeLog. When nobody is logged on to a MMI, logging-on shall be the only function allowed at the MMI.

3.7.3 Modes of Operation

In order to control the scope of functions that users are authorized to operate; it shall be possible to assign the MMI to modes of operation. The functions permitted for each mode shall be defined in a table. MEA programmers shall be able to edit this table in order to change the authorizations of existing modes and to define new modes.

Initial modes that shall be implemented by the contractor are tentatively defined below. Final definition shall be developed in consultation with MEA during the implementation of the project.

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3.7.3.1 Operator Mode

The station operator is authorized to perform all the control and monitoring functions.

3.7.3.2 Supervisor Mode

In this mode, the user shall be able to perform all the functions permitted in the Operator Mode. In addition, supervisors shall be able to manage the configuration of the SA system, change the operating mode, change the assignments of user passwords, set system-wide operating parameters, choose another set of limits, restart the system, request system warm restart, manage communications interfaces, etc.

Any change to an operating parameter, whether it changes parameters in other IEDs or is stored and used strictly by the MMI unit, shall result in an entry to the ChangeLog. In cases where the change doesn’t result in changes to other IEDs, the MMI unit still has to effect the change through the CCU, so that a ChangeLog entry is generated. This means that user-defined parameters, even for the private use of MMI unit functionality, must be represented within the Local Repository.

In particular, any MMI unit that is restarted or placed on-line at the site shall need to pick up the ChangeLog to determine the current values of operating parameters that have been changed from the default values. It has already been stipulated elsewhere in this technical specification that any MMI unit that is restarted or placed on-line shall gather and process all the system logs as part of its start-up procedures.

3.7.3.3 Maintenance Mode

This mode shall provide access to the MMI database and display editors, including programmable logic applications. Users shall be able to build, edit, integrate and test database and display changes, including programmable logic applications, but shall not be permitted to perform any power system operations.

This mode shall be used to modify or reconfigure IEDs or the system at large, using the IEC 61850 SCL tools.

All editing and reconfiguration tools shall use version control, inserting version numbers into configuration files and archiving them in the preparation process.

This mode shall be used to upgrade software in IEDs via file downloads. Software files shall carry version codes.

The contractor shall explain in his bid proposal how these capabilities will be implemented. To the extent these responsibilities involve file services, they are likely the same ones used by the Remote File Manager.

3.7.3.4 Programmer Mode

Programmers and software developers shall be able to perform software development, debugging, integration, and configuration activities from the MMI. Programmers shall also be authorized to perform all the maintenance mode functions.

3.7.4 Event and Alarm Processing

3.7.4.1 Events

The following occurrences shall be processed as events:

1. All changes of status points resulting from supervisory control commands. (These shall result in StatusLog entries.)

2. Substation operator’s actions including, but not limited to, the following:

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Supervisory control. (These shall result in CommandLog entries.)

Tagging and removal of tags. (These shall result in CommandLog entries.)

MMI log-on or log-off. (These shall result in ChangeLog entries.)

Changing of MMI modes. (These shall result in ChangeLog entries.)

Alarm acknowledgement. (These shall result in AlarmLog entries.)

Deactivation and activation of data and command points and of audible alarming. (These shall result in ChangeLog entries.)

Manual substitution for process values. (These shall result in SubLog entries.)

System warm restart. (These shall result in ChangeLog entries.)

3. Events declared by application programs. (These shall result in entries to the most appropriate system log, according to the defined purpose of each system log.)

4. Other conditions that may be specifically called out in this specification

3.7.4.2 Definition of Alarms

Alarms are the result of interpreting system events and determining which events generally require notification of the operator and further action. The following types of events shall be processed as alarms:

1. Uncommanded changes of state of status points

2. Limit crossing by analog values from one defined operating region to another.

3. Failures of a device to respond to a supervisory control command

4. The passage of an SA system component (e.g. IED) to or from on-line status.

5. The power-up of an SA system component.

6. The detected failure of an SA system component (e.g. printer).

7. When a communications resource (e.g. SubLAN) experiences a high error rate (i.e. beyond a defined threshold).

8. Reported loss of heartbeat or abnormal heartbeat for any SA system IED.

9. When an alarm is declared by an application program.

10. Other conditions specifically called out in this specification.

MEA shall be permitted to add, delete or redefine conditions for alarming at any time before the entire contractor's design documents are approved.

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It shall be possible to assign points and specific alarm conditions to major and minor alarms. Therefore, for instance, it shall be possible to define the excursion of a value of an analog value outside the operational limits as a minor alarm and exceeding of emergency limits as a major alarm.

3.7.4.3 Alarm Processing

1. Alarm Reporting

The following shall occur when an alarm is detected:

An audible tone shall sound.

The visual representation of the point in alarm (the status symbol, or the numerical value) shall flash.

An entry shall be made in appropriate Alarm Summary displays.

An entry shall be made in the Alarm and Event (A&E) file.

2. Alarm Inhibition

The station operator shall be able to inhibit alarm processing for any point. When a point is alarm-inhibited it shall be processed as usual, and analog points shall continue to be shown in the color (or other characteristic) that corresponds to their limits range, however no alarm conditions associated with the point shall be reported.

3. Alarm Tones

Different tones shall be used for major and minor alarms. If a minor, audible alarm is already sounding when a major alarm is generated for the same point, the tone shall change to that of a major alarm. The station operator shall be able to silence audible alarms at their workstations. The station operator shall also be allowed to inhibit audible alarming; however, a conspicuous indication shall be displayed as long as audible alarming is inhibited.

4. Acknowledgment and Deletion of Alarms

The station operator shall be able to acknowledge alarms. On Alarm Summary displays, it shall be possible to use the mouse or keyboard to select individual alarms or blocks of alarms for acknowledgement and for deletion from the summary.

Deletion shall be permitted only for previously acknowledged alarms. When an alarm is acknowledged, its visual representation shall no longer flash.

3.7.4.4 Recording of Alarms and Events

1. Alarm Summary

The alarm messages shall be shown in chronological order. The last page, with the most recent alarms, shall appear when a summary is called. Scrolling shall provide access to the complete summary.

Only one (1) alarm shall be shown for a point. An old message for a point shall be deleted when a new alarm is generated for that point.

The time field shall flash for unacknowledged alarms.

2. AlarmLog

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An entry shall be made in an AlarmLog for each occurrence of an event that is defined as an alarm, provided alarming for the item is not currently suppressed (e.g. alarm-inhibited). The alarms shall be chronologically ordered. Unlike the Alarm Summary, the AlarmLog shall have a time-tagged entry for every occurrence, rather than just the most recent occurrence.

The AlarmLog is not to be considered as one of the system logs. It is private to an MMI unit and only serves as an audit trail for the handling of Alarm Summary entries (e.g. alarm entry, acknowledgement, and deletion). The AlarmLog shall be incrementally saved in non-volatile or disk memory. It shall be archived monthly.

The AlarmLog, along with the system logs (i.e. StatusLog, CommandLog, ChangeLog, SubLog, and FileLog) shall be part of the Historical Database (HIS), and entries shall be kept on-line for the period specified for historical data.

3. Alarm and AlarmLog Entry Format

All entries in Alarm Summaries and the AlarmLog shall be a maximum one (1) monitor line in length. Display and print versions shall be identical. No unduly cryptic abbreviations shall be used in alarm and AlarmLog entries. The exact format of the alarm and AlarmLog entries shall be subject to MEA’s approval.

Alarm and AlarmLog entries shall contain the following information, as applicable:

Class or Priority

Major alarm or minor alarm, indicated through color and a symbol.

Date and Time

Date and time of the detection of the condition, or of the user’s action. Date shall be in the format DD /MM/ YYYY.

The User ID (for user-initiated events)

Location (e.g. substation ID or application)

Point name

Point descriptor

Statement of the nature of the alarm or event

For status changes: TRIPPED/CLOSED/TRIPPED or ‘Clearance Tag Placed’.

For analog value transitions between operating regions: The region entered, as well as the analog value shall be stated.

3.7.5 CompositeLog Capability

As a result of an MMI unit’s start-up or return to on-line status, it shall construct a CompositeLog for the station from the system logs it finds on the CCU. The system log entries shall be chronologically interleaved to produce the CompositeLog.

CompositeLog entries from each system log (i.e. StatusLog, CommandLog, ChangeLog, SubLog, FileLog) shall be enabled or disabled for display and printing by a user, through the use of a supporting template. This action shall only affect display and printing for the user’s convenience; it shall not change the content of the CompositeLog, which shall retain all entries. Printout of the enabled portion of the CompositeLog shall be in landscape mode. Each sheet shall have the field headings at the top. Two lines per entry are acceptable if the formatted arrangement is consistent, clean, and easy to read. To the extent possible, the arrangement of fields for the CompositeLog shall be compatible with the arrangement of fields for the Alarm Summary.

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The CompositeLog shall maintain entries for the prior 100 days, including the present one. At the end of each calendar month (or at the first opportunity thereafter), all entries for the just-completed month shall be saved in a separate ‘CompositeLog Archive’, regardless of whether event entries have been acknowledged on the Alarm Summary display. CompositeLog Archives shall be saved on the local disk and on all CCU(s). File names for these archives shall be labeled as follows:

CompLogArchive%’StationName’%’Year-Month’.log

(actual name) (actual year & month)

Operators shall be able to open and display LogArchives on a view-only basis. They may be printed in the same format as the CompositeLog if a printer is available. CompositeLog archives shall not be deletable at an Operator Interface [MMI] unit or CCU, but may be duplicated to separate media (e.g. a portable disk) for backup or analysis at a different site (where deletion shall be allowed).

The operator shall have the capability to enter a mode in which he can select and sort CompositeLog entries for viewing and printout (if a printer is available), using various field-related search keys. For example, he should be able to search for events related to a specific circuit breaker, across a particular period of time. It shall be possible to apply several search criteria at the same time.

The ‘annotation’ field shall provide quick-reference information for each line entry. More than one annotation code may be used for the field entry (e.g. ‘m e’).

‘C’ for command

‘M’ for major status alarm

‘M/’ for transition out of major alarm

‘m’ for minor status alarm

‘m/’ for transition out of minor alarm

‘S’ for manual value substitution

‘S/’ for return to actual system values

‘F’ for file transfer

‘D’ for file deletion

‘P’ for a configuration parameter change

‘e’ for entry time (when date & time reflect Alarm Summary entry time, rather than a time-stamp from the data source).

3.7.6 Browsing to Capture Repository Data Component s

Browsing allows the operator to view the Local Repository in either the primary CCU or standby CCU. More importantly, it allows the MMI’s system software to capture and store the structure and data of Proxy Server Views and Proxy Client Views residing in the Local Repository.

In particular, the MMI shall capture all IEC 61850 object references that represent a terminal leaf. These are object references that drill down through the information structure to the furthest possible points (i.e. to a specific data attribute that has very specific meaning). The wonderful thing about object references is that they not only represent a name for each piece of data, but they also provide navigational directions for finding that piece of data in the Repository.

Object references that do not qualify include those that drill down only part way, and so represent a cluster of lower level objects or data attributes. These assist in establishing the structure and

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navigation of these information models, but they do not otherwise have a bearing on the objectives presented here.

This specification refers to these captured ‘terminal leaves’ as d-tags (short for ‘data tags’ to prevent confusion with utility equipment tags). D-tags shall be used for several purposes. D-tags (or whatever they are called by the contractor) shall be an MMI implementation mechanism for identifying important pieces of station data, whether they represent real-time values, data quality (which is really real-time data, too), operating parameters, configuration parameters, or descriptive text. IEC 61850 simplifies life here, because object references include a field called a functional constraint. The functional constraint classifies the object reference as to its purpose. Examples include status (ST), control (CO), measurement value (MX), configuration (CF), description (DC), substitution value (SV), and so on.

The MMI software shall sort these captured d-tags into several lists according to their functional constraint. These lists shall be used in templates, allowing the maintenance engineer to assign familiar (and shorter) names in lieu of their IEC 61850 object reference handles. These d-tag names shall be used in displays and reports. These lists shall be used to coordinate and simplify coordination of MMI activities with the content of the Local Repository. For example …

1. D-tags with Functional Constraint = CF

D-tags in this list shall be used to support MMI templates for modifying operational parameters. Care is required. Some of these d-tags are closely tied to software or hardware processes (e.g. sample rate), and the maintenance engineer would be ill-advised to alter them. Others can be changed at his discretion. The contractor shall ‘gray out’ any configuration parameters that should not be changed in this way.

Note that not all operational parameters are defined by the IEC 61850 information models, as occasionally explained in other clauses of this specification. The contractor shall include those outlying operational parameters in this list, if appropriate.

2. D-tags with Functional Constraint = MX

D-tags in this list shall be used to support the selection and positioning of real-time measurement values for displays and reports, as part of the editing process. They can also be referenced for defining historical data points, as defined under the Historical Data clause.

3. D-tags with Functional Constraint = ST

D-tags in this list shall be used to support the selection and positioning of real-time status values for displays and reports, as part of the editing process. They can also be referenced for defining historical data points, as defined under the Historical Data clause.

4. D-tags with Functional Constraint = CO

D-tags in this list shall be used to support the selection and positioning of control points for displays (e.g. the one-line diagram), as part of the editing process.

5. D-tags with Functional Constraint = SV

D-tags in this list shall be used to support an MMI template that allows an operator to perform data value substitution. (Substitution services are supported by the IEC 61850 standard.) They can also be used, when a substituted value is being used for a process value, for insertion into historical data records. This requires appropriate annotation of the record to avoid confusion between process and substituted values.

6. D-tags with Functional Constraint = DC

D-tags in this list shall be used to support an MMI template that allows the operator to change these descriptions.

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3.7.7 Displays

Displays to be included in the SA system are listed and described below. This is not an exhaustive list and the contractor shall prepare all the displays necessary for the required functions in consultation with MEA. Display generation tools shall be provided for MEA in order to integrate displays created for future applications. Some screen displays specified in this specification.

