P341

Technical Guide TG8617AMiCOM P341

Interconnection Protection Relay

Technical GuideMiCOM P341


Volume 1

TECHNICAL GUIDE TG8617AMiCOM P341 Volume 1INTERCONNECTION PROTECTION RELAY Contents

HANDLING OF ELECTRONIC EQUIPMENT

SAFETY SECTION

CHAPTER 1 INTRODUCTION

CHAPTER 2 APPLICATION NOTESIncludes Publication R6617,P341 Interconnection Protection Relay

CHAPTER 3 RELAY DESCRIPTION

CHAPTER 4 TECHNICAL DATA

CHAPTER 5 SCADA COMMUNICATIONS

APPENDIX A COURIER DATA BASE

APPENDIX B EXTERNAL CONNECTION DIAGRAMS



HANDLING OF ELECTRONIC EQUIPMENT

A person's normal movements can easily generate electrostatic potentials of several thousand volts.Discharge of these voltages into semiconductor devices when handling electronic circuits can causeserious damage, which often may not be immediately apparent but the reliability of the circuit will havebeen reduced.

The electronic circuits of ALSTOM T&D Protection & Control Ltd products are immune to the relevant levelsof electrostatic discharge when housed in their cases. Do not expose them to the risk of damage bywithdrawing modules unnecessarily.

Each module incorporates the highest practicable protection for its semiconductor devices. However, if itbecomes necessary to withdraw a module, the following precautions should be taken to preserve the highreliability and long life for which the equipment has been designed and manufactured.

1. Before removing a module, ensure that you are at the same electrostatic potential as the equipmentby touching the case.

2. Handle the module by its front-plate, frame, or edges of the printed circuit board.Avoid touching the electronic components, printed circuit track or connectors.

3. Do not pass the module to any person without first ensuring that you are both at the sameelectrostatic potential. Shaking hands achieves equipotential.

4. Place the module on an antistatic surface, or on a conducting surface which is at the samepotential as yourself.

5. Store or transport the module in a conductive bag.

More information on safe working procedures for all electronic equipment can be found in BS5783 andIEC 60147-0F.

If you are making measurements on the internal electronic circuitry of an equipment in service, it ispreferable that you are earthed to the case with a conductive wrist strap.Wrist straps should have a resistance to ground between 500k – 10M ohms. If a wrist strap is notavailable, you should maintain regular contact with the case to prevent the build up of static.Instrumentation which may be used for making measurements should be earthed to the case wheneverpossible.

ALSTOM T&D Protection & Control Ltd strongly recommends that detailed investigations on the electroniccircuitry, or modification work, should be carried out in a Special Handling Area such as described inBS5783 or IEC 60147-0F.

SAFETY SECTION

This Safety Section should be read before commencing any work onthe equipment.

Health and safety

The information in the Safety Section of the product documentation is intended toensure that products are properly installed and handled in order to maintain themin a safe condition. It is assumed that everyone who will be associated with theequipment will be familiar with the contents of the Safety Section.

Explanation of symbols and labels

The meaning of symbols and labels which may be used on the equipment or in theproduct documentation, is given below.

Caution: refer to product documentation Caution: risk of electric shock

Protective/safety *earth terminal

Functional *earth terminal.Note: this symbol may also be used for a protective/safety earth terminal if that terminal is part of aterminal block or sub-assembly eg. power supply.

*Note:The term earth used throughout the product documentation is the directequivalent of the North American term ground.

Installing, Commissioning and ServicingEquipment connections

Personnel undertaking installation, commissioning or servicing work on thisequipment should be aware of the correct working procedures to ensure safety.The product documentation should be consulted before installing, commissioning orservicing the equipment.

Terminals exposed during installation, commissioning and maintenance maypresent a hazardous voltage unless the equipment is electrically isolated.

If there is unlocked access to the rear of the equipment, care should be taken by allpersonnel to avoid electric shock or energy hazards.

Voltage and current connections should be made using insulated crimpterminations to ensure that terminal block insulation requirements are maintainedfor safety. To ensure that wires are correctly terminated, the correct crimp terminaland tool for the wire size should be used.

Before energising the equipment it must be earthed using the protective earthterminal, or the appropriate termination of the supply plug in the case of plugconnected equipment. Omitting or disconnecting the equipment earth may cause asafety hazard.

The recommended minimum earth wire size is 2.5 mm2, unless otherwise stated inthe technical data section of the product documentation.

Before energising the equipment, the following should be checked:

Voltage rating and polarity;

CT circuit rating and integrity of connections;

Protective fuse rating;

Integrity of earth connection (where applicable)

Equipment operating conditions

The equipment should be operated within the specified electrical andenvironmental limits.

Current transformer circuits

Do not open the secondary circuit of a live CT since the high voltage producedmay be lethal to personnel and could damage insulation.

External resistors

Where external resistors are fitted to relays, these may present a risk of electricshock or burns, if touched.

