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 Functional Design Specification – Substation Automation System

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REVISION TABLE

Rev. No Revision Note Approved Week

00 Original Document MVG 35/2009
01 Revised as per customer MVG 42/2009
comments
02 Revised as per customer MVG 45/2009
comments

NTECL
NTECL DOC.No. : 0260-573-PVE-M-093

We reserve all rights in this document and in the information contained therein. Reproduction, use or disclosure to third parties
without express authority is strictly forbidden. Copyright © by ABB Limited

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 Functional Design Specification – Substation Automation System

Table of Contents:

1 About This Document.......................................................................................... 6

1.1 General ................................................................................................. 6

1.2 General requirements ........................................................................... 6

1.3 Abbreviations ........................................................................................ 6

2 Introduction ......................................................................................................... 8

3 System Design .................................................................................................... 9

3.1 System Architecture............................................................................ 10

3.1.1 Station Level ....................................................................................... 10

3.2 Bay Level Functions ........................................................................... 11

3.2.1 Interlock Functions.............................................................................. 13

4 System Description ........................................................................................... 14

4.1.1 GOOSE............................................................................................... 14

4.1.2 Bay level human machine interface (IHMI or LHMI) ........................... 15

4.1.3 Tripping logic and Trip Matrix Logic (PTRC, 94) ................................. 16

4.1.4 Disturbance Evaluation Software PCM 600 ........................................ 17

4.1.4.1 IED 670 Hardware Structure 18

4.1.4.2 Supervision of mA input signals (MMXU) 19

4.2 Station Level Functions....................................................................... 19

4.2.1 Redundant Application server (Main/standby controllers) and Station

HMI (Operating work stations)........................................................................... 20

4.2.2 Master Metering Station...................................................................... 20

4.2.3 Communication Infrastructure............................................................. 21

4.2.4 Time Synchronization ......................................................................... 21

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4.2.5 Engineering Workstation and Fault Recorder station.......................... 21

4.2.6 Remote Control Gateway.................................................................... 22

4.3 Operator Interface functions ............................................................... 22

4.3.1 User login............................................................................................ 23

4.3.2 Logout................................................................................................. 23

4.3.2.1 Time based logout: 24

4.3.3 Application Settings ............................................................................ 24

4.3.4 User Management .............................................................................. 25

4.3.5 Process Display .................................................................................. 26

4.3.5.1 Display Builder 28

4.3.6 Control dialogs.................................................................................... 28

4.3.6.1 Station Local/Remote control 28

4.3.6.2 Bay Local/Remote control 29

4.3.6.3 Switch control 30

4.3.7 Event List ............................................................................................ 32

4.3.7.1 Features of Event List 33

4.3.8 Alarm List............................................................................................ 35

4.3.8.1 Features of Alarm List 36

4.3.8.2 Alarm acknowledgement 37

4.3.8.3 Alarm blocking 37

4.3.8.4 Alarm classes 38

4.3.8.5 Alarm List presentation modes 38

4.3.9 Blocking List........................................................................................ 38

4.3.10 Measurement Reports ........................................................................ 39

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4.3.11 Trend Application................................................................................ 41

4.3.11.1 Features of Trend application 43

4.3.11.2 Trend Basket 44

4.3.12 System Self Supervision ..................................................................... 44

Table of Figures:
Figure 1: Goose (Peer to peer) Communication....................................................... 15

Figure 2 : Bay Level HMI and Functionality keys .................................................... 16

Figure 3: Disturbance Evaluation Software PCM 600 .............................................. 17

Figure 4: Monitor Pro Login dialog * ......................................................................... 23

Figure 5: Application setting dialog * ........................................................................ 25

Figure 6: Example of Authorization profile................................................................ 26

Figure 7: 400 kV SLD (typical)* ................................................................................ 27

Figure 8 : Station Local / Remote control dialog * .................................................... 29

Figure 9 : Bay Local / Remote control dialog * ......................................................... 30

Figure 10 : Switch control dialog (Select Before Operate) * ..................................... 31

Figure 11 : Switch control dialog (expanded)*.......................................................... 32

Figure 12 : Event List * ............................................................................................. 33

Figure 13 : Event list settings ................................................................................... 34

Figure 14 : Event list filter settings* .......................................................................... 35

Figure 15 : Alarm List (Template 1)* ........................................................................ 36

Figure 16 : Alarm List (Template 2)* ........................................................................ 36

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Figure 17 : Alarm list settings*.................................................................................. 37

Figure 18 : Blocking List*.......................................................................................... 39

Figure 19: Measurement Reports (Tabular Form).................................................... 40

Figure 20: Measurement Reports (Graphical form).................................................. 41

Figure 21 : Trend picture (Graphical form)*.............................................................. 42

Figure 22 : Trend picture (Tabular form)* ................................................................. 43

Figure 23 : Trend basket*......................................................................................... 44

Figure 24 : Example of System Supervision picture*................................................ 45

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1 About This Document

1.1 General

This document details the Substation automation system (SAS) functionality for NTECL
400kV GIS Switchyard & Unit Protection.

The SAS is designed considering the functional requirements of Technical Specification E11,
SAS Configuration diagram, Control& protection Schemes as applicable for the project and
brochures of ABB equipment & IED’s.

Reference is made to relevant portions of the following documents:

… Technical Specifications Part II, Section VI CS-3530-573-2 E11

… Configuration Diagram . 0260-573-PVE-B-089-01

… Configuration Diagram :YN1M301338-CZM

(Project specific document submitted by ABB)

… Control & Protection Schemes as applicable for the project

… Catalogues and Technical Reference Manuals of IEDs and MicroSCADA.

1.2 General requirements

The SAS provides facility to monitor the complete 400kV GIS Protections, Control &
Synchronization of the Bay equipments & Metering (Via interfacing from the Energy metering
Master Station) from Switchyard Control Room as well as from Central control room. Main
Plant Operator workstation will be interfaced to the LAN at the Main plant control end. In
addition the SAS system also provide Gateways on IEC 60870-5-101 (Slave) protocol for
interfacing to Load Dispatch Centre and OPC connectivity for interfacing to Main plant
SCADA (DCS) respectively. Gateway for NTPC OS is also envisaged. SAS also uses an
Engineering work station for configuration, parameterization and disturbance evaluation of
IED’s.

The software or hardware described in this document is furnished under a license and may be
used, copied or disclosed only in accordance with the terms of such license.

1.3 Abbreviations

The following abbreviations are used in the document.

SAS – Substation Automation System

IED – Intelligent Electronic Device
HMI – Human Machine Interface
PC – Personal Computer

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LAN – Local Area Network

DR – Disturbance Recorder
DMP – Dot Matrix Printer
SCADA – Supervisory Control and Data Acquisition System
RCC – Remote Control Centre
RLDC-Regional Load Dispatch Centre
LN – Logical Node
BCU – Bay Control Unit
GOOSE – Generic Object Oriented Substation Events
SNMP – Simple Network Management Protocol
SNTP – Simple Network Time Protocol
SLD – Single Line Diagram

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2 Introduction

The SAS is based on ABB make MicroSCADA Pro software running in a redundant
hot standby mode on two industrial PCs(network controllers) with Microsoft Windows
2003 Server Operating System.

The SAS confirms to IEC61850 standards and has a decentralized architecture

consisting of the following main functional parts:

At Switchyard Control Room:

Redundant (Main/standby) application servers.

Dual Human Machine Interface (HMI) (Operator work stations)

One Engineering Work Station – cum – DR Evaluation PC

One Metering Master Station to which all the energy meters are networked on
MODBUS

Intelligent Electronic Devices (IED) for bay control and monitoring

Intelligent Electronic Devices (IED’s) for bay and station protection (SCR& CCR)

Managed switched fibre-optic Ethernet LAN in fault tolerant ring architecture to

ensure highest availability (SCR & CCR)

Gateway for remote communication on IEC 60870-5-101 protocol to RLDC with

suitable modems for interface with PLCC

Four Modems for interfacing with PLCC

Gateway for remote communication to NTPC OS on OPC connectivity

Dot Matrix printer for alarms and events

A3 and A4 size Network printers for graphics and reports

GPS Receiver

Laptop (Configuration and parameterization)

Rear Projection mimic display unit (Located at the 400kV switchyard Control room)

At Central Control Room:

Operator Work stations for CCR

Engineering and Disturbance Recorder Station (one in CCR and one each for
Common engineering rooms CER-1,2,3)

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Laptop (Configuration and parameterization)

GPS Receiver

A3 size Network printer

Gateways for remote communication to Main Plant SCADA (DCS) on OPC

Connectivity

At each Common
Common Engineering Room:

One Engineering Work Station – cum – DR Evaluation PC

One A4 colour laser printer for graphics and reports printing

GPS Receiver to time synchronize the SAS components including the IEDs

The SAS provides an extensive range of Supervisory Control and Data Acquisition (SCADA)
functions.

3 System Design

The SAS is designed considering the functional requirements of NTPC’s Technical

Specification CS-3530-573-2, along with the pre-bid clarifications and the deviations taken
during bidding stage. The relevant sections of NTPC specification are:

Chapter – E11 – section 9.02.00 Bay Protection units

Chapter –E11 - Substation Automation System (SAS) for 400kV Switchyard at Vallur
TPP

The SAS is suitable for operation and monitoring of the complete substation including future
extensions as given in technical specification chapter E11.

The control hierarchy and control levels of the SAS shall be based on the logical structure of
the SAS, shown below

Control level 3 Remote control centre (RCC)

Control level 2 Substation level (HMI)

Control level 1 Bay control Units

Control level 0 Switch gear equipment

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The SAS supports remote monitoring of the Substation from two Remote Control Centres
(One for RLDC, one for OS control room – Communication between Control Llevel 3 and
Control Level 2) .The interface ports for communication with RLDC shall be with V24/V28
standard using IEC 60870-5-101(Slave) protocol and for NTPC OS control room on OPC
connectivity. The lower control level has the highest priority.

The SAS also supports remote control and monitoring from the Main Plant SCADA
(Communication between Control level 2 and Main Plant SCADA) on OPC protocol. In
addition, the offered system envisages integration of status and analog signals (MW, MVAR,
Generator voltage, GTCB and associated Isolator /Earth switch status) from Owner’s OPC
compliant DCS to SAS.

The data exchange between Control level 2 (Station level HMI) and the Control level 1 (Bay
Control and Protection units) shall be based on IEC 61850-communication standard.

Data exchange between Control level 1 (Bay control and Protection units) and control level 0
(Switchgear equipment and Plant) will be through hardwired connections.

The SAS comprises full station and bay protection as well as control, monitoring and
communication functions and provides all functions required for the safe and reliable
operation of the 400 kV GIS at Vallur TPP.

3.1 System Architecture

For safety and availability reasons the SAS is based on a decentralized architecture and on a
concept of bay-oriented, distributed intelligence. Functions are decentralized, object-oriented
and located as close to the process as possible.

The SAS layout is structured in two levels:

Station Level and

Bay Level.

Please refer SAS Architecture diagram (ABB Doc No: YN1M301338-CZM)

3.1.1 Station Level

A redundant PC based HMI (Main/standby / Operator work station) enables local station
control through the software package MicroSCADA Pro, which contains an extensive range of
SCADA functions.

The operator workstation HMI depicts the complete 400kV GIS real time graphic mimic
diagram.

Within the SAS it is possible to work from both Operator workstations at any point of time and
with the failure of Main controller the operations can be monitored from the Standby
Controller.

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At the station level the SAS provide communication gateways for remote interface to RLDC
and NTPC OS. This gateway for RLDC will be through interface ports using V24/V28
communication standard (ITU-T standard, formerly CCITT standard) and will interface with
the Modem (ABB make NSK5 modem) suitable for use with the PLCC.