3.7.7.1 Directories

These are hierarchically organized lists of displays from which displays can be selected for viewing by clicking on items in the lists.

3.7.7.2 Station Displays

1. Station Status

A multi-page set of displays that show the overall status of the station, using both one-line diagrams and a set of text-based displays.

One graphic-based display shall show the station’s one-line diagram.

One text-based display shall provide a high-level overview of the station’s operating status, including key power system measurements.

Others displays shall show information associated with individual bays, both HV and MV, in a manner that enables the operator to easily assess the station’s condition. These shall show more comprehensive information than the overview display.

2. Station Tabular Displays

These shall be automatically created by the SA system. They shall list all the telemetered status, analog, and counter data points associated with the substation. The regions currently defined analog points shall be shown, and Supervisors shall be able to change them from this display.

3.7.7.3 Point Profile Displays

These include an individual display for each data component within the Local Repository. They shall show all the fields associated with the point, including current value, configuration parameters, text descriptions, and any other attributes for the point. Supervisors shall be allowed to change point attributes and limits (as permitted by IEC 61850 rules) from these displays.

3.7.7.4 Communications Status / Operational Status Display

This display shall show the communications status and operational status for all secondary system devices (e.g. IEDs) and resources (e.g. SubLANs). This information shall be used for maintenance of the secondary system.

Information shall include operational status (e.g. device health; in-service/out-of-service; on-line/off-line), communications status, (OK/Failed), and communications statistics for both Substation LANs and all devices connected to them.

3.7.7.5 Summary Displays

A set of summary displays, including those listed below, shall be provided to list alarms and events as well as data points that are in an alarm or abnormal state, or have been placed in a special condition by the substation operator.

1. Alarm Summary

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Each alarm entry shall contain the following fields:

Date and Time: Alarm entries shall be time-tagged with the date and time of occurrence, as reported from the original source.

Alarm entries for status data without a reported time-tag shall be posted with the time of entry into the summary; these time entries shall be annotated with the symbol ‘e’, meaning ‘display entry time’.

Alarm Source: Device name, application name, or ‘system’.

Description of the Alarming Entity: Related to the IEC 61850 LD, LN, and CDC attribute, but described in power system, equipment, or functional terms that are familiar and useful to the operator. The operator shall be able to right-click ‘properties’ for this field to see the associated IEC 61850 ‘object reference’ (if applicable).

State Description: A state description shall be assigned to each discrete status value, where a particular interpretation is intended. Examples follow: Open/Closed/In-Transition, On/Off, In/Out, Energized/De-energized, Lockout/Reset; Warning region, Emergency Region, Out-of-Range. These shall correlate with CDC assignments in the IEC 61850 standard, where applicable. The operator shall be able to right-click ‘properties’ for a ‘State Description’ field entry to see the associated CDC attribute name (if applicable).

The state description used with each discrete status value for each reportable entity shall be user-defined, using a standardized, on-screen template in off-line mode. State descriptions considered ‘normal’ shall also be user-defined.

Normal / Abnormal State: A ‘normal’ or ‘abnormal’ entry shall be made, according to user-defined assignments. The operator shall be able to right-click ‘properties’ for a ‘Normal / Abnormal State’ field entry to see the associated value (if applicable). The appropriate IEC 61850 data type representation shall be used.

2. Abnormal Summary

This summary shall be a list of analog points that are outside of operational limits, and of status points that are not in the state defined as “NORMAL” in the Local Repository.

3. Tagged Device Summary

This is a list of all devices that have been electronically tagged. Each entry shall show the date and time that the tag was placed, the log-on ID of the substation operator placing the tag, the substation and point name of the tagged device, the type of the tag, and a operator-entered comment. Entries shall be deleted when tags are removed.

4. Substituted Values Summary

This display identifies the data points whose process value is currently being substituted by an operator-supplied value. The substitute value being used shall be displayed for each point.

5. Alarm Inhibited Summary

This is a list of points for which alarming has been inhibited by operators.

Operators shall be able to select entries from summaries for viewing or for printing, using appropriate search keys for each type of summary.

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3.7.7.6 Log Displays

1. System Logs

StatusLog

CommandLog

ChangeLog

SubLog

FileLog.

2. CompositeLog

An operator shall be able to selectively enable which system logs are used for displaying or printing CompositeLog entries. Entries from the enabled system logs shall be chronologically interleaved, with the most recent entries at the bottom..

3. AlarmLog

This display is for viewing AlarmLog entries in chronological order, with the most recent entries at the bottom.

3.7.7.7 Bulletin Board

A text display shall be included on which any user may make multi-line message entries. The display will be used to convey information among users, and from one shift to another. The entries on the Bulletin Board shall be ordered chronologically. When a user makes an entry, or updates an entry, the system shall automatically enter the time, date, and the user’s ID. An entry made by a user may be modified or deleted only by that user or by a Supervisor.

3.7.7.8 System Management Displays

These are displays for monitoring and controlling the SA system. They shall include:

1. System Configuration Control Display

2. MMI Assignments Display, for the management of M MI modes

3. Display for monitoring and controlling the SubLA Ns

3.7.8 Control Capabilities

1. Primary Controls

These shall provide control capabilities for the primary system equipment (e.g. circuit breakers, disconnects, earthing switches, power transformer LTCs, recloser enable/disable) through the station’s one-line diagram, using select-before-operate control procedures.

2. Device Tagging

This control capability shall allow controllable devices to be tagged, so that control is by SCADA/EMS, an Operator Interface [MMI], or any other system or enterprise client is inhibited.

This electronic tagging shall be coordinated with use of physical tags on manual control boards and panels. The Tagged Device Summary shall show the system devices that are currently tagged. Tagged devices must be clearly indicated on the one-line station diagram.

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3. Recloser Mode Selection

This control shall allow recloser modes to be selected according to the prevailing situation (e.g. normal, storm, high wind). It shall be supported by a display of the current mode setting.

4. Relay ‘Settings Group’ Mode Selection

This control shall allow a particular protection relay group setting to be activated, when multiple group settings are available. It shall be supported by display of the currently active setting.

5. Primary CCU Selection

This control shall allow the operator to designate which CCU is managing the station, if two are provided. If there is only one CCU, this capability shall be disabled. If enabled, the primary CCU shall be identified in the Station Status Display.

6. Value Substitution

This control capability allows the operator to set substitute values for malfunctioning data points. IEC 61850 substitution services and object references shall be used to carry this out.

7. CCU Restart

This control allows a warm restart or cold restart to be initiated for either the Primary CCU or Standby CCU..

8. Operator Interface Restart

This control allows the operator to restart the Operator Interface.

3.7.9 Other Capabilities

1. Historical Data Reports

This capability is only provided at Terminal Stations. It allows historical data reports to be viewed and printed, as allowed by the tools and facilities provided by the Historical Data application.

2. IEC 61850 Configuration Control

The Operator Interface [MMI] unit shall be able to use the SCL tools (described under the System Configuration heading) off-line to prepare system and IED configuration files. Subsequently, it shall be have the capability to download these files to IEDs.

3. Off-line Editing

Although the Operator Interface shall be delivered with a set of displays already intact, MEA personnel shall be provided with tools and procedures for editing the information to be presented on each display, as well as the screen layouts. These tools shall use IEC 61850 object references to identify data. System reports shall likewise be accommodated.

The editing tools and capabilities shall allow MEA personnel to modify displays and related data on another off-line PC platform. The editing tools and capabilities shall apply to both text-based displays and one-line diagrams. They shall include use of graphical elements, dynamic behavior (e.g. flashing, color), displayed data, static text, and screen layout. The editing tools and capabilities shall allow MEA to modify and/or create the dynamic and static icons used to represent primary and secondary system components.

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The editing tools and capabilities shall allow MEA to designate whether alarms are major or minor, to determine the normal states for all status data (as appropriate), and to identify the electrical equipment contact associated with each status input (e.g. ‘b’, normally closed contact).

The resulting files from all these editing activities shall be backed up on portable media and/or the CCU(s), as a hedge against loss.

3.8 REMOTE FILE MANAGER

The Remote File Manager shall comprise software and any ancillary hardware running on a desktop or notebook PC. It shall provide the capability to remotely manage and perform file operations with a target SA system. These operations shall include file downloads (e.g. software, applications, configuration, data), uploads (e.g. configuration, data), file deletions, and file attributes. In other words, it shall support all file services described under the File Management heading.

As these operations are to be performed from a remote location, care shall be taken to provide security measures. These capabilities shall require administrative passwords and be complemented by audit trail records to identify the person, platform, time, and file action for each remote operation. Note that the latter may be fulfilled through the FileLog records produced by the CCU at the station site. The contractor shall ensure that these capabilities work together in the intended manner.

3.9 EQUIPMENT POWER SUPPLY

A stand-alone power unit (DC/DC converter or DC/AC inverter) shall be provided for computer systems, peripheral devices, the fiber-optic modem, and GPS receiver. MEA’s preference is that all other equipment (including IEDs) incorporate their own power conversion and protection circuits, so that they can be directly connected to station battery.

3.9.1 Power Circuits within other Equipment

Power circuits within another piece of equipment are assumed to be specific to and dedicated to that piece of equipment. If the power circuits lack adequate monitoring and protection for abnormal conditions, it will reflect badly on the performance and acceptance of the whole device.

Equipment incorporating its own power circuits shall provide input fusing and an ON/OFF switch. As the equipment is to operate in a substation environment, the power circuits shall comply with the specifications in IEC 60870-2-1 and IEEE C37.1-1994.

3.9.2 Stand-Alone Power Units

Stand-alone power units frequently provide power to a number of independent loads. Since the design of the power units and the design of those system loads are independent, precautions are taken in these specifications to ensure that a proper power distribution environment is maintained.

Station battery power wiring shall be routed to stand-alone power units through an input power panel. The panel shall provide fusing, voltage monitoring points, and an ON/OFF power switch. The design, location, and connection of fuse carriers and bases shall facilitate convenient fuse replacement.

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All power conversion circuits shall provide overvoltage protection against normal-mode transients at their supply inputs and provide common-mode voltage standoff capability suitable for the substation environment. Power unit outputs shall be isolated from earth ground and short-circuit proof. In general, any load condition (including short-circuit) that exceeds the unit’s capability to deliver quality power shall cause the power unit to temporarily shut down. After a reasonable delay (two seconds, for example), the unit shall start up again, testing the load conditions. This cycle shall repeat indefinitely until the power unit can support the load. The important thing is that the unit be capable of automatically handling abnormal load conditions and recovering normal operation without human intervention.

Overvoltage and undervoltage protection at the power unit outputs shall be included to protect load circuits. Normal power unit operation shall not be disrupted by brief load transients, which may occur when individual system loads are added or removed. LEDs shall be used to indicate that the unit has is working properly and that input and output voltages are within the proper ranges.

DC/DC converters shall incorporate reverse polarity protection at the inputs to protect against connection errors. Station battery shall not be earth grounded.

Power supply busbars in cabinets shall be carefully routed and each busbar shall be shrouded. It shall not be possible to inadvertently short busbars, either between themselves or to earth.

Below the cut-off levels for distribution voltages, equipment (being powered) shall shut down in an orderly manner without generating spurious alarms, generating wild fluctuations in analog readings, or causing unintended control operations.

The stated power unit ratings and reliable operation shall be maintained over the full system temperature operating range and over the entire input supply (i.e. station battery) voltage range. The contractor shall state the power requirements and dissipation rates for each modular sub-rack and fully populated rack in the detailed design documents.

The power unit shall comprise two units and transfer switch. The DC input and AC output shall be isolated from each other (two batteries). The AC. output neutral point shall be solidly earthed. The power units shall be arranged with a main bypass supply, an electronic transfer switch and maintenance bypass circuit.

The transfer switch shall be rated to match the output of the power unit. The transfer time shall not exceed 1 ms. The transfer shall normally be synchronous, but the transfer switch shall be capable of a synchronous operation. Transfer from the main bypass circuit to a power units shall only be initiated manually.

3.9.3 Wetting Voltage

The 125 Vdc station battery voltage shall be used to wet dry contacts for status and counter inputs. As part of installation requirements, the contractor shall be responsible for any required modifications to existing circuits that already carry the 125 Vdc wetting voltage.

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4 SYSTEM DESIGN CONSTRAINTS AND TESTING

4.1 GENERAL REQUIREMENTS

The SA systems shall be manufactured to the highest possible quality to achieve a minimum of ten (10) years useful operating life.

The SA systems shall reflect state-of-the-art, mainstream engineering for continuous-duty service in the substation environment, shall be built of all new material of the best industrial grade with proven reliability, and shall be designed to provide reliable service subject to reasonable maintenance and replacement of consumable parts.

The components of the SA systems shall be unused, free from defect or irregularity, and reflect good engineering judgment with respect to strength, durability, electrical characteristics, insusceptibility to failure, and suitability for the intended service. Materials that may promote the growth of fungus or be susceptible to corrosion shall not be used.

The components of the SA system shall be of current production from industry recognized component manufacturers. The manufacturing process shall be ISO 9001 certified. A copy of the current Certificate of Accreditation shall be included in the bidder’s proposal. In the absence of such certification, bidders shall be capable of demonstrating that the proposed Quality Assurance Program meets or exceeds these standards or is otherwise acceptable to MEA. Bidders shall also submit a detailed description of the proposed Quality Assurance Program in the bidder’s proposal. All hardware and software/firmware of the microprocessor-based components shall be free from defects, new and unused.

4.1.1 System Design and Engineering

Unless explicitly excluded in this specification, the contractor shall perform all work and supply all items and materials for achieving completion of the work. This shall include all work, items, and materials, whether they were explicitly specified or not, provided they can be reasonably inferred from this specification as being required for achieving completion of the work, just as if they were expressly specified.

The contractor shall be responsible for any discrepancies, errors or omissions in this specification, drawings, and other technical documents that it has prepared, whether such specification, drawings and other documents have been approved by MEA or not, provided that such discrepancies, errors or omissions are not because of inaccurate information furnished in writing to the contractor by MEA.