Battery replacement

Where internal batteries are fitted they should be replaced with the recommendedtype and be installed with the correct polarity, to avoid possible damage to theequipment.

Insulation and dielectric strength testing

Insulation testing may leave capacitors charged up to a hazardous voltage. At theend of each part of the test, the voltage should be gradually reduced to zero, todischarge capacitors, before the test leads are disconnected.

Insertion of modules and pcb cards

These must not be inserted into or withdrawn from equipment whilst it is energised,since this may result in damage.

Fibre optic communication

Where fibre optic communication devices are fitted, these should not be vieweddirectly. Optical power meters should be used to determine the operation or signallevel of the device.

Decommissioning and DisposalDecommissioning: The auxiliary supply circuit in the relay may include

capacitors across the supply or to earth. To avoid electricshock or energy hazards, after completely isolating thesupplies to the relay (both poles of any dc supply), thecapacitors should be safely discharged via the externalterminals prior to decommissioning.

Disposal: It is recommended that incineration and disposal to watercourses is avoided. The product should be disposed of in asafe manner. Any products containing batteries should havethem removed before disposal, taking precautions to avoidshort circuits. Particular regulations within the country ofoperation, may apply to the disposal of lithium batteries.

Technical SpecificationsProtective fuse rating

The recommended maximum rating of the external protective fuse for thisequipment is 16A, Red Spot type or equivalent, unless otherwise stated in thetechnical data section of the product documentation.

Insulation class: IEC 601010-1: 1990/A2: 1995 This equipment requires aClass I protective (safety) earthEN 61010-1: 1993/A2: 1995 connection to ensure userClass I safety.

Installation IEC 601010-1: 1990/A2: 1995 Distribution level, fixedCategory Category III installation. Equipment in(Overvoltage): EN 61010-1: 1993/A2: 1995 this category is qualification

Category III tested at 5kV peak,1.2/50µs, 500Ω, 0.5J,between all supply circuitsand earth and also betweenindependent circuits.

Environment: IEC 601010-1:1990/A2: 1995 Compliance is demonstratedPollution degree 2 by reference to genericEN 61010-1: 1993/A2: 1995 safety standards.Pollution degree 2

Product safety: 73/23/EEC Compliance with theEuropean Commission LowVoltage Directive.

EN 61010-1: 1993/A2: 1995 Compliance is demonstratedEN 60950: 1992/A11: 1997 by reference to generic

safety standards.



Chapter 1Introduction

TECHNICAL GUIDE TG8617AMiCOM P341 Volume 1INTERCONNECTION PROTECTION RELAY Chapter 1

ContentsPage 1 of 1

1. INTRODUCTION TO MICOM 12. INTRODUCTION TO MICOM GUIDES 23 USER INTERFACES AND MENU STRUCTURE 43.1 Introduction to the relay 43.1.1 Front panel 43.1.2 Relay rear panel 53.2 Introduction to the user interfaces and settings options 63.3 Menu structure 83.3.1 Protection settings 93.3.2 Disturbance recorder settings 93.3.3 Control and support settings 93.4 Password protection 93.5 Relay confirguration 103.6 Front panel user interface (keypad and LCD) 113.6.1 Default display and menu time-out 123.6.2 Menu navigation and setting browsing 123.6.3 Password entry 123.6.4 Reading and clearing of alarm messages and fault records 133.6.5 Settings changes 133.7 Front communication port user interface 143.8 Rear communication port user interface 163.8.1 Courier communication 163.8.2 Modbus communication 183.8.3 IEC60807-5 CS 103 communication 20

Figure 1 Relay front view 4Figure 2 Relay rear view 6Figure 3 Menu structure 8Figure 4 Front panel user interface 11Figure 5 Front port connection 14Figure 6 PC – relay signal connection 15Figure 7 Remote communication connection arrangements 17


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Section 1. INTRODUCTION TO MiCOM

MiCOM is a comprehensive solution capable of meeting all electricity supplyrequirements. It comprises a range of components, systems and services fromALSTOM.

Central to the MiCOM concept is flexibility.

MiCOM provides the ability to define an application solution and, throughextensive communication capabilities, to integrate it with your power supplycontrol system.

The components within MiCOM are:

• P range protection relays;

• C range control products;

• M range measurement products for accurate metering and monitoring;

• S range versatile PC support and substation control packages.

MiCOM products include extensive facilities for recording information on the stateand behaviour of the power system using disturbance and fault records. They canalso provide measurements of the system at regular intervals to a control centreenabling remote monitoring and control to take place.

For up-to-date information on any MiCOM product, refer to the technicalpublication which can be obtained from:

ALSTOM T&D Protection & Control Ltd, or your local sales office. Alternatively visitour web site.


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Section 2. INTRODUCTION TO MICOM GUIDES

The guides provide a functional and technical description of the MiCOMprotection relay and a comprehensive set of instructions for the relay’s use andapplication.

Divided into two volumes, as follows:

Volume 1 – Technical Guide, includes information on the application of the relayand a technical description of its features. It is mainly intended for protectionengineers concerned with the selection and application of the relay for theprotection of the power system.