The Substation LAN is extended to the Central control room through fibre optic
communication equipment. The SAS also provides gateway on OPC Connectivity for Main
plant DCS interface.

Within the SAS, inter bay bus provides independent station-to-bay and bay-to-bay data
exchange.

The system can be extended both physically and functionally without affecting the original
application. It has a unique user-friendly definition language (SCIL) that facilitates integration
of the system by the users themselves, without detailed knowledge of real-time systems.

An authorization mechanism prevents system access to unauthorized users and allows

assignment of a number of authorization levels. This makes certain functions accessible only
to those users who have the required level of authorization.

All alarm and event logs will be printed out on the DMP printer. The reports and graphics will
be printed on the Colour Laser printer connected to the system over the Ethernet LAN.

A dedicated GPS master clock is provided for the synchronization of the entire system in SCR
and CCR. This master clock is independent of the station computers and gateways, and it
synchronizes all devices via inter bay bus using SNTP protocol as defined by the IEC 61850
standards.

3.2 Bay Level Functions

The Bay Level Control, Monitoring and Protection functions are achieved by a suite
of advanced range of IED670 series fully compliant to the IEC61850 standard. The
IEDs used for various applications are as under:

o Bay Control, Monitoring & Measurements IED REC670

o Line Protection (Full Distance Scheme) IED REL670

o Line Protection IED Reputed make.

o Transformer Protection IED RET670

o Backup Protection IED REL670RET670

o Bus Bar Protection IED REB670

o Generator Protection IED REG670

As per specification requirement, main – II protection relays for line are offered of a
different make and hardware platform in relay type 7SA522 of Siemens make. For

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generator protection, the protection function redundancy is achieved with Generator

protection relay type 7UM622 of Siemens make.

A basic overview of IED670 hardware and functionality is as below.

The offered IEDs are of single closed casing with sizes of ½, ¾, 1/1 of 19” and with
flush mounting arrangement. The basic hardware comprises of a built-in graphical
MIMIC display (HMI and basic modules comprising of main processing module
(CPU), analog digital conversion module (ADM), power supply module (PSM) and
application specific modules viz. transformer input modules (TRM) for acquisition of
the field current and voltage inputs in combination of 6I+6U, 9I+3U,6I or 12I as per
the scheme requirement, binary input/output modules (IOM) as per scheme
requirement. The IEDs are built-in with large monochrome graphical LCD MIMIC
display for controllers and small display units for protection relays. The HMI on the
BCU has the ability to show graphical switchgear arrangement, status information,
measurements, and disturbances (last 100 reports with scrolling function)

The details if the functionality keys on the IED are as below:

… E Enters into editing mode or executes a command

… C Cancels a command or an action

… Help Brings up the help screen

… Up/Down arrow keys Navigate between objects on same page and digits

… Left/Right arrow keys Navigate between screens and digits

… Menu Cycles between main menu screen and control screen

… I (Close key) Starts action of closing an apparatus

… O (Open key) Starts action of opening an apparatus

… Reset Brings up reset screen

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… L/R Local / Remote switch

The IEDs are equipped with three status LEDs situated above the LCD screen with the
following indications.

The IEDs are also equipped with 15 freely configurable indication LEDs (6 red and 9
yellow). Both status and indication LEDs can be acknowledged / reset. The
configuration of the indication LEDs are indicated in the respective schematic
drawings.

The local HMI has a menu structure in the order of measurements, events,
disturbance records, settings, configuration, diagnostics, test and language. These
menus are accessible by pressing the menu key and then the navigation keys.

Screens are accessible by operating the respective keys on the IED for menu, help
and reset. The control screen is set as default in the IEDs. The details about the
navigation and handling the control, indication, disturbances and events from the HMI
is specified in detail in the operation and maintenance manual.

3.2.1 Interlock Functions

The interlocking function blocks the possibility to operate primary switching

devices, for instance to prevent isolator closing when an Earth switch is
closed, in order to prevent material damage and/or accidental human injury.
The BCU (REC670) provided for control has interlocking modules for various
switchyard arrangements. Each BCU handles interlocking of all equipments
pertaining to that bay. The bay level interlocks are distributed to each IED and
is not dependent on any central function.

For the station-wide interlocking, the IEDs communicate via the system-wide
interbay bus (IEC 61850-8-1) or by using hard wired binary inputs/outputs.
The interlocking conditions depend on the circuit configuration and apparatus

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position status at any given time. For instance to realize the Bus Earth switch
interlock, the status of Bus isolators information are passed on GOOSE.

4 System Description

The bay level functions provided for the 400kV system is as shown in the relevant control &
protection schematic drawings (trip logics)

Bay Ethernet switches are provided in each BCU panel, each Bay BPU panel and Generator
protection panels of each unit. The connection from each IED to the switch is by a single fibre
optic link. The switches are connected in a fault tolerant ring topology. At the station level, to
provide communication redundancy, Ethernet switches are used to connect the redundant
HMI and other station level equipment.

In a decentralized architecture the functionality are provided as close to the process as

possible. In this respect, the following functions are allocated at bay level:

Bay control and monitoring functions

Bay protection functions

A process bus is not used and the connections from the bay level to the process are
hardwired. The details of the functions provided for the individual bays and at the station level
are described below.

The bay level functions for each of the feeders and the protection function distribution within
the IEDs are detailed in the protection single line diagram/trip logics.

4.1.1 GOOSE

GOOSE is an acronym for Generic Object Orientated System-wide Events. It aims to replace
the conventional hardwired logic necessary for intra-IED coordination with station bus
communications

It is a mechanism for the fast transmission of substation events, such as commands, alarms,
indications, as messages.

A GOOSE message sent by one IED can be received and used by several other IEDs

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Figure 1: Goose (Peer to peer) Communication

4.1.2 Bay
Ba y level human machine interface (IHMI or LHMI)
LHMI)

The local human machine interface or integrated human machine interface is equipped with
an LCD that can display the single line diagram with up to 9 objects. The local human-
machine interface is simple and easy to understand – the whole front plate is divided into
zones, each of them with a well-defined functionality:

Status indication LEDs

Alarm indication LEDs consisting of 6 red LEDs and 9 yellow LEDs with user printable
sticker. All LEDs are configurable from the PCM600 tool.

Liquid crystal display (LCD)

Keypad with push buttons for control and navigation purposes, switch for selection
between local and remote control, reset and an isolated RJ-45 communication port

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Figure 2 : Bay Level HMI and Functionality keys

4.1.3 Tripping logic and Trip Matrix Logic (PTRC, 94)

A function block for protection tripping is provided for each circuit breaker involved in the
tripping of the fault. It provides the pulse prolongation to ensure a trip pulse of sufficient
length, as well as all functionality necessary for correct co-operation with auto reclosing
functions. The trip function block includes functionality for evolving faults and breaker lock-
out.

The output pulse from the protection function block may be short which may not be sufficient
enough for the trip coil to energise. Hence, all the protection outputs are connected to the
PTRC block thereby extending the pulse duration ensuring correct operation of all functions.
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Twelve trip matrix logic blocks are included in the IED. The function blocks are used in the
configuration of the IED to route trip signals and/or other logical output signals to the different
output relays. The matrix and the physical outputs will be seen in the PCM600 engineering
tool and this allows the user to adapt the signals to the physical tripping outputs according to
the specific application needs.

A high number of logic blocks and timers are available to adapt the configuration to the
specific application needs.

4.1.4 Disturbance Evaluation Software PCM 600

Protection and Control IED Manager PCM 600 is an easy-to-handle tool providing versatile
functionalities required throughout the life cycle of ABB's protection and control IEDs in
transmission and distribution applications. Its Microsoft Windows based user interface with
many familiar and easy-to-use functions adds to operating comfort. PCM 600 features fast
and reliable downloading and uploading of configuration and settings as well as uploading of
disturbance files both locally and remotely. It utilizes TCP/IP via corporate LAN or WAN, or
alternatively directly through the communication port at the front of the IED.

Figure 3: Disturbance Evaluation Software

Software PCM 600

PCM 600 consists of:

Configuration (CAP 531)

Signal Matrix (SMT)

Configuration of I/O Cards, Analog input cards & Goose

Parameter Setting (PST)

Disturbance Handling

Graphic Display Editor (LCD Mimic Editor)

Time Scheduler

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Signal Monitoring

Event Viewer

4.1.4.1 IED 670 Hardware Structure

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4.1.4.2 Supervision of mA input signals (MMXU)

The main purpose of the function is to measure and process signals from different measuring
transducers. Many devices used in process control represent various parameters such as
frequency, temperature and DC battery voltage as low current values, usually in the range 4-
20 mA. Alarm limits can be set and used as triggers, e.g. to generate trip or alarm signals.
The function requires that the IED is equipped with the mA input module.

4.2 Station Level Functions

The hardware of the station level system provided for the 400kV control room consists of the
following:

The SAS conforms to IEC 61850 standards and has a decentralized architecture consisting of
the main functional parts explained in the introduction part.

The SAS is based on ABB make MicroSCADA Pro software running in a redundant hot
standby mode on two industrial PCs with Microsoft Windows 2003 Server Operating System
supported by MicroSCADA software. The windows firewall will be envisaged in the system.

The SAS provides an extensive range of Supervisory Control and Data Acquisition (SCADA)
functions

The station level functions (Logical Nodes) provided are:

Operator Interface (IHMI)

Remote Control Interface (ITCI)

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Archiving (IARC) for long term historical data

Disturbance data evaluation (RDRS)

Time Master (STIM)

System supervision (SSYS)

Full station level HMI include 2 No OWS, one LVS for special user functions such as station
single line diagram, overviews, control of circuit breakers and isolators, alarm lists and event
lists, logging of historical data for trends and reports.

The system will be controlled with the help of a mouse and keyboard. If required, system
engineering can also be done from the Station HMI. All alarm and event logs will be printed
out on the DMP printer. The reports and graphics will be printed on the Colour Laser printer.

The communication to the remote load dispatch centers uses IEC 60870-5-101 (slave)
protocol, with the remote centre as the master and the local gateway as the slave. It is
possible to control and monitor the local station from remote control centers; however remote
control centre will decide the default control point.

In addition to the above the gateway interface to Main Plant SCADA (DCS) uses OPC
connectivity.

4.2.1 Redundant Application server (Main/standby controllers) and Station HMI (Operating work
stations)

The redundant Application servers (Two numbers in SCR, Two numbers in CCR) consist of
industrial PCs with INTEL XEON microprocessor, running Windows 2003 Server operating
system. Monitoring and controlling of the station is through Operator workstations (Station
HMI) by the use of project specific pictures. A mouse is used to move the cursor and thus
navigate on and between picture pages. The PCs work on 230 V AC power supply.

The operator interface is based upon a hierarchical set of menu pages, which provide access
to overview, alarm list, event list and other pages. An authorization mechanism prevents
system access of unauthorized users and also allows assignment of a number of
authorization levels. This makes certain functions accessible only to users who have been
granted the required level of authorization.

4.2.2 Master Metering Station

Energy metering system is located within the 400kV switchyard control room. Energy meters
Elster make ALPHA M+ (ABT) located at CER and SCR have two communication ports.
Optical front port will be utilized for real time data acquisition and RS232 rear port will be
utilized for meter reading. All the energy meters will have RS485 port. All the meters are
looped together and finally single RS485 connection has been brought to mms via RS485 to
RS232 converter. The Real time data acquisition software ALPHA plus in the energy metering
system provide all metering functionalities. The Metering master station is a desktop PC
running Windows XP operating system. The Master Metering Station is connected to the
Substation LAN network for meter report printing only. The Alpha plus is a comprehensive
software interface for configuring all the meter functions.