The contractor shall be entitled to disclaim responsibility for any design, data, drawing, specification, or other document, or any modification thereof provided by MEA, by giving a notice of such disclaimer to MEA.

The contractor shall execute the basic and detailed design and the engineering work in compliance with all requirements specified in this specification, or where not so specified, in accordance with good engineering practice, the emphasis being on reliability and maintainability.

System design shall emphasize use of ‘normal operation’ indicators and self-monitoring / self-diagnosis routines that are able to report operational status to the Local Repository for eventual use by the Operator Interface [MMI] unit.

4.1.2 System Reliability and Availability

Since a Substation LAN is shared for all information-related processes, any failure or disruption that significantly impairs network communications has the potential for bringing down a critical portion of the whole system. It is very important to anticipate the situations that may cause this to

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happen and to mitigate the overall risk to an acceptable level. Risks can be expressed in terms of probabilities, and those probabilities can be combined mathematically to calculate an estimate of annual system downtime. Those calculations depend on the system configuration, interdependencies of system components, and how well the individual components are designed. Realistically, low failure rates are heavily dependent on consideration of environmental and electrical susceptibility factors in equipment selection and design, good engineering judgment and practice, competent and trained O&M personnel, proper attention to system problems, and avoidance of electrical components that require manual adjustment or repositioning during configuration or maintenance (e.g. electronic connectors, jumpers, and switches). The contractor shall keep these and related factors in mind when responding to this specification with a proposed design.

The contractor shall submit his rationale, reliability data, and availability calculations in support of his proposal. The contractor may use any widely recognized reliability tool or method that he believes helps construct his case, but how these are applied must be documented for MEA’s review. MEA will expect cogent, credible, and persuasive evidence for the selected approach. Proven track records will carry greater weight than purely theoretical calculations, although track records need to be substantiated through a number of customer references for like systems (including contact information for persons who can provide authentic testimony). Cherry-picking of several customer references is strongly discouraged; a greater number or references will dispel this concern. Documents supporting the contractor’s reliability/availability claims shall be submitted to MEA within 30 days of the bid opening date. MEA has a strong preference for a system approach that does not require routine maintenance. The IEC 60870-4 standard shall be used as a guide for addressing these issues.

MEA requires the following guaranteed reliability criteria:

1. Annual availability of the system shall be 99.95% or better on average (IEC 60870-4, Table 2 – Class A3). This requires that system downtime be less than 262 minutes per year.

2. MTTR: Trained maintenance personnel shall not require more than six (6) hours to restore the SA system to normal service (IEC 60870-4 Table 3 – Class M4).

The above figures shall exclude administration time and traveling time. Recommended test equipment and replaceable spares are assumed to be locally available to sites needing their use, although these assumed resources must consequently be included in the proposal.

4.1.2.1 Critical Functions

Critical functions are defined as the system functions that need to remain available when a single point of failure occurs in the system. Failures that affect critical functions are subject to the guaranteed reliability criteria. They include the following:

1. Any failure that brings down the entire system.

2. Any failure that causes loss of core station functionality, including:

Local station control (i.e. MMI functions)

Historical data processing (at Terminal Stations)

SCADA/EMS support

Enterprise communications

Station LAN communications

Operation of or access to the Repository

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Programmable logic application processing or supervision

Proper operation of the system logs

System configuration control or diagnostics

Field data acquisition and processing

Time synchronization

3. Any other failure that interrupts system capability beyond that solely attributable to the failed resource.

For example, loss of a single BCU may be excluded if it only results in the loss of data for which it is directly responsible. Loss of all data acquisition, however, comprehensively disables SCADA/EMS support, requiring that failure be subject to the guaranteed reliability criteria.

4.1.2.2 Non-Critical Functions

Non-critical functions are defined as system functions that do not need to remain available when a single point of failure occurs in the system. Failures of non-critical functions are not subject to the guaranteed reliability criteria. Non-critical functions include the following:

1. Database generation and modification (an off-line function)

2. Display generation and modification (an off-line function)

3. ‘Programmable logic application’ generation and modification (an off-line function)

4. Backup of real-time data

5. Archiving

6. Access to on-line documentation

7. Printing functions

4.1.3 System Security

Because of the critical nature of the SA system’s operation and its networked relationship with other systems, security is of major concern to MEA. System components and integration methodology shall provide robust security features to prevent unauthorized users from reading or writing data or files, executing programs, or performing operations for which they do not have appropriate privileges.

The SA system software shall have no special undocumented user sign-on procedure, such as might be used by the programming staff of the contractor or the supplier of the operating system while the software is being developed.

The software system shall be free of viruses when delivered, and shall contain the most recent version of virus detection software.

The contractor shall recommend security capabilities that provide reasonable protection for a reasonable cost, so as to significantly reduce the risk of damage, loss of information, unauthorized use, or impairment of use or control of the station facility.

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4.1.4 System Sizing

Table 2: SA SYSTEM SIZING

Description Ultimate System

1. Local Repository Sizing

Analog Points

Status Points

Counter Points

Control points (2 & 3 state)

Calculated Analog Points

Set Point Control

The Local Repository sizing shall be met with the requirement for the calculated point counts using the substation’s ultimate configuration given in APPENDIX C and point counts for typical stations given in APPENDIX D plus requirements specified elsewhere in this specification

2. Historical Data

Number of values stored once per hour for a period of 3 months, plus the current month.

All values in the Local Repository

Number of values stored twice per day for a period of 120 days (peak daytime values and peak nighttime values)

All analogs and counters in the Local Repository

3. Summaries

Alarm file entries 1,000

A&E file entries 2,000

Abnormal summary entries 500

Alarming inhibited summary entries 500

Tag summary entries (maximum number of equipment tags)

500

** Note: The IEC 61850 information models include a considerable number of additional data components to support the real-time data components identified above. Local Repository sizing requirements for these additional data components are not included here and shall be determined by the contractor.

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4.1.4.1 Initially Delivered Systems

Upon delivery, each SA system’s technical infrastructure shall be sized to meet the substation’s ultimate configuration, as specified in Appendix C. By ‘technical infrastructure’ this specification means the wiring, cabling, connections, enclosures, IED mounting positions, Ethernet switch ports, Repository memory sizing, etc shall all be planned and ready to accept new equipment boxes for the system expansion expected in the future. No new technical infrastructure or engineering shall be required to expand from the initially installed system to the ultimate, planned system configuration. The I/O point counts can be anticipated from the information in Appendix D. Programmable logic applications and other requirements shall be interpreted from descriptions elsewhere in this specification.

All screen displays and other items related to the non-existent or spare bays shall be included in the design of the SA system, as if it already existed, but shown on the screen in a distinctive manner to indicate that it is ‘future’ in nature.

1. Reserved Capacities

At least fifty percent (50%) of installed RAM in the CCU, bay, and MMI processors shall be provided as spare memory. The system shall be able to meet all functional and performance requirements with the spare capacity blocked off or physically removed.

At least eighty percent (80%) of each installed disk’s capacity shall be uncommitted and reserved for future use.

During all performance and functional tests of the Factory Acceptance Test (FAT), the spare RAM and disk capacities shall be blocked off, removed, disabled, or loaded with dummy information, to prevent their use by the supplied software.

2. Utilization Requirements

Over any five (5) minute period (including end-of-hour, end-of-day and end-of-month), the utilization of SA system components during the system activities defined for system performance testing shall not exceed the following limits:

The total loading of a CCU processor shall not exceed thirty percent (30%)

The total loading of a bay processor shall not exceed thirty percent (30%)

The total loading of an Operator Interface [MMI] processor shall not exceed fifty percent (50%).

No disk associated with the CCU shall be busy with data transfers more than twenty percent (20%) of the time.

No more than 8% of SubLAN bandwidth shall be in use at any time. (Ethernet contention becomes a problem when bandwidth exceeds 20%.)

The SA system shall be provided with hardware and software measuring tools to enable precise measurement or calculation of utilization for all system components.

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4.1.4.2 Expansion and Upgrading

In order to accommodate system expansion beyond the ultimate size, MEA requires that the system incorporate hardware and software capabilities that support operational and quality of supply applications that are expected to emerge in the future. This concept requires that the system be design in a manner that progressively allows older equipment to be replaced with new equipment, so that system performance, maintainability, and reliability can be improved. This specification refers to this as a planned migration strategy. In his bid, the contractor shall lay out his vision for a credible migration strategy, supported by the system implementation that he proposes.

The contractor shall indicate in his bid which portions of these technical specifications will be met by existing products, which portions will require additional development, and when the various pieces of additional development will be available. The contractor shall describe how the various pieces are to be integrated to produce the desired system capabilities.

The system shall be designed to facilitate the future addition of station bay equipment, as follows:

1. The system hardware and software modules shall be scaleable, configurable, standard types, employed in similar projects elsewhere. For future modifications or expansions, this system structure shall be easily extendible through the addition of new components of same or similar type. For new components, having the same functionality as the original system, additional programming shall not be required; only the configuration shall be adapted.

2. With appropriate training by the contractor, MEA personnel shall be able to make all database and system changes to support system growth, using tools and procedures supplied with the installed system and without regeneration of system software.

Bidders shall also identify how the supplied system can be modified to accommodate the following system capability options:

1. Communications with each of two SCADA/EMS control centers, using independent communication channels and separate sets of system configuration parameters, over the existing SDH network using DNP3 protocol.

2. Autonomous supervisory control and automation of a remote distribution plant outside the substation fence. For such applications up to thirty (30) typical items of an outside distribution plant (e.g. primary and secondary system devices, such as load-break switches, reclosers, voltage regulators, etc) would be connected via satellite IEDs connected via fiber-optic cables to the SA system. Either IEC 61850 or DNP3 communications might be used, depending on technical and cost factors.

4.1.5 Reference Standards

4.1.5.1 Standards Groups

Except as specified elsewhere in this specification, the SA systems shall be designed, manufactured, integrated, installed, configured, and tested in conformity with the latest revision of applicable standards governed by the groups listed below:

ANSI American National Standards Institute

ASCII American Standard Code for Information Interchanges

ASTM American Society for Testing and Materials

CCITT Consultive Committee International Telegraph and Telephone

CISPR International Special Committee on Radio Interference

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EIA Electronic Industries Association

EN European Standard

FCC Federal Communication Commission

IEEE Institute of Electrical and Electronics Engineers

IEC International Electrotechnical Commission

ISO International Organization for Standardization

NEC National Electrical Code

NEMA National Electrical Manufacturers Association

RAL Deutsches Institut für Gütesicherung und Kennzeichnung e.V.

In case of conflict between the requirements of any of these authorities, the conflict shall be referred to MEA for resolution. In the event of contradictory requirements between such standards and this specification, the terms of this specification shall govern. Any relevant issues not specifically covered by these standards shall be submitted with options and recommendations for MEA’s approval.

Any significant deviations from these standards shall be clearly communicated within proposals under the heading “Deviations from MEA'S Specification”.

Proposals may be submitted that are based on other national standards having similar characteristics and providing equal performance and/or quality to those specified. In this case, complete English language copies of the standards shall be submitted with the proposal; otherwise, such offers may be rejected without further consideration.

4.1.5.2 Specific Relevant Standards

The following are specific standards with special relevance to this technical specification. Conformance with their content shall receive especially close scrutiny. The contractor shall ensure that the delivered systems comply with the requirements of these standards, as conditioned by the specific requirements of this technical specification.

1. IEC 60870: Telecontrol Equipment and Systems. The following parts of this standard are relevant to this technical specification. They refer to numerous IEC base standards used to conduct type-testing.

IEC 60870-2-1-1995: Telecontrol Equipment and Systems – Part 2-1: Operating Conditions – Section 1: Power Supply and Electromagnetic Compatibility

IEC 60870-2-2-1996: Telecontrol Equipment and Systems – Part 2-2: Operating Conditions – Section 2: Environmental Conditions (Climatic, Mechanical, and other Non-Electrical Influences)

IEC 60870-3: Telecontrol Equipment and Systems – Part 3: Interfaces (Electrical Characteristics)

This standard addresses interfaces between telecontrol equipment and the following: (1) process equipment (i.e. field I/O points), (2) operator equipment, (3) communication subsystems, and (4) other data processing equipment.

IEC 60870-4: Telecontrol Equipment and Systems – Part 4: Performance Requirements

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This document shall be used as the project planning reference for addressing reliability, availability, maintainability, security, time parameters affecting performance, and overall accuracy of the delivered systems. Although written for telecontrol systems using serial communications lines, the broad content of this document applies to the systems to be delivered under this technical specification. If any aspects of this document’s content are contraindicated by IEC 61850, the latter shall prevail in those instances.

2. IEC 61010-1: Safety Requirements for Electrical Equipment for Measurement, Control, and Laboratory Use: General Requirements

The SA systems delivered under this technical specification shall conform to the requirements of this standard.

3. IEC 61850: Communication Networks and Systems in Substations

This standard represents the principal communications architecture for the SA systems to be delivered under this technical specification. It includes a network profile, communication services, and information models. During Factory Acceptance Testing and other times, MEA personnel or their agents may inquire how these safety requirements have been applied to the delivered systems and request testing in specific areas of interest.

IEC 61850-1: Communication Networks and Systems in Substations – Part 1: Introduction and Overview.