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4.2.3 Communication Infrastructure

The communication infrastructure consists of a fibre optic, managed, switched Ethernet LAN
in a redundant fault tolerant ring configuration. This LAN is used for both station level and
inter bay communications. The communication protocol conforms to IEC 61850-8-1 standard.
Bay Ethernet switches are provided in all the panels (BCU &BPU panels) wherever an IED is
mounted. By this the requirement of locating Ethernet switches as close to the IEDs is
assured and further it is assured that no FO cables runs between IEDs and bay Ethernet
switches through cable trenches. The IEDs are connected to the switch using fibre optic
cables. At the station level the Ethernet switches Provide dual LAN output for further interface
to Operators work stations. The main features of the Ethernet switches used are listed below:

High speed (100 Mbps) operation

Glass fibre optic cables

Dual redundant power supplies for increased network availability

Designed for harsh environment – exceeds IEC 61850-3 requirements for use in
electrical substations

Operates up to a temperature of 85°C without the use of fans

Full compliance with IEEE 802.3 and IEEE 802.3u Ethernet standards for universal
interoperability

Enhanced Rapid Spanning Tree (IEEE 802.1w) for fault tolerance with fast recovery
times (<5ms)

Quality of service / Class of service (IEEE 802.1p) for prioritization of traffic (real time
traffic for software interlocks)

Virtual LAN (IEEE 802.1Q) for traffic segregation

SNMP for network management

SNTP for time synchronization of the Ethernet switches

Ethernet switches are provided with sufficient spare capacity.

4.2.4 Time Synchronization

The time master is a GPS receiver provided in the SAS. The GPS receiver is connected to
the Ethernet LAN and it synchronizes all the IEDs, the redundant HMIs and the remote
communication gateways directly. In conformance with the IEC 61850 standards, SNTP
protocol is used for time synchronization function.

4.2.5 Engineering Workstation

Workstation and Fault Recorder station

A desktop PC running Windows XP operating system along with the disturbance evaluation
software acts as the DR workstation. The application server automatically downloads the DR

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data from the IEDs in the pre-defined time intervals. The downloading of DR data can also be
done manually on operator’s request.

The operator or protection engineer can access these DR files and analyze them using the
DR evaluation software. The disturbance waveforms are printed on the colour laser printer. In
addition to Disturbance data evaluation, the same work station facilitates Parameterisation
and configuration of the IEDs

4.2.6 Remote Control Gateway

Gateways (Two numbers each) are provided in SCR and CCR) for remote connectivity. The
gateway in SCR has serial port for communication to the RLDC on IEC 60870-5-101 (Slave)
and RJ45 port for communication to the OS Control Room on OPC connectivity. Further
connectivity to Owner’s OS Control room is not in ABB scope. The port for RLDC has
V.24/V28 Communication standard (ITU-T, formerly CCITT standard) interfaces for
connection to the communication channels being provided by NTPC. The communication
speed is selectable independently for each port and can be set to a maximum of 9600 bauds;
however the use of PLCC will restrict the communication speed to a maximum of 1200 bauds.
ABB make NSK5 modems shall also be supplied for interfacing with RLDC.

The Substation LAN is extended to the Main Plant control room through fibre optic
communication equipment. The SAS also provides gateway on OPC connectivity for Main
plant interface (DCS) in CCR.

4.3 Operator Interface functions

The operator interface is based on MicroSCADA Pro (SYS600) software that runs on
Windows operating system. SYS 600 software consists of the basic functions needed to
monitor and control substations.

Application pictures are used to visualize the supervised processes. There are many different
types of application pictures: single line diagrams, process pictures, system supervision, lists,
application tools, measurement reports and trend reports. Generally, only one application
picture is presented within one monitor (Monitor Pro). The opening of another function closes
or hides the previous one. However, several monitors can be opened to the same application.
Each user can modify the layout of Monitor Pro. The user specific layout is saved when the
user logs out and it is loaded when the user logs into the application.

The system specific start picture is the first picture displayed when Monitor Pro is started.
When Monitor Pro starts, it requires login before the session can continue.The Close button in
the login dialog closes the login dialog but not Monitor Pro.

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Figure 4: Monitor Pro Login dialog *

4.3.1 User login

login

In the login dialog, there is a combo box, in which the current "HOT" applications are shown.
The start picture requests a user name and password. Each user is associated with a certain
user profile defined by the system manager.

The password is not displayed on the screen. If the user name and the password do not
match, or the user name does not exist, the login dialog reappears and you can make a new
attempt. Each attempt to log in is registered by the system, even those that are failed.

If the login succeeds, the substation overview picture is produced on the screen. All
operations subsequently performed on the Monitor Pro, are related to the authority profile
associated with the user name. The user name is also included in as an identifier in the event
register when certain manual operations are performed.

4.3.2 Logout

In Monitor Pro, logout means that the user name and user authority are cleared. The user is
logged out when:

The user logs out using the Main/Logout menu item

Monitor Pro is closed down by using the Close button or the Main/Exit menu item

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Automatic time based logout is done by Monitor Pro

The MicroSCADA application state is changed from "HOT" to "WARM" or "COLD"

The MicroSCADA OPC DA server or MicroSCADA service is stopped

4.3.2.1 Time based logout:

After a certain predefined time, e.g. 8 hours, an automatic logout is done. The logout duration
is defined in the Application Settings, i.e. the setting is user specific. The user has to login
again via the Login dialog.

4.3.3 Application Settings

An Application Settings picture can be given new settings by selecting Options-Settings in the
main menu bar. Only a user with rights on system management level (system manager) can
change the application settings. It is used to create some application specific settings such
as:

Application owner: the name of the customer to whom this product is licensed (in this
case – NTPC). The name of the application owner cannot be changed in the
Application settings picture.

First picture shown after login: defines the first picture that pops up after a user logs
in.

System location: this defines whether the MicroSCADA is running as a Remote

Control Centre (RCC) or a Substation Control System (SCS).

Lockout duration: this sets the session length. When the lockout duration time
expires, the authorization level is reset to View (0). The lockout duration time is given
in hours (from 1 to 254). The session duration can be activated or deactivated.

Show object ID: this defines the parts of the Object Identity attributes that are to be
shown in Alarm lists, Event lists and dialogs.

HD space alarm: Hard Disk Supervision function supervises the free Hard Disk
space. This function gives the operator an early warning if there is a risk of running
out of space on the hard disk. The supervision function is stopped when the limit is
set to zero.

Report Settings: this is used to define, among others, the base period for the reports
(15, 30 or 60 minutes) and the history length (1 year to 5 years). These settings are
valid for the entire application and changing these later will erase the existing history
data.

The application settings being used for this project are:

Application owner – NTPC

First picture – Substation overview (400 kV)

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System location – Substation Control System

Lockout duration – 8 hours

HD space alarm – 100 MB

Report settings – base period: 60 minutes, history length: 2 years

Figure 5: Application setting dialog *

4.3.4 User Management

The user with rights on system management level (system manager) can make changes in
the User Management function. In the LIB 500 applications the standard functions in the
process pictures can be freely grouped into authorization groups. This means that a user can
have different authorization levels for different apparatus. Users can also be defined to have
different authorization levels for different tools, substations etc. (see Figure 12).

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Figure 6: Example of Authorization profile

View (0) level: The user is allowed to view the substation status, but is not authorized
to make any control operations, or to use the programming and system configuration
tools.

Control (1) level: The user is allowed to make control operations, but he has no
access to the engineering and system configuration tools.

Engineering (2) level: The user is granted all rights for control, engineering and
system configuration, except system management.

System management (3) level: The user is granted all rights including the rights to
add and remove users. Only one user can be granted this authorization level.

The number of users and their authorization levels will be decided during the detailed
engineering stage. The system manager can add and remove users and user groups as well
as change the authorization levels. All users can change their own passwords.

4.3.5 Process Display

The Process Display is a view, which is displayed when the user is logged into an application.
The process displays appear on the MicroSCADA Pro Monitor. They contain information on
the status of the process in the form of Single Line Diagrams (SLD) having graphical objects
with dynamic behaviour. Process displays in the MicroSCADA Pro Monitor contain the
functionality for zooming, panning and de-cluttering of displays.

The user interacts with the MicroSCADA system through the control dialogs accessed from
the process display. Only those users, who belong to certain user groups, are allowed to
execute control operations towards the process devices of the MicroSCADA system.

The SAS will have the 400kV substation SLD as the main process display. The substation
SLD will have the following information.

Status of all circuit breakers and isolators

Bus voltages and frequency

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Line current, voltage, active power, reactive power and power factor

Control mode (Station/Remote) of the substation

Control mode (Local/Remote) of each bay

Bus bar colouring to identify powered, non powered and earthed segments of the
SLD

It is also possible to control the switchgears from this picture. Further, it provides access to
other pictures like event list, alarm list, trends and reports.

In addition to the above process displays, a ‘soft LED’ is also provided for indicating
‘synchronising in limit’ conditions. Further for doing a check while synchronising, both
Incoming and Running voltages and frequency will be displayed near to each breaker picture.

Figure 7: 400 kV SLD (typical)*

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4.3.5.1 Display Builder

Display Builder is the picture editor in MicroSCADA that is used to create complete graphical
interfaces. You can define the graphical appearance of objects in your interface, describe the
data they will display, and specify their dynamic behavior. The drawing process requires no
programming. Drawings are easy to create and edit directly in the drawing area, and dialogs
let you control all aspects of the editing process, including assigning display characteristics
and specifying how your data is stored. Display Builder provides default values for every
dynamic element of a drawing so you can quickly construct a complete dynamic drawing that
can monitor and control substations as well as electrical power transmission and distribution
systems.

4.3.6 Control dialogs

The control dialogs provide fast and easy access to a device in a substation. The control
dialog combines different kind of information, depending on the object. Control dialogs
interact with standard objects created with Object Navigator by using standard library
functions.

Control dialogs are generic and they have same user-interface appearance, independent of
the IED and the communication protocol defined in standard object configuration. Only one
control dialog can be open at a time for each Monitor Pro window.

4.3.6.1 Station Local/Remote control

The station local/remote control shows whether the control is authorized from the station
locally or from an external control centre.

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Figure 8 : Station Local / Remote control dialog *

This control dialog has three tabs; Main tab, Message tab and Blocking tab. Main tab lets you
select the Local/Remote option. The options available depend on object configuration.
Unavailable options are dimmed. In Messages tab, different messages concerning the object
are shown. In Blocking tab, different blockings concerning the process object are shown and
controlled.

4.3.6.2 Bay Local/Remote

Local/Remote control

The Bay L/R control shows the whether the control of the bay is authorized from the bay unit
locally or remotely over a communication link. If the Bay L/R switch is remotely controllable, it
is possible to change the switch state from the control dialog.

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Figure 9 : Bay Local / Remote control dialog *

This control dialog has three tabs; Main tab, Message tab and Blocking tab. Main tab lets you
select the Local/Remote option. The options available depend on object configuration.
Unavailable options are dimmed. In Messages tab, different messages concerning the object
are shown. In Blocking tab, different blockings concerning the process object are shown and
controlled.

4.3.6.3 Switch control

Switch control dialogs can be used to show current state and status of a switch device object.
It is also used for operating the switch device. The same dialog is used for circuit breakers
and isolators. There are several tabs on this dialog. Navigate between the tabs navigation by
using the arrow buttons on the upper-right corner of the dialog.

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Figure 10 : Switch control dialog (Select Before Operate) *

The upper field of the main tab shows the object identification: station, bay and the object. The lower
field of the tab shows the object status. If control is not blocked, the Close button or Open button is
active. If, based on the interlock conditions, the selection of the control command is successful, the
Execute or Cancel symbol buttons become active. Confirm the control operation by clicking the
Execute button. Cancel the selection by clicking the Cancel symbol button. Possible errors during
operation appear in the Object status field of the Switch state tab. Close the dialog by clicking Exit or
click the icon on the upper-right corner of the dialog. If, based on the interlock conditions, the selection
of the control command is unsuccessful; the operator can view the object, which is blocking the
permissive in the SLD picture where that object will be shown in a flashing mode.

Incase of Breaker switch control dialog, if synchrocheck conditions are not met, the operator can view
a dialogue ‘ Device not synchronised’ in the switch control dialog. If in case Interlock conditions are
not met a dialogue ‘Device’ s Open/Close Interlocked’ appears in the switch control dialogue. The
latter is applicable for switch control dialogues of Isolators and Earth switches also.

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Figure 11 : Switch control dialog (expanded)*

Blocking tab

In the Blocking tab of the Switch control dialog, different blockings concerning the process
objects are displayed.

Forced operation tab

In the Forced operation tab, the internal blockings and control blockings can be bypassed.
After this, the Open and Close buttons are enabled. However, this does not disable any
interlockings or other IED measures, that is, no special bypass messages are sent to the
IEDs.

4.3.7 Event List

Event is a wide term that also comprises alarms. The event activation and consequential
actions are defined in the process database separately for each individual object.

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Figure 12 : Event List *

The purpose of the Event List is to provide the user with information about events occurring in
the system. It is also provides information about activities carried out by other users,
operations of objects, acknowledging of alarms, editing of limit values, logging in and so on.

The Event List presents the data in a structured way for the user’s convenience. Each event
is presented by displaying an event text line, which consists of a time stamp, object
identification, a signal text and a text indicating the status.

4.3.7.1 Features of Event List

Scroll intervals are configurable from 10 to 100 pages, in steps of 10

Fast navigation using the scroll bar: jump to the last page, one page back or forward
and so on.

Possibility to navigate to the previous day or next day or to a day typed into the input
dialog

User-friendly filters and color settings

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Updating/Frozen presentation modes

Additional comments can be given to the events (up to 250 characters per event)

Printing of Events on demand

Possibility to display events either in log order or event order

Color settings

Find

Column sort

If the Event List is in the updating mode, the list will be updated when a new event occurs in
the system. When the list is in the frozen mode (non-updating), a message will be displayed
informing the user to change the mode to the updating mode and view the latest events.

When the Event List is in the updating mode, half a page will be shown when the list is
presented on the screen. All the new events are presented on the remaining half a page until
the page is full. When the page is full, it scrolls up a half page and new events begin to fill the
page again.

Figure 13 : Event list settings

When the Event List is in the updating mode, the events are sorted in the order which they
were written into history database, i.e. logging order. The order defined in the Settings dialog
is applied in the frozen mode.

It is possible to configure certain events to use different colors in the Event List. This improves
the possibility to locate certain system events. E.g. important events, which cause alarms in
the system, can be defined to use the red color in the Event List.

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Figure 14 : Event list filter settings*

Filters are used when the user wants to display or concentrate on specific information. It is
possible to change the existing filters or add new filters that can be stored and reused by
other operators.

By clicking the left mouse button on a column header in the event list, the event list is sorted
on the column clicked. If the same column is clicked twice, the sorting is descending. After the
data is sorted, the list is set to Frozen mode. Column sort is reset when the list mode is
changed back to Update.

The Find tool allows the user to search for text within the current event list view. The Find tool
searches the list from the start to the end. If an event line contains the desired text, it is
selected. A message box appears when find has reached the end point of the search or when
searched text is not found.

4.3.8 Alarm List

The Alarm List displays a summary of the present alarm situation of the supervised process.
Each alarm is presented as an alarm text line, which has a time stamp, an object id, an object
text, a text indicating the alarm status, as well as a number ranging from 1-7 indicating the
alarm class.

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Figure 15 : Alarm List (Template 1)*

Figure
Figure 16 : Alarm List (Template 2)*

The process alarms are alarms that are related to the supervised process, for example,
measurement values exceeding or going below the preset alarm limits, breakers tripping or
getting into a faulty position and so on.

The internal alarms are alarms caused by the network control system itself. Reasons for
these alarms include communication problems between a communication unit and substation,
printer device errors, substation getting suspended, etc.

4.3.8.1 Features of Alarm List

Two types of Alarm List templates

User-friendly filters

Alarm List setting tool for colors and text layout

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Color and text layout settings

Updating/Frozen presentation modes

Alarm acknowledgement

Alarm reset function

Locate Object

Column sort

Find

Figure 17 : Alarm list settings*

4.3.8.2 Alarm acknowledgement

An acknowledgement of an alarm is a way to show that the operator has registered and
identified the alarm. Generally, acknowledging an alarm does not affect the alarm state. An
unacknowledged alarm remains in the alarm buffer until it is acknowledged, even if the alarm
state has passed.

4.3.8.3 Alarm blocking

Alarm blocking blocks a signal in such a way that it cannot generate an alarm. (The same
implies for history blocking, printout blocking and reprocessing blocking.) Since the alarm is
blocked, it is not registered in the process database when the process object gets into an
alarm generating state.

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4.3.8.4 Alarm classes

The alarms can be grouped into seven equally significant alarm classes. This feature can be
used when the user wants to group alarms caused by process objects with common
properties. From the system point of view there is no internal priority between the different
alarm classes. The alarm classes can also be used when searching alarms from the alarm
buffer. By setting the alarm class to 0, the alarm function of a process object is set off.

Filters are used when the user wants to concentrate on certain information in the alarm buffer.
This is done by defining criteria to filter out unwanted information. A single criterion or multiple
criteria can be used for filtering. The alarm list filter settings are identical to the event list filter
settings (Figure 14 : Event list filter settings*

4.3.8.5 Alarm List presentation modes

The alarm buffer is updated every time the alarm state of a process object changes. Basically,
the Alarm List should be updated at each update of the alarm buffer to give correct and up-to-
date information. However, if the list is updated frequently, it is almost impossible to
concentrate on a single alarm line. This is the reason why the Alarm List has two presentation
modes: frozen and updating. When the list is in the frozen mode, it is not updated, and the
alarm information can be read easily. If the alarm buffer is updated while the Alarm List is in
the frozen mode, the operator is notified with an informative text on the status bar. When in
the updating mode, the Alarm List is updated at every update of the alarm buffer. The frozen
mode is automatically selected when the list is scrolled or when a tool affecting the alarm
buffer is used. The current mode is always indicated.

By clicking the left mouse button on a list column header, the alarm list is sorted. The column
that is used for sorting is the column that was clicked. If the same column is clicked twice, the
sorting is in descending order. After the data is sorted, the list is set to the Frozen mode. The
column sort is reset when the list mode is changed back to Update.

The Find function allows you to search for text within the current alarm list view. Find
searches through the list from the beginning point down. The alarm line that contains
searched text is set selected. A message box appears when Find has reached the end point
of the search or when searched text does not exist.

Acknowledgement of a single alarm is done by selecting the alarm text line of the desired
alarm on the list. If the selected alarm is unacknowledged, selecting Acknowledge from the
pop-up menu can open the Acknowledgement dialog. At the same time the Alarm List is set to
the frozen mode to prevent unwanted scrolling.

4.3.9 Blocking List

The Blocking List summarizes the present blocking situation of the signals of the supervised
process. Each signal is presented as a signal text line, which describes the signal in the
process. The signal text line normally consists of a signal text and a group of check boxes
indicating the blocking state.

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Figure 18 : Blocking List*

List*

The following blocking types are provided by the Blocking List:

Alarm blocking: alarms are not raised, regardless of the object state.

Update blocking: indications are not updated by the process.

Control blocking: operation commands are not sent to the process.

Event blocking: event registrations are not made, events are not shown in the Event
List.

Printout blocking: events are not sent to the printer.

Action blocking: event channel activation is blocked.

4.3.10 Measurement Reports

The measurement reports display is an application that collects data and visualizes the data
in numerical or graphical form. The measurement reports display is used to log and report
data during longer periods than the Trend Application, and it is dedicated for Energy, Current,
Voltage, Temperature and Frequency reports.

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 Functional Design Specification – Substation Automation System

The available time ranges for the reports are listed below:
• Hourly report (time resolution: 3 minutes)
• Daily report (time resolution: 15 minutes)
• Daily report (time resolution: 30 minutes)
• Daily report (time resolution: 60 minutes)
• Weekly report (time resolution: 1 day)
• Monthly report (time resolution: 1 day)
• Yearly report (time resolution: 1 month)
The storage period for the reports can be up to 5 years. Longer storage periods can be
custom built or achieved by exporting data to an external reporting database.

Figure 19:
19: Measurement Reports (Tabular Form)

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 Functional Design Specification – Substation Automation System

Figure 20:
20: Measurement Reports (Graphical form)

4.3.11 Trend Application

MicroSCADA Monitor Pro includes the new Trend Application. Trend Application is used for
trend analyses and for showing measured values in the form of a curve or a table.

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 Functional Design Specification – Substation Automation System

Figure 21 : Trend picture (Graphical form)*

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 Functional Design Specification – Substation Automation System

Figure 22 : Trend picture (Tabular form)*

4.3.11.1 Features of Trend application

Graphic or tabular view modes

Hairline function

Zooming graphic view

Scrolling with scroll bars and panning

Configurable axes and line properties

• Using legend

• Update interval options from 30 seconds to 10 minutes

• Clearing trend data by user

• Save, Open and Delete preconfigurations

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 Functional Design Specification – Substation Automation System

• Printout option

• Update/Frozen modes

4.3.11.2 Trend Basket

A trend is a time-related follow-up of process data. All types of process objects, e.g. analogue
and digital data can be illustrated as trends.

When the trend picture is shown, the user can select the data from the trend basket. When
the trend basket is closed, the selected trends are brought to the trend picture. Trend view
configuration includes a set of parameters such as colors, fonts, etc., which are called trend
preconfigurations. Users can create, delete or apply existing preconfiguration to the trend
picture.

Figure 23 : Trend basket*

4.3.12 System Self Supervision

The SYS 600 System Self Supervision (SSS) is used with the MicroSCADA systems for
supervising and monitoring the system. It provides status information of hardware and
software, as well as picture functions for the supervision of system objects.