IEC 61850-2: Communication Networks and Systems in Substations – Part 2: Glossary

IEC 61850-3: Communication Networks and Systems in Substations – Part 3: General Requirements

IEC 61850-4: Communication Networks and Systems in Substations – Part 4: System and Project Management

IEC 61850-5: Communication Networks and Systems in Substations – Part 5: Communication Requirements for Functions and Device Models

IEC 61850-6: Communication Networks and Systems in Substations – Part 6: Configuration Description Language for Communications in Electrical Substations Related to IEDs

IEC 61850-7-1: Communication Networks and Systems in Substations – Part 7-1: Basic Communication Structure for Substation and Feeder Equipment / Principals and Models

IEC 61850-7-2: Communication Networks and Systems in Substations – Part 7-2: Basic Communication Structure for Substation and Feeder Equipment / Abstract Communication Service Interface

IEC 61850-7-3: Communication Networks and Systems in Substations – Part 7-3: Basic Communication Structure for Substation and Feeder Equipment / Common Data Classes

IEC 61850-7-4: Communication Networks and Systems in Substations – Part 7-4: Basic Communication Structure for Substation and Feeder Equipment / Compatible Logical Node Classes and Data Classes

IEC 61850-8-1: Communication Networks and Systems in Substations – Part 8-1: Specific Communication Service Mapping (SCSM) / Mappings to MMS (ISO 9506-1 and ISO 9506-2) and to ISO/IEC 8802-3

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IEC 61850-10: Communication Networks and Systems in Substations – Part 10: Conformance Testing

4. IEEE C37.1-1994: Definition, Specification, and Analysis of Systems used for Supervisory Control, Data Acquisition, and Automatic Control

This standard shall be applied to any implementation involving field connections for I/O points, such as BCU field circuits. It overlaps IEC standards 60870-2-1, 60870-2-2, and 60870-3, but addresses issues that the IEC standards may not address as well [e.g. common mode voltage standoff for analog input signal processing, rejection of normal and common mode voltages in analog input signal processing, rejection of false status changes, time-tagging precision and time of application, change of status monitoring, and change validation (i.e. digital signal filtering)].

5. IEEE C37.90.1-2002: IEEE Standard Surge Withstand Capability (SWC) Tests for Relays and Relay Systems Associated with Electric Power Apparatus

6. IEEE C37.90.2-2004: IEEE Standard for Withstand Capability of Relay Systems to Radiated Electromagnetic Interference from Transceivers

7. IEEE C37.111-1999: Common Format for Transient Data Exchange (COMTRADE) for Power Systems

8. IEEE C37.115-2003: Test Method for Use in the Evaluation of Message Communications between IEDs in an Integrated Substation Protection, Control, and Data Acquisition System

9. IETF – RFC 542: FTP standard

4.2 SYSTEM PERFORMANCE REQUIREMENTS

4.2.1 The General Rule

If a person asks how fast real-time data needs to be, the answer should generally be “whatever it takes to make the applications successful”.

To elaborate and broaden the previous statement somewhat: Applications and system processes need timely data in order to perform their functions successfully (i.e. late data can cause them to fail their system missions). The General Rule is that the system must reliably process and deliver all system data within times that satisfy the requirements of individual system functions, applications, and overall system performance expectations.

This specification lays out certain expectations for system functions and applications, and also imposes constraints on the design approach (e.g. use of the IEC 61850 communications standard; use of Substation LANs). It is the contractor’s responsibility to make it all come together in a consistent manner, to achieve the desired intent and specific results. This clause describes the timing and other metrics required of the system.

4.2.2 Time Synchronization and Time-Stamping

All station time-stamping processes are expected to provide accurate time-tags within a precision of +/-0.5ms of absolute time.

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4.2.3 CCU

4.2.3.1 ‘System Log’ Entries

System log entries shall be added within one (1) second of when the initiating conditions are updated in the Local Repository.

4.2.3.2 Backup of Real-Time Data

Data that is stored in volatile memory (i.e. memory whose contents are lost when power is interrupted) shall also be stored locally on hard disk or in flash memory for use in warm restart procedure. The contents of the Local Repository in a primary CCU shall be incrementally backed up in the standby CCU and on disk or in flash memory as they occur.

4.2.3.3 Time Synchronization

The CCU module shall synchronize IEDs once per minute over the network. If the TDS or GPS signal fails, the CCU shall synchronize IEDs once per minute using the SCADA/EMS source, following a user-defined delay. The default value for the delay shall be one hour.

4.2.4 Operator Interface [MMI]

4.2.4.1 Operator Request Completion Time

During the system activities defined for system performance testing (refer to ‘System Performance Testing Requirements’), the system shall complete responses to MMI operator requests within one (1) second, following the request. These requirements shall apply to all operator requests, including the following:

Operator Request System Response (within 1 s)

Point selection on a monitor Pop-up window appears.

Alarm acknowledgement Acknowledged alarm stops flashing.

Control request The system confirms the control action selected.

Control execute Control sent to the responsible server IED.

Control point tagged. Tag is in effect and shown on monitor. The tag summary is updated.

Alarm inhibit Alarm checking stopped; inhibit indication (I) shown on the appropriate displays; inhibit summary is updated.

Silence audible alarm Sound stops.

Real-time data point placed out-of-service / in-service

Processing of the point is stopped / resumed, deactivated summary is updated.

Table 3: Operator Request Completion Times

4.2.4.2 Display Update Time

During the system activities defined for system performance testing (refer to ‘System Performance Testing Requirements’), the following display update times apply to the MMI monitor:

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1. The delay between the occurrence of a status event at the station and the appearance of the corresponding Alarm Summary entry shall not exceed two (2.0) seconds.

2. Updates of measured or status values appearing on a display shall occur within two (2.0) seconds of their being updated in the Local Repository. This shall be tested with values that change once per second.

3. System time shall be shown on displays with a resolution of one (1.0) second and shall be updated once per second.

4.2.4.3 MMI Boot-Up Time and Start-Up Time

The MMI’s ‘Boot-Up Time’ is defined as the time interval beginning when power is turned on (or the MMI is rebooted) and ending when the user is prompted to perform a log-on. The boot-up time shall not exceed one (1) minute.

The MMI’s ‘Start-Up Time’ is defined as the time interval beginning when the user completes the log-on and ending when the initial set of displays has been completely generated, input data is being received and processed, the displays are being updated with real-time data, and the Operator Interface [MMI] unit is ready to accept user input. The ‘Start-Up Time’ shall not exceed two (2) minutes.

4.2.4.4 System Restarts

Two (2) modes of restart are required:

1. A warm restart in which the database resident in volatile memory is restored from disk.

A mechanism for warm restarting the system (e.g. CCU) shall be provided. The warm restart may be used to reset the DNP application, but not necessarily to reset other application programs. Typically, the warm restart is used to initialize the configuration. A warm restart shall be initiated only in response to an MMI request from an authorized user.

Time for a warm restart shall not exceed twenty (20) seconds.

2. A cold restart is a complete restart of the system after a power loss or after it had been de-powered and then re-powered up.

After a power outage or total shutdown of the system, the total elapsed time for a complete system start-up, beginning when power is restored and ending when data processing is initialized, real-time data is available at the MMI and SCADA/EMS control center, and all functions are operational, shall not exceed five (5) minutes.

System Restarts shall cause a major alarm to be generated. This status shall be mapped and automatically sent to the SCADA/EMS control center.

System Restarts shall not clear system logs, which shall normally be kept in non-volatile memory and archived on disk.

4.2.5 Communications

4.2.5.1 Network Associations

The following specifies the minimum number of concurrent LAN associations that each type of IED shall be able to maintain:

IED Servers: 4

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CCU IED: 50

Operator Interface [MMI: 6

TDS: 4

4.2.5.2 SubLAN Data-Interchange Failure between Sta tion-Level and Bay-Level

The failure of SubLAN data interchange between station-level and bay-level IEDs shall not affect the capability of IEDs at either level from continuing their individual responsibilities and buffering the data to eventually be communicated. At a certain point, of course, finite buffers overflow and the oldest data is . These shall be circular buffers, designed to accommodate 1,000 entries. If a circular buffer were to overflow through extraordinary circumstances, the oldest entries should be discarded as newer ones are added. This would at least enable MEA to salvage the most important data.

4.2.5.3 Communication Errors

The system shall track communications error statistics for each LAN port and serial communications port (if applicable), on a module-by-module basis. The statistics shall be displayed by the Operator Interface [MMI] unit.

A user-defined percentage, applicable to each LAN port, shall be used to determine when communication failures exceed an acceptable rate over a particular period of time. A second percentage shall be applied to serial ports (if applicable). When those rates are exceeded, the affected port shall be alarmed as ‘Excessive Error Rate’. Separate, but lower, user-specified percentages shall be applied to determine when a port has again achieved an acceptable rate. When it does, the port shall be returned to a ‘Normal’ status. A sufficiently long, user-specified interval (30 to 300 s) shall be used to make these assessments. Failures for a given module shall not be counted when its port is taken out-of-service or when the module cannot successfully communicate because of external failures (e.g. the failure of a communications partner).

4.3 HARDWARE REQUIREMENTS

This section describes hardware specifications for the various modules and subsystems that comprise the SA system. These are not functional specifications, but are specifications regarding other required qualities of hardware that make it acceptable for use in MEA’s systems.

4.3.1 Equipment Power Supply

4.3.1.1 General Specifications

Power units and circuits, whether stand-alone or incorporated within other equipment, shall be designed to operate reliably, maintaining their stated power-delivery capacity and other specifications in compliance with IEC 60870-2-1 and IEC 60870-2-2. The station battery voltage and compliance-levels selected for use in the systems to be delivered are as follows:

AC power supply -

Nom. input voltage 220 V, 50 Hz

Input voltage range -15% to +10% IEC 60870-2-1 Class AC2)

Freq tolerance ±5% IEC 60870-2-1 Class F3

Harmonic content tolerance: < 10% IEC 60870-2-1 Class H2 (input voltage)

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Inverters -

Output voltage variations < 10% IEC 60870-2-1 Class AC1

Harmonic content tolerance: < 10% IEC 60870-2-1 Class H2 (input voltage)

DC/DC converter -

Nom. Input voltage: 125 Vdc

Input voltage range: -20% to +15% IEC 60870-2-1 Class DC3

Input earthing condition: Floating earth IEC 60870-2-1 Class EF

Input voltage ripple: < 5% IEC 60870-2-1 Class VR1

If a piece of equipment cannot accept 125 Vdc, it is acceptable to use 48 Vdc through provision of a stand-alone 125VDC/48VDC converter.

The load on a power supply, converter, or inverter shall not exceed 70% of its rated power output capacity. Power unit efficiency shall be 75% or higher.

4.3.1.2 System-Related Specifications

Several other requirements are listed below. They represent conditions that must be met between the integrated SA system and the power units that supply it. The fulfillment of these requirements shall be demonstrated during Factory Acceptance Testing and Site Testing.

1. SA system shall tolerate a 20ms interruption in the auxiliary supply without de-energizing. (Reference IEC 60255-11)

2. SA system shall tolerate 12% ripple on the DC auxiliary supply. (Reference IEC 60255-11)

3. The starting current shall be less than 10A if the nominal load current is less than 2A. Otherwise, starting current shall be less than 3 x the load current. (Reference IEC 60870-4)

4.3.2 IED Clock Circuits and Time-Stamping Capabili ties

IEDs shall be equipped with a real-time clock, with full calendar support (including leap year). Clock resolution shall be governed by IEC 60870-4, Table 7 Class TR4. Clocks shall have an accuracy of ±2ppm and shall not drift more than twenty (20) ms per hour. If necessary, IEDs shall employ software algorithms to counter inaccuracies and drift resulting from crystal ageing.

All IEDs that need to maintain precise time for time-stamping shall be capable of supporting IEC 61850 time-synchronization by the CCU, maintaining acceptably low drift in time between synchronizations, and time-stamping events with an absolute precision of +/-0.5ms relative to the GPS source.

IEDs shall support local setting of time and date from the front port or HMI panel. This feature is intended only for use in unusual circumstances, such as the loss of CCU synchronization or for IED testing. This set of values shall be maintained by the IED until overridden by a successful time-synchronization from the CCU.

Except for synchronization, the IED’s real-time clock shall be completely independent of outside sources, so that the IED can continue to properly handle its time related applications, should the time-synchronization mechanism fail.

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4.3.3 Substation LANs

Operation of the Substation LANs shall comply with the IEC 61850 Ethernet profile using TCP/IP. Substation LANs shall support 10/100 Mbps operation, with consideration of whether 1Gbps is technically and economically appropriate.

All connections to Substation LANs shall be made using ST or SC or LC connectors. Unless otherwise specified, the Substation LANs shall use multi-mode cable and be sheathed for protection against abrasion and cuts. Fiber optic cable shall be terminated and routed according to best industry practices. All materials shall be industry standard, commercially available, and supportive of the open systems concept. A service loop shall be provided at connection points to allow flexibility for future equipment upgrades.

The Substation LAN design shall not require any routine engineering administration or manual reconfiguration to remedy an equipment failure or to facilitate failure recovery.

The Substation LAN shall be designed to ensure that, in the event of a single LAN cable or LAN interface module failure, none of the SA system functionality shall be lost and at most one IED server (e.g. BCU) shall be isolated from the CCU.

4.3.4 CCU

The CCUs shall be a 19” rack type, industrial standard, computer system and shall be capable of operating under the specified ambient conditions for indoor equipment. The CCU shall conform to UL approved safety standards and be certified to FCC Class B. The statistical MTBF for the CCU shall be not less than 50,000 hours, when analyzed at 75% loading and 25°C.

The CCU shall be manufactured by IBM, Dell, Hewlett Packard, or an equivalent source approved by MEA. Alternatively, an SA system supplier’s computer system hardware is also acceptable if it is designed for use in the electrical substation environment, designed for this purpose, and otherwise meets all requirements. Full repair services shall be available in THAILAND for the selected equipment.

Aside from hardware requirements, the equipment shall incorporate an acceptable real-time operating system and other required system software. Refer to the Software Requirements clause.

The CCU shall be equipped with certain interfaces that enable data and file communication exchanges with other SA system components:

1. Dual Ethernet ports for connection to the SubLANs.

The CCU shall connect to both Substation LANs through separate fiber optic interfaces. Use of the two connectors is described under the ‘Dual Substation LAN Connections’ heading.

2. A serial maintenance port for connecting to a portable Operator Interface [MMI] unit, even though such connections will usually be made via a SubLAN.

The portable MMI unit shall support configuration, testing, commissioning, operational monitoring and control, and troubleshooting of the CCU as described elsewhere in this technical specification.