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 Functional Design Specification – Substation Automation System

Figure 24 : Example
Example of System Supervision picture*

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We reserve all rights in this document and in the information contained therein. Reproduction, use or disclosure to third parties
without express authority is strictly forbidden. Copyright © by ABB Limited

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Table of Contents:
1 General ............................................................................................................... 5

2 Bay...................................................................................................................... 5

2.1 Bay level ............................................................................................... 5

2.2 Line bays .............................................................................................. 6

2.2.1 Description of Line bay functionality ..................................................... 7

2.2.1.1 Distance protection (PDIS, 21) 7

2.2.1.2 Power swing detection (RPSB, 78) 8

2.2.1.3 Directional IDMT earth fault protection (PDEF, 67N) 8

2.2.1.4 Over voltage protection (PTOV, 59) 8

2.2.1.5 Scheme communication logic (PSCH, 85) 8

2.2.1.6 Current reversal and weak-end in-feed logic (PSCH, 85)

9

2.2.1.7 Fuse failure supervision (RFUF) 9

2.2.1.8 Autorecloser (RREC, 79) (built in function of Bay

Controller) 9

2.2.1.9 Synchrocheck and energizing check (RSYN, 25) 9

2.2.1.10 Fault locator (RFLO) 10

2.2.1.11 Alarm and Event recorder (RDRE) 10

2.2.1.12 Disturbance recorder (RDRE) 10

2.2.1.13 Measurements (MMXU) 11

2.2.1.14 Apparatus control (CSWI) 11

2.2.1.15 Interlocking (CILO) 11

2.2.2 Implementation of Line bay functionality ............................................. 11

2.3 Bus Reactor Bay................................................................................. 12

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2.3.1 Description of Reactor bay functionality.............................................. 13

2.3.1.1 High Impedance reactor differential protection (PTDF

,87R) 14

2.3.1.2 Back up Over current and earth fault Protection (PTOC,

51) 14

2.3.2 Implementation of Bus Reactor bay functionality ................................ 14

2.4 Station Transformer bays.................................................................... 15

2.4.1 Description of ST bay functionality...................................................... 16

2.4.1.1 Transformer differential protection (PTDF, 87T) 16

2.4.1.2 Restricted earth fault protection (PNDF, 87N) 17

2.4.1.3 Transformer over current protection (PTOC, 51) 17

2.4.2 Implementation of Station Transformer bay functionality .................... 17

2.5 Generator, Generator Transformer, UT bays...................................... 18

2.5.1 Description of GT bay functionality ..................................................... 20

2.5.1.1 Transformer differential protection (PTDF, 87T) 20

2.5.1.2 Restricted earth fault protection (PNDF, 87N) 21

2.5.1.3 Standby Earthfault Protection (TEF, 51N) 21

2.5.1.4 Over excitation protection (PVPH, 24) 21

2.5.2 Implementation of Generator, Generator Transformer and UT bay

functionality ....................................................................................................... 22

2.5.3 Bus bar protection IED REB 670 ........................................................ 23

2.5.3.1 Busbar protection (PBDF, 87B) 24

Table of Figures:
Figure 1: Configuration of 400 kV Line bay IEDs .............................................. 12

Figure 2 : Configuration of 400kV Bus Reactor bay IEDs........................................ 15

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Figure 3: Configuration of 400 kV ST bay IEDs........................................................ 18

Figure 4: Configuration of 400 kV GT bay IEDs (Typical)......................................... 22

Figure 5: Configuration of 400 kV REB 670 ............................................................. 24

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1 General
This document explains briefly about the bay level IED’s hardware and
functionality. It also includes bay level protection details along with IED
features as enabled for each bay for both Main-I and Main-II.

2 Bay
A bay comprises of one circuit breaker and associated disconnectors, earth
switches and instrument transformers.

2.1 Bay level

At bay level, the IEDs provide all bay level functions like control (command
outputs), monitoring (status indications, measured values) and protection. The
IEDs are directly connected to the switchgear without any need for additional
interposing devices or transducers.

Each bay control IED is independent of the others and its functioning is not
affected by any fault occurring in any of the other bay control units of the
station.

The data exchange among bay level IEDs and between bay level and station
level takes place via the fibre-optic inter bay bus according to IEC 61850-8-1
standard. The use of fibre-optic LAN guarantees disturbance-free
communication.

Though, at station level, the entire station is controlled and supervised from
the station HMI, it is possible to control and monitor the bay from the bay level
equipment, whenever required. The decentralized architecture ensures that
station wide interlocking is available even when the station computer fails.

Clear control priorities prevent the initiation of simultaneous operation of a

single switch from more than one of the various control levels, i.e. RCC, Main
Plant SCADA, station, bay level or apparatus level. The priority is on the
lowest enabled control level. The operation also depends on the status of
other functions like interlocking, synchrocheck, etc., as applicable.

Separate IEDs are provided for bay control function and bay protection
function. For line bays, Auto reclose function is configured in the respective
bay control units. A backup autorecloser function is configured in a BPU
(Main-1 distance relay, REL670 for lines that will be enabled in case of failure
of BCU).

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Note The bay level functionalities shall be as per the approved Scheme.
Note:

2.2 Line bays

The following functions (Logical Nodes, or LN, as defined in IEC 61850) are
required for 400 kV line bays.

Distance protection (PDIS, 21), with quadrilateral characteristics and

suitable for series compensated lines.

Power swing block (RPSB, 78)

Current reversal and weak end in-feed logic (PSCH, 85)

Permissive under reach / over reach / blocking (PSCH, 85)

Fuse failure supervision (RFUF, 60)

Back up Over Current Protection (PTOC,51)

Directional backup IDMT earth fault protection (PDEF, 67N)

Single shot auto reclose function (RREC, 79), with single phase or
three phase reclosing facility.

Synchronizing and energizing check (RSYN, 25)

Trip Circuit Supervision

Line over voltage protection (PTOV, 59)

Standby Earth fault Protection (PTEF,51N)

Non directional over current Protection (PTOC , 51)

Fault locator (RFLO)

Disturbance Recording, bay level acquisition (RDRE), with 8 analog

and 16 digital

Sequential event recorder (RDRE) with time resolution of 1 ms

Breaker and isolator control (CSWI)

Bay level and inter bay interlocks (CILO)

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Measurement of voltages, currents, active and reactive power (MMXU)

Local HMI (IHMI)

As per IEC 61850, the primary equipments are also represented as LNs, and
the ones used in this bay are:

Circuit breaker (XCBR)

Isolators (XSWI)

Earth switches (XSWI)

Current transformer (TCTR)

Voltage transformer (TVTR)

Since process bus (IEC 61850-9-2) is not used, these LNs are hardwired
inputs and outputs of the control and protection IEDs. XCBR and XSWI
represent the status inputs from, and command outputs to the breaker and
isolators. TCTR and TVTR are the current and voltage inputs respectively
from the instrument transformers.

2.2.1 Description of Line bay functionality

2.2.1.1 Distance protection (PDIS, 21)

The line distance protection is a five-zone full scheme protection with three
fault loops for phase-to-phase faults and three phase fault loops for phase-to-
earth fault for each of the independent zones. Individual settings for each
zone resistive and reactive reach give flexibility for use on overhead lines and
cables of different types and lengths.

The function has a built in algorithm for load encroachment, which increases
the possibility to detect high resistive faults on heavily loaded lines. The
independent measurement of impedance for each fault loop together with a
sensitive and reliable built in phase selection makes the function suitable in
applications with single phase auto reclosing.

Built-in adaptive load compensation algorithm prevents overreaching at

phase-to-earth faults on heavily loaded power lines. The distance protection
zones can operate independent of each other, in directional (forward or
reverse) or non-directional mode. This makes them suitable, together with
different communication schemes, for the protection of power lines and cables

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in complex network configurations, such as parallel lines, multi-terminal lines

etc.

Automatic switch onto fault logic is a function that gives an instantaneous trip
at closing of breaker onto a fault. A dead line detection check is provided to
activate the function when the line is dead.

2.2.1.2 Power swing detection (RPSB, 78)

Power swings may occur after disconnection of heavy loads or trip of big
generation plants. Power swing detection function is used to detect power
swings and initiate block of selected distance protection zones. Occurrence of
earth fault currents during a power swing can block the power swing detection
function to allow fault clearance.

2.2.1.3 Directional IDMT earth fault protection (PDEF, 67N)

All IEC and ANSI time delayed characteristics are available together with an
optional user defined characteristic. The function can be set to be directional
or nondirectional independently for each of the steps. A second harmonic
blocking can be set individually for each step.

Directional operation can be combined together with corresponding

communication blocks into permissive or blocking teleprotection scheme.
Current reversal and weak-end in-feed functionality are available as well. The
function can be configured to measure the residual current from the three
phase current inputs or the current from a separate current input.

2.2.1.4 Over voltage protection (PTOV, 59)

The function has two voltage levels, each level is inverse or definite time
delayed. The over voltage function has an extremely high reset ratio to allow
setting close to system service voltage.

2.2.1.5 Scheme communication logic (PSCH, 85)

To achieve instantaneous fault clearance for all line faults, a scheme
communication logic is provided. All types of communication schemes e.g.
permissive under reach, permissive over reach, blocking, inter-trip etc. are
available.

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2.2.1.6 Current reversal and weak-

weak-end in-
in-feed logic (PSCH, 85)
The current reversal function is used to prevent unwanted operations due to
current reversal when using permissive overreach protection schemes in
application with parallel lines.

The weak-end infeed logic is used in cases where the apparent power behind
the protection can be too low to activate the distance protection function.
When activated, received carrier signal together with local under voltage
criteria and no reverse zone operation gives an instantaneous trip. The
received signal is also echoed back to accelerate the sending end.

2.2.1.7 Fuse failure supervision (RFUF)

Failures in the secondary circuits of the voltage transformer can cause
unwanted operation of distance protection, under voltage protection, neutral
point voltage protection, energizing function (synchro-check) etc. The fuse
failure supervision function prevents such unwanted operations.

There are three methods to detect fuse failures.

The method based on detection of zero sequence voltage without any zero
sequence current. This is a useful principle in a directly earthed system and
can detect one or two phase fuse failures.

The method based on detection of negative sequence voltage without any

negative sequence current. This is a useful principle in a non-directly earthed
system and can detect one or two phase fuse failures.

The method based on detection of du/dt-di/dt where a change of the voltage is

compared to a change in the current. Only voltage changes means a voltage
transformer fault. This principle can detect one, two or three phase fuse
failures.

2.2.1.8 Autorecloser (RREC, 79) (built in function of Bay Controller)

The autoreclosing function provides high-speed and/or delayed autoreclosing
for single breaker applications. Up to five reclosing attempts can be
programmed. The first attempt can be single phase, two phase and/or three
phase for single phase or multi-phase faults respectively.

2.2.1.9 Synchrocheck and energizing check (RSYN, 25)

The synchrocheck function checks that the voltages on both sides of the
circuit breaker are in synchronism, or with at least one side dead to ensure
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that closing can be done safely. The function includes a built-in voltage
selection scheme for double bus and one- and a half or ring busbar
arrangements. Manual closing as well as automatic reclosing can be checked
by the function and can have different settings, e.g. the allowed frequency
difference can be set to allow wider limits for the auto-reclose attempt than for
the manual closing. A synchronizing function providing closing of the breaker
at the correct instance when network parts are running asynchronous is also
provided.

2.2.1.10 Fault locator (RFLO)

The built-in fault locator is an impedance based function giving the distance to
the fault in percent, km or miles. The main advantage is the high accuracy
achieved by compensating for load current and for the mutual zero sequence
effect on double circuit lines. The compensation includes setting of the remote
and local sources and calculation of the distribution of fault currents from each
side. The fault can be recalculated with new source data at the actual fault to
further increase the accuracy. Specially on heavily loaded long lines (where
the fault locator is most important) where the source voltage angles can be up
to 35-40 degrees apart the accuracy can be still maintained with the advanced
compensation included in our fault locator.

2.2.1.11 Alarm and Event recorder (RDRE)

The event recorder logs all selected binary input signals connected to the
Disturbance Report function. Each recording can contain up to 150 time
tagged events. The event recorder information is available for the last ten
disturbances locally in the IED.

2.2.1.12 Disturbance recorder (RDRE)

The Disturbance Recorder function supplies fast, complete and reliable
information about disturbances in the power system. It facilitates
understanding system behavior and related primary and secondary equipment
during and after a disturbance. The Disturbance Recorder acquires sampled
data from all selected analogue input and binary signals connected to the
Disturbance Report function (maximum 40 analogue and 96 binary signals).
The binary signals are the same signals as available under the event recorder
function. The function is characterized by great flexibility and is not dependent
on the operation of protection functions. It can record disturbances not
detected by protection functions. The disturbance recorder information for the
last 100 disturbances are saved in the IED and the Local Human Machine
Interface is used to view the list of recordings.

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2.2.1.13 Measurements (MMXU)

The service value function is used to get on-line information from the IED.
These service values makes it possible to display on-line information on the
local HMI about measured voltages, currents, frequency, active, reactive and
apparent power and power factor.

2.2.1.14 Apparatus control (CSWI)

The apparatus control is a function for control and supervision of circuit
breakers and isolators within a bay. Permission to operate is given after
evaluation of conditions from other functions such as interlocking,
synchrocheck, operator place selection and external or internal blockings.

2.2.1.15 Interlocking (CILO)

The interlocking function blocks the possibility to operate primary switching
devices, for instance when an isolator is under load, in order to prevent
material damage and/or accidental human injury. Each apparatus control
function has interlocking modules included for different switchyard
arrangements, where each function handles interlocking of one bay. The
interlocking function is distributed to each IED and is not dependent on any
central function.

For the station-wide interlocking, the IEDs communicate via the system-wide
interbay bus (IEC 61850-8-1) or by using hard wired binary inputs/outputs.
The interlocking conditions depend on the circuit configuration and apparatus
position status at any given time.

2.2.2 Implementation of Line bay functionality

To achieve the above functionality, various IEDs were selected keeping in
mind the constraints specified by NTPC.

The IED for Main 1 distance protection is ABB make REL 670 (with
communication module), while for Main 2 we have used Siemens make
7SA522 relay. The bay control IED is ABB make REC 670, with built in mimic.
The bay control IED is designed to control (switch ON / OFF), along with all
necessary interlocks. It also measures voltages (R-Y, Y-B, and B-R), currents
(R, Y and B) and active and reactive power for each line.

The Auto Reclose (RREC) function of 400 kV line bays is integrated in the
respective Bay control IED REC 670. Check synchronizing functions required
for auto reclose function is also integrated within the same IED for easy
coordination. A backup autorecloser function is configured in a BPU (Main-1
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distance relay, REL 670 for lines and that will be enabled in case of failure of
BCU.

All intra-bay interlocks are software based and performed by the BCU. The
complete bay can be monitored and controlled from the local HMI on the
BCU.

Station wide interlocks are software based; the data for the interlocks are
transmitted using GOOSE messages by the individual IEDs. To provide
backup for these GOOSE messages, GOOSE messages will be duplicated.
i.e., a BCU requiring status of one equipment in another bay will receive that
status as GOOSE message from two BCUs simultaneously .In case of failure
of one of those two BCUs, still status will be available from the other BCU.
This ensures that failure of one Bay does not affect the operation of another.
However no duplication is envisaged for GOOSE signals used for DR triggerin

Figure 1: Configuration of 400 kV Line bay IEDs

REL 670 / 7SA522 REC 670

CSWI RSYN
PDIS RPSB
CSWI RREC
PDEF RFUF
CSWI MMXU
PTOV RFLO
CILO IHMI
PTOC PSCH

PTEF RREC* XCBR

RDRE – DR, SER XSWI TCTR

TVTR TCTR XSWI TVTR

2.3 Bus Reactor Bay

The following Logical Nodes, as defined in IEC 61850, are required for 400 kV
Bus Reactor bay.

Percentage Bias Reactor differential protection (PDIF, 87R) triple pole

type

Restricted earth fault protection (PDIF, 64R), triple pole type

Non directional over current Protection (PTOC,51)

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Non directional earth fault protection (PTEF, 51N)

Over excitation protection (PVPH, 99R)

Trip Circuit Supervision (PTRC, 94)

Disturbance Recording, bay level acquisition (RDRE), with 8 analog

and 16 digital.

Sequential event recorder (RDRE) with time resolution of 1 ms.

Breaker and Isolator control (CSWI)

Synchronizing and energizing check (RSYN, 25)

Bay level and inter bay interlocks (CILO)

Measurement of voltages, currents, frequency, active power, reactive

power, winding temperature and tap position (MMXU).

Local HMI (IHMI)

The primary equipment LNs used in this bay are:

Circuit breaker (XCBR)

Isolators (XSWI)

Earth switches (XSWI)

Reactor (ZREA)

Current transformer (TCTR)

Voltage transformer (TVTR)

As in the case of line bays, these LNs are hardwired inputs and outputs of the
control and protection IEDs.

2.3.1 Description of Reactor bay functionality

Functions not described earlier under Line bay & transformer bay
functionality are described below.

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2.3.1.1 High Impedance reactor differential protection ((PTDF, 87R))

PTDF, 87R
The high impedance differential protection can be used when the involved CT
cores have same turn ratio and similar magnetizing characteristic. It utilizes a
series resistor and a voltage dependent resistor externally to the relay for
each phase. The function should preferable be used on dedicated CT cores.

2.3.1.2 Back up Over current and earth fault Protection (PTOC

(PTOC,, 51
51))
Non directional Over current and earth fault protection is provided as backup
protection for the reactor. Over current and earth fault protection functions are
time delayed and characteristics of the timing element can be selected to suit
the required application.

2.3.2 Implementation of Bus Reactor bay functionality

For both Main 1 and Main 2 Bus reactor protection, the IED selected is ABB
make RET 670. The main Bus reactor protection LNs are distributed between
these two IEDs. The bay control IED is ABB make REC 670, with built in
mimic. The bay control IED is designed to control (switch ON / OFF), along
with all necessary interlocks. It also measures voltages (R-Y, Y-B, and B-R)
and currents (R, Y and B) for the Bus reactor bay.

All intra-bay interlocks are software based and performed by the BCU. The
complete bay can be monitored and controlled from the local HMI on the
BCU. Station wide interlocks are software based; the data for the interlocks
are transmitted using GOOSE messages by the individual IEDs. To provide
backup for these GOOSE messages, GOOSE messages will be duplicated.
I.e., a BCU requiring status of one equipment in another bay will receive that
status as GOOSE message from two BCUs simultaneously .In case of failure
of one of those two BCUs, still status will be available from the other BCU.
This ensures that failure of one Bay does not affect the operation of another.

The distribution of LNs in the various IEDs is shown below.

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REC 670
RET 670-
670-1 RET670-
RET670-2
CSWI RSYN
PDIF PDIF
CSWI

PVPH PTOC PTEF CSWI MMXU

CILO IHMI

XCBR
XCBR TCTR XCBR TCTR
XSWI TCTR
ZREA TVTR ZREA TVTR
XSWI TVTR

Figure 2 : Configuration of 400kV Bus Reacto

Reactorr bay IEDs

*PDIF Logical Node is representing Differential Function and Restricted

Fault function.

2.4 Station Transformer bays

The following Logical Nodes, as defined in IEC 61850, are required for ST
bay.

Transformer differential protection (PDIF, 87T) triple pole type with

faulty phase identification, percentage bias restraint for through faults,
second harmonic restraint for transformer inrush

Restricted earth fault protection (PDIF, 64R) for HV, LV1 & LV2

Standby earth fault protection (PTEF, 51N) for LV1 & LV2

Backup over current Protection (PTOC,51)

Over excitation protection (PVPH, 24(99))

Trip Circuit Supervision

Disturbance Recording, bay level acquisition (RDRE), with 8 analog

and 16 digital

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Sequential event recorder (RDRE) with time resolution of 1 ms

Breaker, isolator and earth switch control (CSWI)

Synchronizing and energizing check (RSYN, 25)

Bay level and inter bay interlocks (CILO)

Transformer tap changer control (ATCC, only manual mode)

Measurement of voltages, currents, frequency, active power, reactive

power, winding temperature and tap position (MMXU)

Local HMI (IHMI)

The primary equipment LNs used in this bay are:

Circuit breaker (XCBR)

Isolators (XSWI)

Earth switches (XSWI)

Power Transformer (YPTR)

Current transformer (TCTR)

Voltage transformer (TVTR)

As in the case of line bays, these LNs are hardwired inputs and outputs of the
control and protection IEDs.

2.4.1 Description of ST bay functionality

2.4.1.1 Transformer differential protection (PTDF, 87T)

The differential function for two winding and three winding transformers is
provided with internal CT ratio matching and vector group compensation,
which allows connection directly to star connected main CTs. Zero sequence
current elimination is made internally in the software.

All current inputs are provided with percentage bias restraint features, making
RET670 suitable for two or three winding transformers in multi-breaker station
arrangements.

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The setting facilities cover applications of the differential protection to all types
of power transformers and autotransformers with or without onload tap-
changer. An adaptive stabilizing feature is included for heavy through-faults.

Stabilization is included for inrush currents respectively for over-excitation

condition. Adaptive stabilization is also included for system recovery inrush
and CT saturation for external faults. A fast high set unrestrained differential
current protection is included for very high speed tripping at high internal fault
currents.

Innovative sensitive differential protection feature, based on the theory of

symmetrical components, offers best possible coverage for power transformer
windings turn-to-turn faults.

2.4.1.2 Restricted earth fault prot

protection
ection (PNDF, 87N)
The high impedance differential protection can be used when the involved CT
cores have same turn ratio and similar magnetizing characteristic. It utilizes
an external summation of the phases and neutral current and a series resistor
and a voltage dependent resistor externally to the relay. The function should
preferable be used on dedicated CT cores.

2.4.1.3 Transformer over current protection (PTOC, 51)

The four step three phase overcurrent function has an inverse or definite time
delay independent for each step separately. All IEC and ANSI time delayed
characteristics are available together with an optional user defined time
characteristic. The function can be set to be directional or non-directional
independently for each of the steps.

2.4.2 Implementation of Station Transformer bay functionality

For transformer protection, the IED selected is ABB make RET 670. The bay
control IED is ABB make REC 670, with built in mimic. The bay control IED is
designed to control (switch ON / OFF), along with all necessary interlocks.

All intra-bay interlocks are software based and performed by the BCU. The
complete bay can be monitored and controlled from the local HMI on the
BCU. Additionally, hardwired switches are provided to operate the breaker
during emergencies. During such emergency operations all interlocks are
bypassed. Station wide interlocks are software based; the data for the
interlocks are transmitted using GOOSE messages by the individual IEDs.

The transformer protection functions are explained above.

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The distribution of LNs in the various IEDs is shown:

RET 670-
670-1 RET 670-
670-2
REC 670
PDIF PTEF PDIF PTEF
CSWI RSYN
PTOC
CSWI RDRE

CSWI MMXU
RDRE RDRE
CILO IHMI

XCBR
TCTR XCBR TCTR XCBR TCTR
XSWI
YPTR TVTR YPTR TVTR
XSWI TVTR

RET 670-
670-3

PDIF PVPH

RDRE RBRF

XCBR TCTR

YPTR TVTR

Figure 3: Configuration of 400 kV ST bay IEDs

2.5 Generator, Generator Transformer, UT bays

The following Logical Nodes, as defined in IEC 61850, are required for GT
bay.

Generator Differential Protection (PDIF, 87G)

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Overall differential protection (PDIF, 87GT)

Pole Slip Protection (PPAM ,78)

Loss of Excitation (PDIS, 40)

Backup Impedance Protection ( PDIS,21G)

Directional Over Power Protection (Reverse Power) (PDOP, 32)

Directional Under Power Protection (Low Forward Power) (PDUP, 37)

Rotor Earth Fault Protection based on injection principle (64F)

Negative Sequence Protection (46G)

Stator Earth Fault Protection (100%) based on low frequency injection

principle (64G1)

Stator Earth Fault Protection (95%) ( 64G2)

Over Voltage Protection (PTOV, 59G)

Under Frequency ( PTUF, 81G)

Dead Machine Protection ( 50GDM)

Generator Transformer differential protection (PDIF, 87T)

Overhang Differential protection ( PDIF, 87HV)

Over Excitation Protection (PVPH, 99)

UT Differential Protection (PDIF, 87UT)

UT backup Over current Protection (PTOC,51UT)

UT LV Restricted Earth Fault ( PDIF, 64UT)

UT Backup Earth Fault ( PTEF, 51UT)

Fuse failure supervision (RFUF, 60)

Trip Circuit Supervision (PTRC,94)

Disturbance Recording, bay level acquisition (RDRE), with 8 analog

and 16 digital
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Sequential event recorder (RDRE) with time resolution of 1 ms

Breaker, isolator and earth switch control (CSWI)

Synchronizing and energizing check (RSYN, 25)

Bay level and inter bay interlocks (CILO)

Measurement of voltages, currents, frequency, active power, reactive

power, winding temperature and tap position (MMXU)

Local HMI (IHMI)

The primary equipment LNs used in this bay are:

Circuit breaker (XCBR)

Isolators (XSWI)

Earth switches (XSWI)

Current transformer (TCTR)

Voltage transformer (TVTR)

As in the case of line bays, these LNs are hardwired inputs and outputs of the
control and protection IEDs.