3. USB ports for connection to a portable flash memory drive (i.e. thumb drive), Zip drive, or hard drive.

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4.3.5 Operator Interface [MMI]

The MMI unit shall conform to UL approved safety standards and be certified to FCC Class B. The statistical MTBF for the MMI unit shall be not less than 50,000 hours, when analyzed at 75% loading and 25°C. The equipment shall be capable of operating under the specified ambient conditions for indoor equipment.

The MMI unit shall be manufactured by IBM, Dell, Hewlett Packard, or an equivalent source approved by MEA. The equipment shall be warranted to work in MEA’s electrical substation environments. Full repair services shall be available in THAILAND for the selected equipment.

The MMI unit shall connect to both Substation LANs through separate fiber optic or coppper media interfaces, using ST or RJ-45 connectors. Use of the two connectors is described under the ‘Dual Substation LAN Connections’ heading.

Aside from hardware requirements, the equipment shall incorporate the required system software. Refer to the Software Requirements clause.

4.3.5.1 MMI Units based on Desktop PC

MMI units based on a desktop PC shall meet the minimum specifications shown in Table 4, unless the contractor believes that the specifications are not sufficient for meeting requirements or that the specifications can be better oriented to available, mainstream products. In either case, the contractor shall submit a counterproposal to MEA, accompanied by reasons for the proposed changes.

Processor Intel® Core™ i7-2600 (3.40 GHz, 8MB cache, 4 cores)

RAM 4 up to 16 GB 1333 MHz DDR3 SDRAM,4 DIMM Slots

Hard Drive SATA (7200 rpm) from: 250 GB Up to: 1 TB

Other Storage SATA SuperMulti DVD writer

Display 23-inch LED color monitor with 1920 x 1080 Resolution , 250 Brightness, 2ms Response Time, 1,000:1 Typical Contrast Ratio, 5,000,000:1 Dynamic Contrast Ratio, 170°/160° Viewing Angle

16.7 Million Colors Supported

Video Card NVIDIA Quadro NVS 300 (512 MB) or equivalent

Ports 2 @ 9-pin RS-232C port 1 @ 25-pin bidirectional ECP and EPP (Parallel port) 6 @ Universal Serial Bus ports (USB 2.0) 1 @ 15-pin VGA port 2 @ Ethernet LAN jack: 10/100 Base TX (RJ45) + 100 Base-FX fiber optic interface (ST) or adapter required for each port. 1 @ RJ11 phone jack, 1 eSATA/USB 2.0 combo port

Network Interface & Communications

Dual Fast Ethernet NIC (10/100/1000Mbps) communications adapter with all necessary facilities for Ethernet TCP/IP networking per the IEC 61850 network profile specifications, including compatible TCP/IP stack. (Note: Two independent ports required with same IP address

Keyboard USB standard keyboard with a minimum of 104 keys with Thai/English key labels. Function keys required for dedicated MMI functions.

Operating System Genuine Windows® 7 Professional 64-bit with Thai language support and latest service pack

Accessories Recovery CDs and operating system Microsoft Wheel Mouse™ (USB Interface) Mouse pad Speaker/sound card for audible alarming and for use with future functions Real-time clock, calendar with battery backup, and support for CCU time-synchronization Auto-restart capability 2 @ spare expansion PCI slots for future expansion Diagnostics, on-site installation, and validation

Table 4: Operator Interface [MMI] based on Desktop PC

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4.3.5.2 MMI Units based on Notebook PCs

MMI units based on a notebook PC shall meet the minimum specifications shown in Table 5, unless the contractor believes that the specifications are not sufficient for meeting requirements or that the specifications can be better oriented to available, mainstream products. In either case, the contractor shall submit a counterproposal to MEA, accompanied by reasons for the proposed changes.

Processor Intel® Core™ i7 Mobile Processor Family with Turbo Boost Technology

RAM DDR3 SDRAM (1333 MHz), two slots supporting dual-channel memory, 2048 MB SODIMMs, up to 8192 MB total

Hard Drive 500 GB 7200rpm SMART SATA II HDD

Other Storage Blu-ray ROM DVD+/-RW SuperMulti DL LightScribe Drive

Display 14-inch diagonal LED-backlit HD+ Anti-Glare (1600 x 900 resolution)

Video Card ATI Mobility Radeon™ HD 540v with 512MB dedicated video memory or equivalent

Ports

1 @ 9-pin RS-232C port 1 @ 25-pin bidirectional ECP and EPP (Parallel port) 3 @ Universal Serial Bus ports (USB 2.0) 1 @ 15-pin VGA port 1 @ Ethernet LAN jack: 10/100 Base TX (RJ45) + 100 Base-FX fiber optic interface (ST) or adapter required 1 @ RJ11 phone jack 1 eSATA/USB 2.0 combo port 1 docking connector

Network Interface & Communications

Dual Fast Ethernet NIC (10/100/1000Mbps) communications adapter with all necessary facilities for Ethernet TCP/IP networking per the IEC 61850 network profile specifications, including compatible TCP/IP stack. (Note: Two independent ports required with same IP address

Modem Interface 56-Kbps V.92 MODEM

PC Card Slots 1 @ Type II PCMCIA card slot, CardBus-enabled

Keyboard 87- (US)/88-(Int’l English) key, full-size keyboard (with 101-/102-key emulation) supports Windows keys Embedded Numeric Keypad, 12 function keys, suspend/resume sleep button

Operating System Genuine Windows® 7 Professional with Thai language support and latest service pack

Accessories • Recovery CDs and operating system • Leather luggage • Microsoft Wheel Mouse™ (USB Interface) • Mouse pad • Power adapter, battery and charger

Table 5: Operator Interface [MMI] based on Notebook PC

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4.3.6 Time and Date Server

One (1) GPS satellite disk and receiver shall be provided for time synchronization purposes at each SA system station site. The physical connection and installation of the GPS hardware components shall simple, not requiring any RF or GPS expertise. Any software for configuring or operating the unit shall be provided with the system.

A GPS antenna unit with remote power supply and supporting cable shall be provided. The antenna shall be dc-insulated with dielectric strength of 1,000 V. The interface between the GPS receiver and the GPS input of the TDS module shall be a standard serial interface equipped with an optical-to-serial converter (or equivalent interface with isolation, approved by MEA).

The GPS clock receiver shall withstand operating temperatures up to 70°C and humidity up to 100% non-condensing. The contractor shall supply all necessary cables, connectors, accessories, and mounting hardware needed to support positioning and adjustment of the antenna.

At a MINIMUM the GPS clock receiver shall require no more than one (1) minute to synchronize, using a known receiver position and valid almanac, or twelve (12) minutes if this data is not known.

The following specifications shall be met for the time-synchronization subsystem:

1. The accuracy of the GPS clock receiver shall be better than ±250 nanoseconds immediately after synchronization and ±2 us after 20 minutes of operation (in the absence of further synchronization).

If the GPS signal is temporarily lost, the GPS clock receiver shall continue to provide precise time measurements to the TDS module based on its own low-drift time-keeping, per the drift specification stated directly above.

2. When the SA system is synchronized using SCADA/EMS control center time, the maximum allowable time synchronization error (i.e. deviation from absolute time) shall be not more than 20 ms plus the propagation delay in the SDH network.

The default delay between loss of GPS signal and the use of SCADA/EMS control center time shall be four (4) hours, unless the CCU determines that the time provided by the TDS module is unreasonable for the elapsed time (for example, the TDS module may have failed). In that case, the CCU shall immediately start using the SCADA/EMS control center time for time synchronization. The default delay may be changed via a user-defined parameter.

4.3.7 CGW: Communications Gateway

The CGW shall support a maximum SDH data rate of 19,200 bps, although the operational rate shall initially be set at 9,600 bps. The CGW interfaces with the SDH WAN through a Fiber Optic Modem (FO Modem).

The FO Modem shall be mounted on a standard 35 mm DIN rail. It is the contractor’s responsibility to verify that the modem he selects for use at station sites is fully compatible with existing SDH Node modems used by MEA at other locations (e.g. at the SCADA/EMS control center). If the modems selected by the contractor are not fully compatible with the existing modems, the contractor shall either modify the selected modems or furnish matching modems for existing SDH Nodes.

The CGW module, which interfaces the FO Modem to the SA system, shall connect on the other side to both Substation LANs through separate fiber optic interfaces. Use of the two connectors is described under the ‘Dual Substation LAN Connections’ heading.

MEA will provide one (1) independent communications circuit to the SCADA/EMS control center. The contractor will be responsible for establishing end-to-end communications with the SCADA/EMS control center.

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4.3.8 Serial Communication Interfaces

Where data communication interfaces using DNP3 protocol are necessary, DNP-IP shall be used over the Substation LANs.

Where DNP-IP is not practical (e.g. perhaps for legacy data integration), a DNP serial communication interface shall be used. Any such interface shall be implemented using serial-optical converters to achieve electrical isolation against common-mode voltage and transient failure phenomena. This applies only to serial communication lines that leave protective enclosures.

4.3.9 Bay Control Units with Protection Relays (BCU s)

BCU servers have data acquisition and control responsibilities within the SA system. In the systems to be delivered under this technical specification, they connect to traditional I/O points on the back end (e.g. status contacts, counter contacts, analog inputs, and control outputs). On the front end they are presented as IEC 61850 data models, just as though they originated from true IEC 61850-compatible sources. The data from these models shall be selectively delivered to the CCU’s Local Repository according to station needs.

The BCUservers shall be capable of storing and executing programmable logic applications. In support of a distributed processing environment, they shall be capable of interconnecting with other BCU servers via IEC 61850 GOOSE messaging to acquire status and commands and to provide the same in return. In this way, multiple units can cooperate perform bay interlocking and automation applications. All parameters, configurations, programs, software, and process data shall be stored in non-volatile memory, along with revision control information.

4.3.9.1 Installation Issues

To the extent feasible, distributed BCU servers shall be grouped and installed in station cabinets where the required inputs and outputs can be most easily accessed, in order to minimize the length and complexity of control and field wiring, while providing convenient site service and maintenance. A collateral objective is to reduce the exposure of low-level analog signals to electromagnetic interference (EMI).

Construction requirements for outdoor cabinets are specified in an attachment to this technical specification: ‘Equipment Construction Requirements’. Besides cabinet construction, it governs terminal blocks, cabling, and wiring techniques.

4.3.9.2 Interface, Electromagnetic, and Environment al Compatibility

The BCU servers and any affiliated data acquisition or control modules shall be considered protection grade equipment. They shall be type-test certified as meeting the ‘Compatibility Test Criteria’ for (1) interfaces, (2) electromagnetic compatibility, and (3) environmental issues. Refer to the ‘Compatibility Test Criteria’ heading for specific requirements.

4.3.9.3 BCU I/O Point Types

BCUs shall be equipped to handle and use the required physical I/O points described in APPENDIX D and elsewhere in this specification. Refer to the ‘I/O Point Types’ heading for specifications regarding each applicable point type. The contractor shall provide verifiable information regarding such capabilities and present any limitations of the proposed BCU units in his proposal. The IEC 61850 representations for this data shall be addressed in the Work Statement, after award of contract.

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4.3.10 Printing Facilities

The contractor shall provide printers (for the stations that require them) and all necessary installation components (e.g. LAN interfacing, cabling, connectors). Printers shall be located in close proximity to the Operator Interface [MMI] units.

4.3.11 I/O Point Types

Table 6 summarizes the current I/O point types used by MEA and whether there is support for using each type of point within IEC 61850. Fact is, the IEC 61850 communications standard supports a broader range of capabilities than has been offered by traditional practice.

What follows is a description of each point type and how it is applied within MEA’s power delivery system. This information strongly correlates with the content of IEC 60870-3, concerning interfaces used in telecontrol equipment and systems, although it is a rather obtuse standard to apply. For the purposes of this technical specification, the contractor’s bid response shall describe in detail how the proposed equipment meets these requirements. Equipment shall be examined and tested during Factory Acceptance Tests to ensure these requirements are adequately met.

Point Type Supported by IEC 61850?

Analog inputs

AC-AI: AC Analog Inputs Yes

DC-AI: DC Analog Inputs Yes, but information is limited by the loss of knowledge due to DC representation

Digital Inputs

Single contact, 2-state Yes (including SOE)

Double-contact, 2-state Yes (including SOE)

MCD: 2-state with memory Yes (including SOE)

Digital Outputs

ON/OFF Device Control Yes

Raise/Lower Control Yes

Set-point Control Yes

Variable-Length Control Yes

Direct-Operate Control (and pulse output)

Yes

Table 6: Summary of IEC 61850 Support for I/O Point Types

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4.3.11.1 Analog Inputs

The following descriptions apply to BCU servers that acquire and process analog input values. MEA has traditionally used DC transducers for acquiring values, but going forward, that approach shall only be used in exceptional cases, where other approaches are not convenient or feasible or where economic considerations dominate. For the systems to be delivered under this technical specification, AC analog inputs are the strongly preferred approach. Once protective relays are added to these systems, measurement values shall be acquired from those devices.

4.3.11.1.1 AC Analog Inputs (AC-AI)

BCU servers shall acquire the AC Inputs directly from the current transformers (CTs) and voltage transformers (VTs), without any interposing devices and transducers, and use these inputs to calculate true RMS, the 50Hz phasor, and other power system data.

The BCU servers shall accept AC current and voltage input signals with the following nominal signal ranges:

0 to 5A ac or 0 to 1A ac

0 to 115Vac or 0 to 120Vac

The AC Analog Input (AC-AI) Sub-Module shall be able to convert at least three (3) current inputs of 1A or 5A and three (3) voltage inputs for 115Vac or 120Vac, with linearity better than ±0.05% on the range of 1.2 times of rated values. Configurable assignment of voltage and current pairs for single phase and three phase star or delta configurations and for independent CT inputs shall be provided.

The Overall Accuracy (true RMS) of the AC Analog Input (AC-AI) Sub-Module shall be at least ±0.2% of full scale over the temperature range 0 to 70°C.