2.5.1 Description of GT bay functionality

Functions not described earlier under Line bay functionality are described
below. The functions PDEF, RDRE, CSWI, CILO, MMXU and IHMI are
identical to the functions of the Line bay.

2.5.1.1 Transformer differential protection (PTDF, 87T)

The differential function for two winding and three winding transformers is
provided with internal CT ratio matching and vector group compensation,
which allows connection directly to star connected main CTs. Zero sequence
current elimination is made internally in the software.

All current inputs are provided with percentage bias restraint features, making
RET670 suitable for two or three winding transformers in multi-breaker station
arrangements.

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The setting facilities cover applications of the differential protection to all types
of power transformers and autotransformers with or without onload tap-
changer. An adaptive stabilizing feature is included for heavy through-faults.

Stabilization is included for inrush currents respectively for over-excitation

condition. Adaptive stabilization is also included for system recovery inrush
and CT saturation for external faults. A fast high set unrestrained differential
current protection is included for very high speed tripping at high internal fault
currents.

Innovative sensitive differential protection feature, based on the theory of

symmetrical components, offers best possible coverage for power transformer
windings turn-to-turn faults.

2.5.1.2 Restricted earth fault prot

protection
ection (PNDF, 87N)
The high impedance differential protection can be used when the involved CT
cores have same turn ratio and similar magnetizing characteristic. It utilizes
an external summation of the phases and neutral current and a series resistor
and a voltage dependent resistor externally to the relay. The function should
preferable be used on dedicated CT cores.

2.5.1.3 Standby Earth fault Protection (TEF, 51N)

All IEC and ANSI time delayed characteristics are available together with an
optional user defined characteristic. The function can be set to be directional
or nondirectional independently for each of the steps. A second harmonic
blocking can be set individually for each step.

Directional operation can be combined together with corresponding

communication blocks into permissive or blocking teleprotection scheme.
Current reversal and weak-end in-feed functionality are available as well. The
function can be configured to measure the residual current from the three
phase current inputs or the current from a separate current input.

2.5.1.4 Over excitation protection (PVPH, 24)

The functions is provided with IEEE standard inverse curves and have also
possibility to set a user defined characteristic when the transformer over
excitation capability curves are available. The function has also an alarm level
for early warnings.

The function shall be connected to transformer windings without any tap

changer. The function can measure on the positive sequence voltage or a
phase-to-phase voltage. The voltage has also a voltage drop function where
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the load current voltage drop is compensated for to get a fully true flux
measurement. The over excitation function measures the U/f ratio which gives
a measure of the magnetic flux in transformers and generators.

2.5.2 Implementation of Generator, Generator Transformer and UT bay

functionality
For Generator, GT protection, the IED selected is ABB make REG 670. For
Main2 GT protection Siemens make 7UM622 is used.

The protection functions are explained above.

The distribution of LNs in the various IEDs is shown:

Figure 4: Configuration of 400 kV GT bay IEDs

REG670
REG670/7UM622
670/7UM622 RET 670-
670-1 RET 670
670-2

PDIF PTOC PDIF

PDIF

PDIS RFUF

PDOP PDUP

PTOV RDRE PTEF

PPAM RDRE

TCTR
XCBR TCTR
XCBR TCTR
XCBR TVTR YPTR TVTR
YPTR TVTR

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RET 670-
670-3 RET 670-
670-4 RET 670-
670-5

PDIF PDIF PTEF PTOC PTEF

RDRE RDRE RDRE

XCBR TCTR XCBR TCTR XCBR TCTR

YPTR TVTR YPTR TVTR YPTR TVTR

Note: The configurations shall be as per approved GRP Scheme.

2.5.3 Bus bar protection IED REB 670

The REB 670 IED (Intelligent Electronic Device) is designed for the protection
and monitoring of busbars, T-connections and meshed corners from medium
to extra high voltage levels. Due to its extensive I/O capability, REB 670
protects single and double busbars with or without transfer bus, double circuit
breaker or one-and-half circuit breaker arrangements.

It provides selective, reliable and fast fault clearance for all types of internal
phase-to-phase and phase-to-earth faults in solidly earthed or low-impedance
earthed power systems. This IED features extremely short operate time,
typically 12 ms, for most internal faults regardless of number of connected
feeders. At the same time, it maintains complete stability for external faults,
even when heavy CT saturation occurs. It can also handle all internal multi-
phase faults in isolated or high-impedance earthed power systems.

REB 670 provides complete busbar protection including differential protection

and flexible software based dynamic zone selection (disconnector replica)
integrated in one IED. This enables dynamic CT connections to differential
zones, as well as selective busbar and breaker failure tripping, disconnector
and circuit breaker status supervision. Due to its unique measuring principle,
this IED has very low CT requirements compared to other numerical
differential protection.
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The distribution of the LNs in the REB 670 is shown below

REB 670
PBDF RBRF

XCBR TCTR

XSWI RDRE

XSWI

Figure
Figure 5: Configuration of 400 kV REB 670

2.5.3.1 Busbar protection (PBDF, 87B)

The protection algorithms are based on two well-proven measuring principles,
which have been applied successfully in earlier ABB low impedance bus bar
protection systems:

stabilized differential current measurement

determination of phase relationship between feeder currents (phase

comparison)

Any DC component and harmonics are suppressed. The first measuring

principle uses a stabilized differential current algorithm. The currents are
evaluated individually for each of the phases and each section of bus bar.

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PCM600 Project Aspects

PCM600 STARTUP

REVISION TABLE

Rev. No Revision Note Approved Week

0 Original Document

We reserve all rights in this document and in the information contained therein. Reproduction, use or disclosure to third parties
without express authority is strictly forbidden. Copyright © by ABB Limited

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1MYN900031-001
PCM600 Project Aspects

Table of Contents:
1 About This Document.......................................................................................... 4

1.1 Applicable Version ....................................................................................... 4

1.1.1 PCM 600............................................................................................... 4

2 Engineering Workflow ......................................................................................... 5

2.1 Project structure........................................................................................... 5

3 Communication Settings ................................................................................... 11

3.1 Implementation Guidelines......................................................................... 11

4 CAP 531............................................................................................................ 13

4.1 Application Configuration ........................................................................... 13

Table of Figures:
Figure 1: PCM 600 Display ........................................................................................ 4

Figure 2: Main Menu .................................................................................................. 5

Figure 3: New Project................................................................................................. 5

Figure 4: Project name definition................................................................................ 5

Figure 5: New project added to the database............................................................. 6

Figure 6: Region definition ......................................................................................... 6

Figure 7: Substation definition.................................................................................... 6

Figure 8: Voltage level definition ................................................................................ 7

Figure 9: Bay definition............................................................................................... 7

Figure 10: Addition of IED .......................................................................................... 8

Figure 11: REC 670 – Technical Key ......................................................................... 8

Figure 12: Configuration Wizard................................................................................. 9

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PCM600 Project Aspects

Figure 13: Version Selection ...................................................................................... 9

Figure 14: Protocol Selection ................................................................................... 10

Figure 15: IP Address Definition............................................................................... 10

Figure 16: Communication configuration completed ................................................ 10

Figure 17: Internet protocol (TCP/IP) properties ...................................................... 11

Figure 18: Application Configuration ........................................................................ 13

Figure 19: CAP 531.................................................................................................. 13

Figure 20: Insertion of a new worksheet................................................................... 14

Figure 21: Naming the worksheet ............................................................................ 14

Figure 22: Useful Graphical Symbols ....................................................................... 15

Figure 23: Addition of text into the sheet .................................................................. 15

Figure 24: Addition of Function Block....................................................................... 16

Figure 25: Parameter ............................................................................................... 16

Figure 26: Variables ................................................................................................. 17

Figure 27: Cross References ................................................................................... 17

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PCM600 Project Aspects

1 About This Document

This guide is concerned with aiding the user in the configuration of the IED using PCM600.

1.1 Applicable Version

This guide is prepared using PCM600 with SP1 Revision 11. The same procedure is
applicable to previous versions also.

1.1.1 PCM 600

Protection and Control IED Manager (PCM 600) is an easy-to-handle tool providing versatile
functionalities required throughout the life cycle of ABB's protection and control IEDs in
transmission and distribution applications. Its Microsoft Windows based user interface with
many familiar and easy-to-use functions adds to operating comfort. PCM 600 features fast
and reliable downloading and uploading of configuration and settings as well as uploading of
disturbance files both locally and remotely. It utilizes TCP/IP via corporate LAN or WAN, or
alternatively directly through the communication port at the front of the IED.

Figure 1: PCM 600 Display

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PCM600 Project Aspects

2 Engineering Workflow
The step-by-step procedure for creating a new project is shown below.

2.1 Project structure

Step 1: Go to File
Open/ Manage Project.

Figure 2: Main Menu

Figure 3: New Project

Step 2: Enter the Project name

Figure 4: Project name definition

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PCM600 Project Aspects

Figure 5: New project added to the database

Step 3: After defining the project, region is to be defined.

Figure 6: Region definition

Step 4: Create a new Substation. In the Object Properties edit the caption as AA1.

Figure 7: Substation definition

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PCM600 Project Aspects

Step 5: Create the voltage level. Choose the voltage level from the Voltage Range in the
Object properties. For example, the voltage level selected here is 220kV. The technical
Key is AA1D1.

Figure 8: Voltage level definition

Step 6: Create a new bay. Change the caption to corresponding bay name. For example,
The bay name here is Q01.

Figure 9: Bay definition

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PCM600 Project Aspects
Step 7: The appropriate IEDs are taken. For Example, here REC 670 IEC Version 1.1 is
chosen.

Figure 10: Addition of IED

Step 8: The Technical Key should be matching with the created structure. For REC, the key
shall end with A1. For Protection device, it should be FP1.

Figure 11: REC 670 – Technical Key

NOTE: The IED type will be Generic IED initially. Once the IED is configured using
configuration wizard, it will change to IED670.

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PCM600 Project Aspects
Step 9: Right click on the IED. Go to Configuration Wizard.

Figure 12: Configuration Wizard

Step 10: Choose the appropriate version of the IED.

Figure 13: Version Selection

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PCM600 Project Aspects
Step 11: Then, IED Protocol should be selected.

Figure 14: Protocol Selection

Figure 15: IP Address Definition

Figure 16: Communication configuration completed

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PCM600 Project Aspects

3 Communication Settings
Each IED is provided with a communication interface, enabling it to connect to one or many
substation level systems or equipment, either on the Substation Automation (SA) bus or
Substation Monitoring (SM) bus. Establishing the communication between the relays is very
vital in the substation automation system for horizontal and vertical communication. Single or
double optical Ethernet ports for the new substation communication standard IEC61850-8-1
for the station bus are provided and one RJ 45 port is available for programming and setting
of the relays.

3.1 Implementation Guidelines

1. Make sure the optical cables used for communication is healthy and not broken anywhere.
2. For front communication use cross cables (i.e) to download the configuration through front
port.

3. Make sure the relay IP address matches with that of in the configuration before establishing
communication.
4. Ensure that the system IP address should match with relay subnet masking.
5. Go to network settings and set the TCP/IP properties as shown below. The IP address is
obtained from the architectural drawing made in visio using IET.

Figure 17: Internet protocol (TCP/IP) properties

Note: There should not be IP address conflict within the network.

6. To set IP address for the relay :
Go to Setting
General Setting
communication
TCP/IP configuration
Front port/

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PCM600 Project Aspects Sale Order :
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PS-SAS Created 2008.05.04 Revision 0 Yr 07 Wk 01
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PCM600 Project Aspects
Rear OEM-port AB. IEC61850-8-1 operation is made ON. This can be made directly from the
HMI or right click on the IED
Parameter Settings. Change the PC value and can be loaded
to the IED.

Figure 18: Internet protocol (TCP/IP) properties

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PCM600 Project Aspects

4 CAP 531
The IED is configured using CAP531 (Configuration and Programming tool).

4.1 Application Configuration

The step-by-step procedure for using CAP tool is described below.

Step 1: Right click on the IED. Go to Application configuration.

Figure 19: Application Configuration

Step 2: This screen will appear. Type the password as “abb”. It is not case-sensitive.

Figure 20: CAP 531

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PCM600 Project Aspects
Step 3: Click on the IED. Go to Edit
Insert. This is to insert a new worksheet. Give a name
to the worksheet.

Figure 21: Insertion of a new worksheet

Figure 22: Naming the worksheet

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PCM600 Project Aspects Sale Order :
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PCM600 Project Aspects

Figure 23: Useful Graphical Symbols

Step 5: To enter a text on the worksheet, click on the “T” symbol shown. Double click on the
sheet. The font properties can be edited.

Figure 24: Addition of text into the sheet

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PCM600 Project Aspects
Step 6: To add a function block into the worksheet, press “ F” on the worksheet or click on the
symbol that is shown in the toolbar. Choose the required function block from the list.

Figure 25: Addition of Function Block

For example, SMAI block is added here. Pink color represents the parameters. To edit the
name, just press “ P ”.

Figure 26: Parameter

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PCM600 Project Aspects

Figure 27: Variables

Figure 28: Cross References

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 LARSEN & TOUBRO LIMITED
ECC DIVISION, EDRC – Electrical

Project 400/220kV GIS SWITCHYARD PACKAGE FOR VALLUR THERMAL POWER PROJECT (2x500MW + 1x500MW)
Client NTPC TAMILNADU ENERGY COMPANY LIMITED (NTECL)
Consultant -
Title COMPLIANCE REPORT FOR FUNCTIONAL DESIGN SPECIFICATION OF SAS. Date: 18.11.09
Ref. As per NTPC comments Dt: 04.11.09

Sl.No NTECL’s Comments ABB’s Reply

Comments have been marked in the drawing. Please append with the
marked comments wherever required. Please note that with respect to
1. approved FDS for Jhajjar required inputs/descriptions in detail as
Noted. Complied
commented for Vallur shall be included.
Please include references made in the document here with respect to
Technical Specifications E11, SAS Configuration Diagram, Control &
2. Protection Schemes as applicable for the project and Catalogues and Complied.
Technical Reference Manuals of IEDs and Micro SCADA. Please refer
approved FDS for Jhajjar for this.
Switchyard Control Room:
• How many? (Engg. & DR Station)
• One number.
3. • Master metering station to which all the meters are configured
• Complied.
through MODBUS
• Four Nos. Indicated in FDS.
• Modems?
Also include CER as one more functional part of SAS functional
4. description. Please specify it as one CER for each unit. Provide Complied.
reference to SAS architecture in the tender drawing.
System Design:
5. Chapter E-11 instead of Chapter E-10.
Complied.

Please provide details for each bay IED here also. Provide this details
6. bay wise. Please refer approved FDS for Jhajjar for this.
Complied.

Include details for interlocking function of the IEDs along with the
7. required functions for this. Please refer approved FDS for Jhajjar for Complied.
this.

Page 1 of 5
 LARSEN & TOUBRO LIMITED
ECC DIVISION, EDRC – Electrical

Project 400/220kV GIS SWITCHYARD PACKAGE FOR VALLUR THERMAL POWER PROJECT (2x500MW + 1x500MW)
Client NTPC TAMILNADU ENERGY COMPANY LIMITED (NTECL)
Consultant -
Title COMPLIANCE REPORT FOR FUNCTIONAL DESIGN SPECIFICATION OF SAS. Date: 18.11.09
Ref. As per NTPC comments Dt: 04.11.09

There is no limit on the no. of GOOSE messages to be transmitted (multicast)

while for receiving; it is dependent on implementation in the IED.

There is no necessity of information storage in this case as the GOOSE

messages are transmitted and received based on set priority and storage of
data on data bus has no relevance here.

For information on the frame and interpretation of the same, the standard
(61850-1) may be referred to. Same can be explained during FAT.

W.r.t the time taken for traverse of GOOSE messages: Latency of the
Please describe in detail with respect to the speed and the limit on Ethernet communication network is the time taken to traverse the message
number of goose messages sent/receive by any IED. Please clarify if form the transmitter to the receiver. The prominent sources of latency in an
there is any limit with respect to information storage with respect to this. Ethernet switched communication network are:
8. Also include the details regarding, how each device identify and
interprets the information, its source and meaning. Please ensure that (a) Store and Forward Latency L(SF) which is directly proportional to the size
each detail shall provide discrete example for the communication of the frame being transmitted and inversely proportional to the baud rate.
between the devices. L(SF) = FS/BR. It is approx 0.120ms for baud rate of 100MPBS and the
maximum frame size.
(b) Switch Fabric Latency L(SW) which is switch dependent and internal to
the switch. It is approx 0.0052ms for RuggedCOM make switch.
(c) Wireline Latency L(WL). Predominant in long distances of networks of
approx 100KM. In the present case it is insignificant as the distance is less
than a KM.
(d) Queuing Latency L(Q). Depends upon the traffic patterns of the network.
L(Q) = Network Load x L(SF). Most of the cases the no of IEDs connected
are in such a way that the network load is less than about 25% on an
average. The basis for bus loading calculation is as per IEC61850-5

Page 2 of 5
 LARSEN & TOUBRO LIMITED
ECC DIVISION, EDRC – Electrical

Project 400/220kV GIS SWITCHYARD PACKAGE FOR VALLUR THERMAL POWER PROJECT (2x500MW + 1x500MW)
Client NTPC TAMILNADU ENERGY COMPANY LIMITED (NTECL)
Consultant -
Title COMPLIANCE REPORT FOR FUNCTIONAL DESIGN SPECIFICATION OF SAS. Date: 18.11.09
Ref. As per NTPC comments Dt: 04.11.09

The first three latency values are deterministic while queuing latency is non-
deterministic. Based on the above, L(TOTAL) = [L(SF)+L(SW)+L(WL)+L(Q)] x
No of switches in the network.
L(Q) can be calculated as {[(FS) x No of Ports] / BR (MBPS)}. For a 8 port
switch L(Q) is {[(12288) x 7] / 100} = 0.86ms.
Calculating the latency per switch for the given application for the worst case
conditions with the largest frame size L(TOTAL) = [0.120 + 0.0052 + 0 + 0.86]
= 0.9852ms. For a ring of 21 switches, the worst case latency would be
approx 20.6ms for the longest route and the highest frame size and fully
loaded bus. Which means the switch latency for one subnet in the present
application is less than 4ms considering 25% bus load on an average.

Communication infrastructure with respect to the communication shall

9. be added here. Please refer approved FDS for Jhajjar for this.
Please refer clause no. 4.2.3 of the FDS for same.

Please specify whether editing is password protected and if yes, then

10. confirm the same through series of steps with one example. No. It is not password protected.

The output pulse from the protection function block may be short which may
not be sufficient enough for the trip coil to energise. Hence, all the protection
Tripping Logic & Trip Matrix Logic (PTRC, 94):
11. Please provide detailed description outputs are connected to the PTRC block thereby extending the pulse
duration ensuring correct operation of all functions.
Same is included & explained in clause no 4.1.3 of the FDS.
Please provide details about PCM 600. Also highlight if soft logic
12. preparation is also through PCM600, if yes, please provide the steps Kindly refer the attached Annexure-PCM.
and difference with reference to PST.
Process display for processes with dynamic behaviour shall be
13. included. Display in the form of SLD shall also be included. Please refer Complied.
approved FDS for Jhajjar for this.

Page 3 of 5
 LARSEN & TOUBRO LIMITED
ECC DIVISION, EDRC – Electrical

Project 400/220kV GIS SWITCHYARD PACKAGE FOR VALLUR THERMAL POWER PROJECT (2x500MW + 1x500MW)
Client NTPC TAMILNADU ENERGY COMPANY LIMITED (NTECL)
Consultant -
Title COMPLIANCE REPORT FOR FUNCTIONAL DESIGN SPECIFICATION OF SAS. Date: 18.11.09
Ref. As per NTPC comments Dt: 04.11.09
Please confirm with the manufacturers limit on the number of metering
14. inputs to the converter? i.e. how many meters can be connected to the 32 meters can be connected.
converter?
On the capacity please provide the number of inputs able to connect
There are 20 ports available in the Ethernet switch. All the ports can be
15. through one Ethernet switch. Also if possible one diagram with terminal
used.
detail for the Ethernet switch can be provided here.
Please confirm if history for the changes made in the previous login is
also available in the SYS600 software. If yes, please specify how many
16. and through which login the data has been changed? Is this all also
Yes. The same thing can be viewed in the Event list
configured through the software?
"HOT" -The application is running. Its databases are stored
in the primary memory.
"WARM" -The application is not running, but the databases
17. Define HOT ,WARM & COLD state. are loaded and accessible.
"COLD" -The application is not running and not accessible,
but it may receive file shadow input from another
Application.
Please clarify if this (Display builder) operation is active even after the
18. users have been assigned view level? No. That option will be freezed for View level user.

Please provide brief description of these (update, control alarm..etc) Please refer the Clause 4.3.9 of FDS for the same and hence these are set in
19. blocking operations. What will each of these actions react as? the blocking Tab submenu.
These are not interlocks. Forced operation option will force the objects to
operate on your command even if another user is connected to them or the
Please describe these two interlockings?
20. (Internal Blockings & Control Blockings) function is normally not permitted. However, this does not disable any
interlockings or other IED measures, that is, no special bypass messages are
sent to the IEDs.
Forced operation does not disable any interlockings or other IED measures,
Please ensure/confirm that the Forced Operation does not bypass the
21. interlock as built within the IED. that is, no special bypass messages are sent to the IEDs.

Page 4 of 5
 LARSEN & TOUBRO LIMITED
ECC DIVISION, EDRC – Electrical

Project 400/220kV GIS SWITCHYARD PACKAGE FOR VALLUR THERMAL POWER PROJECT (2x500MW + 1x500MW)
Client NTPC TAMILNADU ENERGY COMPANY LIMITED (NTECL)
Consultant -
Title COMPLIANCE REPORT FOR FUNCTIONAL DESIGN SPECIFICATION OF SAS. Date: 18.11.09
Ref. As per NTPC comments Dt: 04.11.09
Based on the functions the Alarms can be prioritised into different alarm
classes.
The base system software does not make any distinction between the
classes, but applications may use alarm classes to categorise alarms,
The application engineer can choose how to group the objects in alarm
22. Can the priority be defined among different alarm classes? classes. They can, for example, be grouped based on the location of the
process objects or alarm
severity. An object with alarm class 0 has no alarm function.
Changing AC from 0 to another value or vice versa does not affect the alarm
state of the object.

23. Are these commands set from blocking tab sub-menu? Yes.

Please clarify that trends are to be defined by the user or shall these be
24. defined by the system by default/ could these be configurable? The trend are to be defined by the user and the same is configurable.

Please ensure that bay level details shall be as per the protection
25. scheme for each bay. This shall be ensure for all the bays. Complied.

26. Clearly highlight that this is only for line bays. Complied.

27. Three phase Complied.

Please ensure that all this descriptions for all the bays shall confirm
28. with the protection scheme with each bay. Complied.

Page 5 of 5