The sampling rate for AC quantities shall be at least 32 samples per cycle, using at least a 12-bit- plus-sign A/D converter.

The AC Analog Input (AC-AI) Sub-Module shall be designed to reject common mode voltages up to 150Vac (50 Hz). For DC inputs, normal mode noise voltages up to 5Vac shall be rejected while maintaining the specified accuracy.

For current inputs, the input impedance shall be such that the voltage across the input terminals does not exceed 5 V with full-scale input current [IEC 60870-3 Table 12], and no damage shall occur for sustained 100% overcurrent. For voltage inputs, the input impedance shall not be less than 200kΩ per volt [IEC 60870-3 Table 12].

PT and CT connections shall be wired to individual terminal blocks of the removable-link or bypass-bridge type (as appropriate), so that CT and PT connections may be safely interrupted without removing individual wires. The appropriateness of ABB Combitest or ALSTOM or SIEMENS test switch blocks or equivalent shall be provided. Status, counter, and control field wiring shall be connected to I/O field modules through the existing, disconnectable terminal blocks, so that field wires do not have to be removed to interrupt those circuits. I/O modules shall be replaceable without reprogramming.

Wiring conductors shall be stranded copper wire 500 V class insulation. The cross section area shall be as follows :-

For PT circuit : 1.5 mm2

For CT circuit : 2.5 mm2

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4.3.11.1.2 DC Analog Inputs (DC-AI)

BCU servers shall support DC inputs from linear transducers and other DC instrument sources. These shall be used where CT and PT inputs are not available, where the measurement does not represent power system data, or where economics dictates the choice.

For this project, the interfacing to plant parameters, such as transformer temperature values, transformer tap position, etc shall use a live-zero transducer of 4 to 20mA value. The transducer (if not already installed in a current system) shall come factory-fitted with precision scaling resistors, conform to IEC 60688-2 standards, and be approved by MEA. It shall be possible to remove or replace scaling resistors at site without any resoldering.

The DC Analog Input (DC-AI) Sub-Module shall be configurable to accept DC inputs in the following signal ranges:

Unipolar Voltage : 0-1V, 0-2.5V, 0-5V, 1-5V

Unipolar Current : 0-10mA, 0-20mA, 4-20mA

Bipolar Voltage : ±1V, ±2.5V, ±5V

Bipolar Current : ±10mA, ±20mA

It shall be possible to adapt each individual DC analog input terminal to any of the above input ranges with minimal difficulty. Programmable ‘gain factor’ shall be employed to enable a range of current inputs to be used.

The DC Analog Input (DC-AI) Sub-Module shall support differential inputs to provide maximum noise immunity and shall exhibit common-mode noise rejection characteristics of at least 85 dB between 0 to 50 Hz and normal-mode (differential) rejection of at least 48 dB at 50 Hz.

The Overall Accuracy of the DC Analog Input (DC-AI) Sub-Module, from input terminal to digital value, shall be at least ±0.2% of full scale for current and voltage inputs, over the full temperature operating range. For the definition of accuracy, “FULL SCALE” shall mean the measurement span, which is the difference between maximum positive and negative readings.

The DC analog processing shall use at least a 12-bit-plus-sign A/D converter.

For current inputs, the input impedance shall be such that the voltage across the input terminals does not exceed 5 V with full-scale input current [ IEC 60870-3 Table 12 ], and no damage shall occur for sustained 100% overcurrent. For voltage inputs, the input impedance shall not be less than 200kΩ per volt [ IEC 60870-3 Table 12 ].

4.3.11.2 Digital Inputs

The following descriptions apply to BCU servers that acquire and process digital input values.BCU servers shall support continuous monitoring of contact status inputs and shall have the capability to time-stamp changes that are validated as meeting the change criteria.

Each digital input point shall be implemented with an optical isolating barrier (i.e. opto-coupler) between the internal circuit and the external connection point. The BCU shall support inverting the status via configuration (i.e. a configuration table), so that a “b” or normally closed contact can be reported as an “a” or normally open contact. In addition, each input circuit shall include an LED indicator to show the status of the associated input.

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A soft-filtering technique shall be provided to eliminate noise effects and false-change detections, and to ensure that a changed status signal level persists for a user-defined, minimum period of time before being accepted as a valid change. The user-defined parameter shall be settable between 10 and 100ms. Note that time-stamping is to be performed at the initial transition of the change, but that the change shall only be accepted if validated through the filtering process. The precision of time-stamps must comply with the specification stated under the ‘Time Synchronization and Time-Stamping’ heading. Hard-filtering techniques (using passive electrical components) are discouraged, as they inevitably distort time-stamping values.

The wetting voltage used for input contacts shall be the same as the primary control voltage (125 Vdc from station battery) used within the control cabinet from which the digital input point is acquired.

Note that it is an MMI planning issue as to whether any digital state is to be considered abnormal, whether any state is to be classified as an alarm, and if an alarm, whether major or minor. This interpretive information shall be part of the MMI unit’s configuration, and it is not part of an BCU server’s responsibilities.

The following types of digital input points shall be supported and shall be configurable without the requirement for different hardware.

4.3.11.2.1 Single Contact, Two-State

For single contact, two-state digital input points, a single contact shall represent both states of the monitored device.

4.3.11.2.2 Double Contact, Two-State

For double-contact, two-state digital input points, separate contacts shall be provided for representing the state of the monitored device. The contacts shall be treated as a complimentary pair. One contact (when closed) shall indicate an OPEN condition of the monitored device, while the other contact (when closed) shall indicate a CLOSED condition. When both contacts are open, they represent that the monitored device is in transition (e.g. a motor-operated switch in the process of changing position). When both contacts are closed, they represent an invalid condition.

4.3.11.2.3 Two-State with Memory (MCD)

‘Two-state with memory’ digital input points, also called “Momentary Change Detect (MCD) digital inputs”, shall include a means to indicate that two or more status changes have occurred since the last reported status, regardless of the current status of the device. Both the ‘two-state with memory (MCD)’ digital input and the current status of the point shall be returned in the response message (i.e. a total of two bits). Two-state with memory (MCD) digital input points shall be filtered (i.e. debounced), as described above, to eliminate false indications produced by contact bounce.

4.3.11.3 Digital Outputs

The following descriptions apply to BCU servers that provide control output capabilities.

Digital Output (DO) Sub-Modules shall support control outputs by means of independent, voltage-free, optically-isolated, single-pole / single-throw (SPST) relay output contacts. The contact outputs shall be used to control various station equipment (e.g. circuit breakers [via TRIP/CLOSE commands], motor-operated switches [via OPEN/CLOSE commands], tap-changers [via RAISE/LOWER commands], relay RESET, digital set-point). Transistor outputs are not acceptable. All contacts shall be immune to vibration effects and all contacts shall have a minimum mechanical durability of one million (1,000,000) operations.

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The type of relay output contacts used shall be normally-open (Form A) and they shall be able to make and break at least 5A inductive (L/R ≤ 40 ms) at 125 Vdc. All individual digital output points shall be equipped with an individual BCU to confirm the operation (i.e. energization) of each control relay coil. For heavy-current circuits (e.g. TRIP/CLOSE circuits for circuit breakers), the output relay may be integrated within the BCU server; alternatively, it may be provided by the contractor as an interposing relay. These interposing relays shall be mounted and wired as an integral part of the BCU server’s enclosure assembly and shall be included in the scope of supply. The interposing relays shall be also able to make and break at least 5A inductive (L/R ≤ 40 ms) at 125 Vdc.

Where individual control outputs operate existing circuits that require lower contact ratings, the contractor may propose using lower power-handling relays that are integral to the BCU server. In such cases, the contractor shall be responsible for ensuring that the current handling characteristics of the relay are adequately rated to match the existing interface circuit.

All modules providing digital output points shall be equipped with a control disable switch to disconnect power from control relay contacts, thereby disabling control of equipment. Variations of this approach may be used if approved by MEA.

An auxiliary contact shall be provided on each control disable switch. This auxiliary contact shall be wired to one (1) digital input to provide a remote indication of the switch’s status. These indicators shall be included in the specified point counts.

Each Digital Output (DO) Sub-Module shall be equipped with a dummy breaker (latching relay) as a test indication for control functionality.

One (1) pair of control outputs in each equipped Digital Output (DO) Sub-Module shall be used to handle TRIP and CLOSE commands from a communicating host (e.g. SCADA/EMS or MMI) and two pole trip one pole close of control outputs shall be used to handle TRIP and CLOSE commands from protection functions. The status of the relay shall be acquired by the BCU server as a digital input point for transmission to the communicating host.

The BCU servers shall support the following types of digital output points in order to support control actions initiated by the communicating host or, where applicable, the integrated programmable logic facilities of the BCU servers or SCADA/EMS software applications:

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4.3.11.3.1 ON/OFF Device Control

The DO Sub-Module shall perform ON/OFF control actions using complimentary pairs of contact outputs. One contact output shall perform the “ON” control action, and a second output contact shall perform the “OFF” control action.

The DO Sub-Module shall be designed such that only one output of a complimentary pair can be activated at a time.

These control commands shall use the SBO control procedure.

4.3.11.3.2 RAISE/LOWER Control

The DO Sub-Module shall perform RAISE / LOWER control actions using complimentary pairs of contact outputs. One contact output shall perform the “RAISE” control action, and a second output contact shall perform the “LOWER” control action.

The DO Sub-Module shall be designed such that only one output in a complimentary pair can be activated at a time.

These control commands shall use the SBO control procedure when controlling primary equipment such as LTCs that require control security.

4.3.11.3.3 SET-POINT Control

The DO Sub-Module shall be capable of accepting Set-Point Values (e.g. pre-set, analog output values) from the communicating host (e.g. MMI unit or SCADA/EMS control center, if mapped), and using them to initiate closed-loop control actions through its programmable logic capabilities (e.g. initiating consecutive RAISE/LOWER controls at a transformer tap changer to maintain line voltage at the set-point value).

To support the above capabilities, DO Sub-Module shall provide momentary control outputs and latching control outputs. Each momentary control output shall provide a contact closure (pulse) that has a programmable duration. The pulse duration shall be adjustable on an individual point basis from 0.01 to at least 16 seconds in increments of 0.01 seconds.

In contrast, latching control outputs shall remain in the last commanded state until a subsequent command or until the process variable changes the control output state.

4.3.11.3.4 Variable-Length Control

The DO Sub-Module shall be capable of performing command outputs whose pulse duration shall be adjustable during the course of the output per a set-point parameter received from the communicating host (e.g. MMI unit or SCADA/EMS control center, if mapped).

The voltage rating of the control outputs contacts shall be the same as the primary control voltage (125 Vdc) used within the control cabinet associated with the controlled device.

4.3.11.3.5 Direct-Operate (Pulse Output) Control

Direct-operate controls are typically used for controlling devices and systems that do not require the control security (i.e. they do not use the SBO control procedure). They can be configured as individual or paired outputs.

Direct-operate (pulse output) controls shall be used for step functions, such as precisely-timed RAISE and LOWER commands to generator controllers. Multiple RAISE/ LOWER control outputs shall be able to operate concurrently. On receipt of a command message from the communicating host (e.g. MMI unit or SCADA/EMS control center, if mapped), a timed pulse is sent to a specified device. The time duration is specified in the command message. These controls shall be configurable for latching or pulsed operation.

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It is preferred that BCU servers supporting direct-operate (pulse output) control functionality use the same module as used for secure control. In such a case, the module is able to operate in either mode, according to operational parameters associated with a control point. The direct-operate capability, however, may be provided by a different module.

All control outputs (secure and direct-operate) shall be equipped with individual BCUs to confirm the energized-coil status of each control relay.

4.3.12 Control Circuit Requirements and Internal wi ring Conductors

All BCUs and Protection Relays shall be house in a dust proof cover, class IP51, with a transparent front and shall be provided with test switch blocks.

Low voltage circuit breaker with auxiliary contact and suitable breaking characteristics shall be provided for protection of each measuring and control circuit in each panel.

All internal wiring conductors shall be stranded copper wire 500 V class insulation. The cross section area shall be as follows :-

For voltage and control circuit 1.5 mm2

For current circuit 2.5 mm2

Potential circuits, current circuits, trip circuits and auxiliary supply shall be connected to test switch block.

4.3.13 Console Furniture

The L-shape console furniture shall conform to the proposed MMI, and shall be designed in accordance with generally accepted ergonomic principles regarding the height and orientation of the monitors, the keyboard, and the mouse.

One (1) L-shape desk or two (2) separate computer desks with one (1) operator chair shall be provided and shall have a full depth of at least 70 cm, a depth of approximately 40 cm in front of the monitor, and a free flat area with a minimum size of 100 cm in length by 70 cm in depth.

The L-shape console furniture shall be situated in the substation control room, in a location approved by MEA. The proposed design, dimensions and materials of the desk and chair shall be subject to MEA's review and approval.

4.4 SYSTEM SOFTWARE REQUIREMENTS

System software includes any software or firmware used to implement or support the functions required by this technical specification. It is possible that software includes certain programmable logic applications, if those applications are in fact an extension of system software (e.g. the File Agent). System software does not include programmable logic or other application implementations that represent specialized MEA-defined utility functions, as described under the Functional Requirements clause.

4.4.1 A Non-Comprehensive List of System Software

The following is a non-comprehensive list of specific functions to be implemented by system software:

1. Operating system functions.

2. High-speed SubLAN communication among IEDs using IEC 61850 communication services over Ethernet.

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3. Time synchronization functions.

4. Field data acquisition and pre-processing functions.

5. Control of primary system devices.

6. Local Repository functions.

7. ‘SCADA/EMS control center’-requested functions.

8. DNP3 communication services and functions

9. Bay- and station-level interlocking functions.

10. System log functions.

11. Configuration capabilities supporting –

IEC 61850 SCL configuration

Operator templates and procedures for setting and modifying operational parameters

Proprietary configuration of devices

Programmable logic and other applications

12. Use of programmable logic and other application functions (but not including the application code itself)

13. Generation, editing, and maintenance functions for –

Displays and reports

Programmable logic and other applications

DNP database

14. Diagnostic functions

15. Archiving and recall functions

16. File-related functions

17. Security functions

18. Use of displays

19. Use of system peripherals (e.g. monitor, printer, keyboard, mouse)

20. Any other functions associated with device or subsystem responsibilities -

CCU functions

SubLAN or CGW functions

Operator Interface [MMI] functions

TDS functions

BCU functions

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4.4.2 General Requirements

The following are general comments on MEA’s software expectations for the systems to be delivered.

4.4.2.1 Operating Systems

System software and tools for any computer system platform shall be integrated under an operating system based on Microsoft Windows XP professional™ with Thai language support and the latest service pack, either desktop-based or embedded.

An anti-virus protection program shall be selected to run on these same computer system platforms.

4.4.2.2 Software Components

The contractor shall provide a comprehensive list of the system software components to be provided. The list shall be organized by system platform (e.g. CCU, Operator Interface [MMI], BCU, TDS, CGW, Ethernet switch). The function(s) provided by each software component shall be briefly but clearly described.

The list shall be an expansion of the system software list shown above, but one that is specific to the contractor’s proposed implementation. The result shall enable MEA to understand how the system functions are defined, organized, and related, where they reside, and how they are integrated to support the system functionality required by this technical specification. MEA does not expect a detailed understanding of how the internal code for each function is designed.

4.4.2.3 Software Interfaces

The contractor shall describe how he anticipates the software components will be integrated into a system software structure that supports the requirements of this technical specification. This will require a characterization of the interfaces to be used to support interaction among the software components.

The contractor shall provide a comprehensive list of the types of software interfaces used by the system to coordinate software components. Each interface shall be described in a way that enables MEA to understand why the interface exists, which platform provides and manages the interface, how the interface works to coordinate use of software components, and other distinguishing characteristics. All software interfaces shall conform to good, mainstream engineering practices.

The final system deliverables shall include ‘as-installed’, detailed documentation that functionally describes the interfaces in more detail. The contractor shall enumerate the types of interfaces used and then list the various instances where each type is used and for what purpose it is used. This shall include a diagram showing the overall system software structure, including software components and their linkages through the individual interfaces. This shall be performed in a way that makes it easy to understand how this implementation has been partitioned among the various system platforms and devices. These diagrams and accompanying explanations shall enable MEA to understand the functional organization of the overall system software design.

4.4.2.4 Programming Languages

The software shall be written in C++ (preferred) or C, and shall include a fully-documented version control capability.

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4.4.2.5 Buffer Overflows

System software shall identify and alarm any buffer or FIFO overflows. If these occur during system operation, they represent system design deficiencies. They indicate that some aspect of system operation or loading has been underestimated. It is imperative that these kinds of problems be identifiable so that they can be fixed. The occurrence of such problems damages system reliability.

4.4.2.6 System Loading

System software shall calculate and display the percentage loading on the CCU(s). This information shall appear on the ‘Communications Status / Operational Status’ display of the Operator Interface [MMI] unit.

4.4.2.7 Unit Behavior

The software of each IED or other subsystem shall provide automatic restart of the unit upon power restoration, memory parity errors, hardware failures, manual requests, and operator requests via the network. All restarts shall be reported as time-tagged system events.

4.4.3 IEC 61850 Communications and Stack Software

IED products (e.g. protection relays, BCUs) that support IEC 61850 over Ethernet will include this software. If the contractor integrates IEDs based on PC systems (e.g. CCU, Operator Interface [MMI] units), he shall ensure this software is properly integrated and tested. This software is typically obtained from one of three principal suppliers who work closely with the electric utility industry in support of the IEC 61850 communications standard.

4.4.4 Programmable Logic Control (PLC) Software

A Windows-based, graphical programming tool, compliant with the IEC 61131-3 (Soft PLC) standard for open PLC programming languages, shall be provided for developing logic programs for the SA system. The tool shall support the IEC 61131-3 programming model, which addresses configuration, resources, tasks, programs, and functions. Simulation tools shall be provided to test and debug logic programs before they are placed into service. These tools shall be used on all Operator Interface MMI units.

The contractor shall be responsible for configuring the SA system and all logic control functions required by this specification. Refer to this topic in the Functional Requirements clause.

4.4.5 Configuration Software

Configuration software shall enable a password-authorized maintenance engineer to change the values of a variety of user-defined parameters. These user-defined parameters affect the way the system software components behave, allowing MEA to tailor system operation to its preferences. Changes shall be accomplished through procedures that use templates, dialog box prompts, and pull-down menus. All changes shall be entered into the ChangeLog (one of the system logs). The clauses that follow describe some of the various areas affected.

4.4.5.1 Operational Parameters for IEC 61850 Inform ation Models

Certain operational parameters, defined in the IEC 61850 information models, control how communication services behave. The user shall be able to change a selected group of these.

Each change shall be issued as a separate transaction, using IEC 61850 communication services to update the appropriate Proxy Server View in the Local Repository. The CCU has responsibility

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to also install them in the corresponding IED Server View and in any Proxy Client View mapped to the same information. Refer to Figures 2 and 3.

4.4.5.2 User-Defined Parameters for Individual Soft ware Components

All user-defined parameters for software components shall be handled in a like manner. In each case, the user shall use the template and procedures to locate the desired parameter and to make and save the change. Affected software functions include data acquisition, data processing, alarm management, supervisory control, display management, display generation and maintenance, programmable logic applications, others.

4.4.5.3 Report Scheduling

Using the same facilities, the user shall be able to schedule reports to run either at a preset time, or on demand (i.e. via a keyboard entry or a mouse selection). It shall be possible to schedule the reports to be printed periodically, for example every half an hour, or once a month. Alternatively, the user may schedule a report to run in response to a specific event.

4.4.5.4 Operator Permissions

Using the same facilities, the authorized maintenance engineer shall also have the capability to assign and restrict individual operator permissions for access of data, displays, alarm-processing and system controls.

4.4.6 Display / Report Generation and Editing Softw are

These software capabilities shall allow a password-authorized maintenance engineer to create, edit, or delete displays and reports. These shall include text displays and reports, one-line diagrams, graphic pictures annotated with data and text (e.g. device names, state names), or combinations. These capabilities shall be provided on Operator Interface [MMI] units. The software shall provide a user interface, a set of tools, and procedures to support this activity.

Software application and programming skills shall not be required. Wherever possible, the software shall make use of (1) pop-up dialog boxes to prompt the user for required actions and (2) pull-down menus to show available choices. Pull-down menus dramatically reduce input errors when compared with manual entry. They also inform the user about the full range of available choices.

These capabilities shall be very flexible, while maintaining consistency with certain choices made by the authorized maintenance engineer. Such choices include the selection of icons to represent different equipment and equipment states, the selection of colors to represent different states, use of flashing for unacknowledged changes, and so on.

The data in these displays and reports shall be individually linked to components in the IEC 61850-based Proxy Client Views in the Local Repository. The software shall establish Repository subscriptions for dynamic data in displays and reports, so that they are updated when the Repository is updated. Static data can be refreshed on a more infrequent basis. Refer to the clause titled ‘Browsing to Capture Repository Data Components‘.

4.4.7 DNP3 Protocol Software Implementation

The Contractor’s implementation of DNP3 protocol shall meet or exceed the requirements of “Level 2 DNP3 Implementation” as described in the most recent version of DNP3 Users Group Document. In addition, the following capabilities shall be implemented in the delivered systems.

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4.4.7.1 Binary Command Operation

The SA system shall support Control Relay Output Blocks (Object 12, Variation 1). With special emphasis: all DNP binary command operations shall be performed via Control Relay Output Blocks (Object 12, Variation 1). Use of Write (Function Code 2) for this purpose is not permitted.

4.4.7.2 Time Synchronization

‘Delay Measurement’ (Function Code 23) on ‘Time Delay Fine’ (Object 52 Variation 2) shall be supported for synchronizing SA system time with the SCADA/EMS control center, should the GPS capability fail.

4.4.7.3 Data Point Configuration

For the DNP protocol, the following shall be configured and modified on a point basis: (1) class, (2) variation, and (3) point address.

4.4.7.4 Data Class

The SA system shall support the assigning and re-assigning of data objects to classes dynamically (i.e. during run-time). An assign class (Function code 22) of all class objects shall be supported by the SA system.

4.4.7.4 Unsolicited Response

Where required for the data in Appendix E, the SA system shall support ‘Unsolicited Response’ (Function Code 130).

The SA system must accept commands from the SCADA/EMS control center in order to enable and disable unsolicited responses by event class (using object headers with group number 60) even if the device does not have class 1, 2 or 3 data when the request arrives.

The SA system shall support end-use configuration of at least following parameters:

• Destination address of the master • Unsolicited response mode (either “ON” or “OFF”)

• Timeout period for unsolicited response confirmation

• Number of unsolicited retries

Regardless of the cause, when the SA system is reset or restarted, all of its points must be disabled form initiating unsolicited responses. The SA system shall not report unsolicited events until its points are explicitly enabled by a request from the master, and then only data from the enabled points are permitted to be included in the response.

When the SA system receives a function code DISABLE_UNSOLICITED request to disable initiation of unsolicited responses from points identified by the object headers in the request, it must no longer transmit any data via an unsolicited response for those points. The request also cancels any pending expectation of confirmation for an unsolicited response that has already been sent from the outstation, but for which confirmation has not yet been received.

The SA system must not lose or discard event data as a result of receiving the DISABLE_UNSOLICITED function code; the SA system must report events if they are requested in a master poll for those points that were disabled from reporting in unsolicited responses.

The response to enable unsolicited and disable unsolicited requests are null responses.

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4.4.8 Protocol Analyzer Software

The contractor shall provide test set software for DNP3 protocol and the IEC 61850 communications architecture. The test set software is for testing and monitoring system communications capabilities, enabling the user to diagnose problems and maintain the system. All necessary interfaces and facilities (e.g. cables, connectors) shall be provided for use on both notebook and desktop PC platforms.

The DNP3 protocol analyzer software shall be capable of emulating both master and slave and supporting DNP Levels 2 and 3. The software shall be capable of listening to both the master and slave concurrently. Operation over a serial port or Ethernet / IP shall be supported. The software shall support multiple frame message processing and the full range of objects, variations, function codes, and application service data units (ASDUs).

In support of the IEC 61850 communications architecture, the analyzer shall include stack and related communications software that enable the unit to sit on the network and act as an initiating or receiving network node. The user shall be able to set the network address and data link address as MAC address, enabling the unit to operate in lieu of a system node taken off-line. The analyzer shall be able to record and analyze traffic at any of the various stack levels of various nodes in the same time, particularly at the applications level. Application data shall be appropriately presented as text and numbers, so that the user can interpret results in a manner consistent with use of the information models. Similarly, the user shall be able to set up a message with a template and issue it to another designated node in client-server mode. Alternatively, the analyzer shall be able to broadcast messages in GOOSE mode. All control block capabilities and communication services shall be supported.

The protocol analyzer software shall provide dynamic data display during monitoring and ‘simulation mode’ test sessions(e.g Master, Slave). It shall be capable of continuously monitoring communications without interfering with normal operation. The message data shall be displayed in a format that can be easily interpreted by the user and also can be displayed in the raw format if the user request. Selection of number base (e.g. decimal, hexadecimal, octal and binary) shall be also available. The protocol analyzer software shall allow the user to store all data resulting from communication tests into memory (e.g. disk, flash) for subsequent analysis.

4.4.9 Demo Software and Literature

Wherever possible, the contractor’s bid shall include demo software and literature for the software functions described by this technical specification.

4.5 SYSTEM TESTING REQUIREMENTS

System testing shall ensure that the proposed system components and system-at-large are suitable for continuous service in an electric power substation environment.

If this technical specification fails to identify the required class (i.e. level) of compliance for any issue of testing, the contractor shall submit a recommendation and request MEA’s approval.

4.5.1 Testing Categories

The following are the specific categories of tests that need to be passed during the course of the project:

1. Type Testing

Certificates shall be submitted for successful type-testing of proposed equipment for electromagnetic compatibility, environmental requirements, interface requirements, and other miscellaneous requirements. These tests are specified by standards IEC 60870-2-

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1, IEC 60870-2-2, IEC 61850-3, IEEE C37.1-1994, IEEE C37.90.1-2002, and IEEE C37.90.2-2004.

Type-testing shall be performed by internationally accredited testing laboratories that are independent of the bidder and equipment manufacturers. Tests performed by an in-house laboratory are not acceptable.

All test reports shall be submitted to MEA within 180 (one hundred and eighty) days after the Effective Date of Contract. The detailed testing facilities and procedures, including schematic diagrams and photographs, if any, shall also be included.

The type-testing must be performed on the same equipment models and configurations as proposed for the SA systems.

Refer to the ‘Compatibility Test Criteria (for Type-Testing)’ heading.

2. IEC 61850 Certification

Test certification shall be submitted for all proposed IEDs, configuration tools, and test tools used to fulfill IEC 61850 communication requirements. The certificates shall confirm compliance with mandatory aspects of the standard and any non-mandatory aspects claimed by the manufacturer.

3. DNP3 Certification

A DNP3 Level 2 conformance certificate is required. Beyond that, the contractor shall demonstrate the successful implementation of additional Level 3 capabilities required for implementation of the delivered systems.

4. Factory Acceptance Testing

The contractor shall conduct a Factory Acceptance Test that is interactively witnessed and critiqued by selected MEA personnel and/or MEA’s agent. The test objectives, upon which a subsequent test plan shall be based, shall be recommended by MEA or its agent, reviewed by the contractor, and finally approved by MEA. Thereafter, the contractor shall submit a test plan with supporting procedures for MEA’s approval. These tests shall be conducted at the contractor’s facilities, before delivery of any portions of the system. Exceptions must be approved by MEA in writing. The approved test objectives and test plan shall be included in the Work Statement, following award of contract and adequate review of the technical proposal.

The test objectives and test plan shall include integration issues (e.g. interfaces), functional issues, and performance issues. In general, compliance issues shall not be included where type-testing or other certification has addressed those issues, unless a reason arises to doubt their validity.

The Factory Acceptance Test shall use sufficient equipment to reasonably represent actual system behavior at site. Circuit breaker simulators, Doble (or equivalent) PT and CT simulators, and monitoring equipment shall be included to support visual confirmation of test results. The contractor shall submit in writing his rationale as to how the proposed, integrated system test plan and set-up fulfills the test objectives.

MEA, its agent, and the contractor shall note variances as testing proceeds. Descriptions of these variances shall be entered into a Test Log kept by MEA and shared with the contractor. The contractor shall respond to each variance in writing, detailing the problem and the specific, proposed solution. These responses shall be submitted to MEA for review and approval before the proposed solutions are implemented by the contractor.

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5. Site Testing

Site testing shall be performed at each site to ensure the installed and configured system-at-large and individual components perform as intended. With the problems identified during the Factory Acceptance Test already resolved, test objectives at this stage shall focus on verification of complete-system functionality and performance. The test objectives shall be proposed by MEA or its agent, reviewed by the contractor, approved by MEA or its agent, and specified in the Work Statement. The contractor shall submit a site test plan with supporting procedures for MEA’s approval, and this, too, shall be included in the Work Statement. Both functional and performance testing shall be included. The successful testing of each aspect of system behavior shall be witnessed by MEA personnel and/or their agent. Testing at each site shall be concluded with a successful 100-hour test (i.e. no failures and no discrepancies). The Test Log procedures used during Factory Acceptance Testing shall be used here as well. Finally, each system shall be commissioned and placed into service. As part of the contract, the contractor shall successfully and expediently resolve any problems that arise during the first six months of station service.

MEA’s failure to detect or recognize a problem during Factory Acceptance Testing, Site Testing, or at any other time shall not release the contractor from the responsibility of (1) correcting problems that are eventually recognized or of (2) producing and delivering reliable systems that perform in the manner intended by these specifications. The contractor shall assist MEA and its agent with ‘tightening’ these technical specifications where necessary.

4.5.2 System Performance Testing Requirements

As mentioned above, Factory Acceptance Testing and Site Testing both involve performance testing. The working assumption is that the system has already passed the prescribed functional tests. Performance tests shall determine whether timing specifications are met.

The proposed system shall comply with the performance requirements stated below. In preparation, the contractor shall present calculations and/or other credible evidence to support his contention that the integrated system is designed to perform its responsibilities (under all circumstances) within the timing requirements stated in this technical specification. Processing speed, memory resources (all applicable types), communications bandwidth, system latencies, and I/O bandwidth, and avoidance of resource bottlenecks shall be among the factors considered. To demonstrate this compliance during performance testing, loading on processors, LANs, and communication interfaces, and other system components shall be simulated for the ultimate system configuration.

If upgrades to the system are required as the result of performance testing, the contractor shall bear all costs to replace system components and/or materials and to integrate and test them to meet the requirements of this technical specification.

The following system activities are postulated for system performance testing. These concurrent system activities intend to represent composite system behavior during an exceptionally busy interval of time. The system is expected to run without interruption and to successfully complete all activities while the test is in progress. Performance testing shall be run for a minimum of five continuous minutes:

1. The system is processing the ultimate number of status, analog, and counter data, as determined from point data in the attached appendices for the individual stations to be delivered.

2. All calculated analog points are processed for the ultimate number of points, whenever data for the Local Repository is received from IEDs.

3. The system performs historical data processing per the stated requirements and prescribed frequencies.

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4. The system communicates and interacts with the SCADA/EMS control center at the prescribed polling rates.

5. All hourly and other periodic processing of data functions is performed on schedule.

6. The MMI is logged on and its displays are updated at the required rates.

7. The MMI is in either the Operator or Supervisor Mode. The monitor of the MMI is shows the station one-line diagram used during Factory Acceptance Testing.

8. Ten (10) new status alarms and four (3) new analog alarms are processed every ten (10) seconds. The alarms shall be uniformly distributed among different IEDs.

9. At least twenty-five percent (25%) of all analog points being monitored change during any update cycle and these changed values are processed for updating the Local Repository.

10. Programmable logic applications are executed at rates that are representative of their functional responsibilities and the system’s expected, typical behavior.

11. The Operator Interface [MMI] keeps its displays up to date within the prescribed update times and the operator acknowledges outstanding alarms as quickly as possible.

4.5.3 Compatibility Test Criteria (for Type-Testing )

The following tables summarize the Compatibility Test Criteria for equipment delivered under this technical specification:

Table 7: Environmental, Shock, & Vibration Compatibility Req uirements

These test requirements apply to all equipment delivered for the SA system. The temperature and humidity requirements specify the operating ranges for equipment.

These requirements have been selected using IEC 60870-2-1 and IEEE C37.1 as guides. They and any referenced base standards shall be used to perform type-testing on the equipment under test.

Table 8: Insulation Withstand Requirements

These test requirements apply to all wiring and cables entering and exiting equipment enclosures. For equipment to pass these tests, no equipment damage must occur as a result of these tests. Tests shall be performed on de-energized equipment.

These requirements have been selected using IEC 60870-2-1, IEC 60870-2-2, IEC 60870-3, IEC 60255-5 and IEEE C37.1 as guides. They and any referenced base standards shall be used to perform type-testing on the equipment under test.

Table 9: EMC Immunity & Emission Requirements

These test requirements selectively apply to equipment delivered for the SA system. The table includes columns that indicate which tests are applicable to each type of equipment. Any equipment not classified as a power unit or as telecom equipment is assigned to the ‘control & signal’ category.

For equipment to pass the immunity tests, no improper operation of the equipment shall occur while the tests are in progress. Tests shall be performed on energized equipment.

These requirements have been selected using IEC 60870-2-1 and IEEE C37.1 as guides. They and any referenced base standards shall be used to perform type-testing on the equipment under test.

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Table 7: Environmental, Shock, & Vibration Compatib ility Requirements

Equipment Applicability

Test Class Description Applicable Standard

Severity Level or Class Comments Telecom

Control & Signal

DC Power

AC Power

Operating temperature IEC 60068-2-2 ----

0 to 55oC, 20oC/hr, 96 hrs (indoors)

0 to 70oC, 30oC/hr, 96 hrs (outdoors)

x x x x

----

40oC, 5 to 95%, 10 days (indoors)

40oC, 0 to 100%, 10 days (outdoors)

x x x x

Climatic

Relative humidity IEC 60068-2-3

---- 25oC to 55oC at 95% RH (indoors); six-cycle test x x x x

Shock response & withstand

IEC 60255-21-2 IEC 60068-2-27 IEC 60068-2-29

1 x x x x Shock & Vibration

Mechanical vibration IEC 60255-21-1

IEC 60068-2-6

1 To be performed on complete assemblies; performance checks during test.

x x x x

Table 8: Insulation Withstand Tests (No damage permitted to pass; performed on de-energized equipment)




Control & Signal

DC

Power AC Power

Insulation resistance IEC 60870-3 (Table 7)

----

Insulation resistance to earth > 1 MΩ at 500 Vdc

x x x x

---- Inputs with direct connection to items of substation equipment: Shall withstand 2kVrms to earth for 60s.

x x x x

Dielectric

Hi-pot IEC 60060

---- Across open relay contact circuits: Shall withstand 1kVrms to earth for 60s.

x x x x

Common-mode IEC 60060 ---- 2kV test voltage (1.2/50us waveform; 0.5J) x x x x Impulse

Differential mode IEC 60060 ---- 1kV test voltage (1.2/50us waveform; 0.5J) x x x x

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Table 9: EMC Immunity & Emission Tests [2 sheets]

(To pass immunity tests, no improper operation is permitted)




Control & Signal

DC Power

AC Power

Harmonics

(Test A.1.1) IEC 61000-4-1 2 x

Inter-harmonics (Test A.1.2)

IEC 61000-4-1 2 x

Signaling voltage (Test A.1.3)

IEC 61000-4-16 4 x

Voltage fluctuations (Test A.1.4)

IEC 61000-4-11

IEC 61000-3-3

2 x x

IEC 61000-4-11 2 x

Low Freq Disturbance Immunity

Voltage dips & short interruptions (Test A.1.5) IEC 61000-3-3 2 x

Voltage & current surges:

100/1300us (Test A.2.1)

IEC 61000-4-1 ---- Either the IEC or IEEE test may be performed; compliance with both is preferred.

x x

Surge immunity: 1.2/50us voltage & 8/20us current (Test A.2.2)

IEC 61000-4-5 4 4kV open circuit test voltage / short circuit current x x x

Fast transient bursts (Test A.2.3)

IEC 61000-4-4 or IEEE C37.90.1

4

----

x x x x

Damped oscillatory waves (Test A.2.5)

IEC 61000-4-12 or IEEE C37.90.1

3 ----

Either the IEC or IEEE test may be performed; compliance with both is preferred.

x x x x

Conducted Transient & High-Freq Disturbance Immunity

Surge immunity: 10/700us voltage (Test A.2.8)

IEC 61000-4-5 4 x

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Control & Signal

DC Power

AC Power

ESD Immunity

Electrostatic discharges (Test A.3.1)

IEC 61000-4-2 3 6kV test voltage for contact discharge tests; 8kV for air discharge tests

x x x x

Radiated E/M field

disturbance (Test A.5.1) IEC 61000-4-3 4 Field strength of 10V/m over freq range 80 to 1000MHz

(80% AM; 1kHz) x x x x

Power frequency magnetic field (Test A.4.1)

IEC 61000-4-8 5 100 A/m continuous; 1000 A/m for 3s pulse

x x x x

Magnetic and E/M Field Immunity

Damped oscillatory magnetic fields (Test A.4.3)

IEC 61000-4-10 4 x x x x

50Hz interference IEC 61000-4-16 ---- Tests immunity to power freq voltage interference on

control & signal lines.

Common-mode test: 500Vrms for 2s Differential-mode test: 250Vrms for 2s

x x Other Immunity Tests

DC voltage on control and signal lines

IEC 61000-4-16 ---- x

RF disturbance voltages CISPR 22 A x x

RF disturbance currents CISPR 22 A x

Conducted interference voltage

CISPR 22 A Freq range: 150kHz to 30MHz x x x x

Interference field strength CISPR 22 A Freq range: 30MHz to 1000MHz x x x x

Harmonic currents

IEC 61000-3-2 ---- Limits for harmonic current emissions in equipment with rated current < 16A. Measurements up to 40th harmonic.

x

Voltage fluctuations IEC 61000-3-3 ---- Limits for voltage fluctuations and flicker in equipment with low-voltage supply systems with rated current < 16A.

x

EMC Emissions

Low freq disturbance voltages

CCITT Rec. P.53 ---- Psophometric measurements (DC to 4kHz) x

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5 TRAINING and SYSTEM MOCK-UP

5.1 Training System

At least three months prior to Factory Acceptance Testing, the contractor shall deliver and install a hands-on training system at a facility specified by MEA. The purposes are three-fold:

1. To provide a means for MEA personnel to become familiar with individual system components (e.g. wired connections, layout, installation characteristics, configuration, operational controls, maintenance features, HMI, use of client software, and so on.

2. To provide hands-on reinforcement of training material during the presentation of courses by the contractor or his suppliers.

3. To provide a means for MEA personnel to become familiar with operation and maintenance of the integrated system and to validate system operations.

4. To serve as a test-bed for MEA engineering personnel to address operational, maintenance, or technical issues that affect use of the systems to be delivered.

The initially-provided training system need only provide a representative configuration, having the same operational characteristics but not necessarily the exact data specified for the delivered systems. This shall suffice for familiarization and training purposes. As the delivered systems become better defined, the training system shall be progressively updated to reflect the capabilities of the systems to be delivered. These improvements will facilitate objectives 3 and 4.

The training system shall include the following equipment:

1. Substation LAN (2 ea) and Ethernet switches: Interconnected with the training system IEDs via fiber optic cable.

2. GPS connection: All necessary parts to deliver the signal.

3. CCU IEDs (2 ea): One primary and one standby

4. Operator Interface [MMI] IED (1 ea): Terminal Station version

5. TDS IED (1 ea)

6. BCUs, Protection Relays (IEDs): Sufficient modules to support all point types and IEC 61850 Logical Nodes to be used.

These need to be supplemented with simulator panels providing status and counter inputs; these shall support both manually-initiated inputs and automatic toggling and counting. CT and PT inputs shall be provided by MEA via a Doble or equivalent test unit.

7. CGW IED (1 ea)

8. Power converters, fusing, and power distribution: As necessary to safely support the above equipment. To be supplied from conventional 220, 50 Hz wall sockets.

9. Simulator devices for circuit breakers, OLTC controls, reclosers, and any other controlled equipment: Simulator devices shall provide control and status indicators. Other display and control panels shall be provided as needed to interpret system behavior. The training system shall not be connected to any real primary system equipment.

10. ABB Combitest or AREVA or SIEMENS or equivalent test switch blocks for isolation and testing of Protection relays within the system allow rack space for mounting these.

11. Open relay racks to support 19” rack mounting at convenient heights and trays to support cable and wiring interconnections.

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5.2 Training Courses

The contractor shall recommend a menu of training courses for the purpose of preparing MEA personnel to configure, operate, program, and maintain the delivered systems. It is understood that MEA shall have no programming or configuration responsibilities for the systems under contract, but they may well need these skills after system deliveries.

MEA and the contractor shall come to agreement in the Work Statement regarding which courses shall be presented prior to the Factory Acceptance Tests, so that MEA has a solid foundation for witnessing and evaluating the structure and results of tests.

6 Simulation Test Tool and Multifunction Primary Te st Set

The contractor shall provide Simulation Test Tool and Multifunction Primary Test Set for Substation Automation Systems as specified in Appendix F for testing all IEDs (Protection Relays and BCUs) according to the IEC 61850 communications standard and IEC 60870-5-103 companion standard for the informative interface protection equipment. Training shall be also provided.