Volume 2 – Operation Guide, contains information on the installation andcommissioning of the relay, and also a section on fault finding. This volume isintended for site engineers who are responsible for the installation, commissioningand maintenance of the relay.

The chapter content within each volume is summarised below:

Volume 1 Technical Guide

Handling of Electronic Equipment

Safety Section

Chapter 1 Introduction

A guide to the different user interfaces of the protection relay describinghow to start using the relay.

Chapter 2 Application Notes (includes a copy of publication R6617)

Comprehensive and detailed description of the features of the relayincluding both the protection elements and the relay’s other functions such asevent and disturbance recording, fault location and programmable schemelogic. This chapter includes a description of common power systemapplications of the relay, calculation of suitable settings, some typical workedexamples, and how to apply the settings to the relay.

Chapter 3 Relay Description

Overview of the operation of the relay’s hardware and software. This chapterincludes information on the self-checking features and diagnostics of the relay.

Chapter 4 Technical Data

Technical data including setting ranges, accuracy limits, recommendedoperating conditions, ratings and performance data. Compliance withtechnical standards is quoted where appropriate.

Chapter 5 Communications and Interface Guide

This chapter provides detailed information regarding the communicationinterfaces of the relay, including a detailed description of how to accessthe settings database stored within the relay. The chapter also givesinformation on each of the communication protocols that can be used withthe relay, and is intended to allow the user to design a custom interface toa SCADA system.


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Appendix A Relay Menu Database: User interface/Courier/Modbus/IEC 60870-5-103

Listing of all of the settings contained within the relay together with a briefdescription of each.

Appendix B External Connection Diagrams

All external wiring connections to the relay.

Volume 2 Operation Guide

Handling of Electronic Equipment

Safety Section

Chapter 1 Introduction

A guide to the different user interfaces of the protection relay describinghow to start using the relay.

Chapter 2 Installation (includes a copy of publication R6617)

Recommendations on unpacking, handling, inspection and storage of therelay. A guide to the mechanical and electrical installation of the relay isprovided incorporating earthing recommendations.

Chapter 3 Commissioning and Maintenance

Instructions on how to commission the relay, comprising checks on thecalibration and functionality of the relay. A general maintenance policy forthe relay is outlined.

Chapter 4 Problem Analysis.

Advice on how to recognise failure modes and the recommended course ofaction.

Appendix A Relay Menu Database: User interface/Courier/Modbus/IEC 60870-5-103

Listing of all of the settings contained within the relay together with a briefdescription of each.

Appendix B External Connection Diagrams

All external wiring connections to the relay.


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Section 3. USER INTERFACES AND MENU STRUCTURE

The settings and functions of the MiCOM protection relay can be accessed bothfrom the front panel keypad and LCD, and via the front and rear communicationports. Information on each of these methods is given in this section to describe howto get started using the relay.

3.1 Introduction to the relay

3.1.1 Front panel

The front panel of the relay is shown in Figure 1, with the hinged covers at the topand bottom of the relay shown open. Extra physical protection for the front panelcan be provided by an optional transparent front cover. With the cover in placeread only access to the user interface is possible. Removal of the cover does notcompromise the environmental withstand capability of the product, but allowsaccess to the relay settings. When full access to the relay keypad is required, forediting the settings, the transparent cover can be unclipped and removed when thetop and bottom covers are open. If the lower cover is secured with a wire seal, thiswill need to be removed. Using the side flanges of the transparent cover, pull thebottom edge away from the relay front panel until it is clear of the seal tab.The cover can then be moved vertically down to release the two fixing lugs fromtheir recesses in the front panel.

Figure 1: Relay front view

User programablefunction LEDs

TRIP

ALARM

OUT OF SERVICE

HEALTHY

= CLEAR

= READ

= ENTER

SER No

DIAG No

Zn

Vx

Vn

V

V

1/5 A 50/60 Hz

SK1 SK2

Serial No and I*, V Ratings Top cover

FixedfunctionLEDs

Bottomcover

Battery compartment Front comms port Download/monitor port

Keypad

LCD

Note: *May vary according to relay type/model


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The front panel of the relay includes the following, as indicated in Figure 1:

• a 16-character by 2-line alphanumeric liquid crystal display (LCD).

• a 7-key keypad comprising 4 arrow keys ( , , , and ),an enter key (↵), a clear key (C), and a read key ( ).

• 12 LEDs; 4 fixed function LEDs on the left hand side of the front panel and 8programmable function LEDs on the right hand side.

Under the top hinged cover:

• the relay serial number, and the relay’s current and voltage rating information*.

Under the bottom hinged cover:

• battery compartment to hold the 1/2 AA size battery which is used for memoryback-up for the real time clock, event, fault and disturbance records.

• a 9-pin female D-type front port for communication with a PC locally to the relay(up to 15m distance) via an RS232 serial data connection.

• a 25-pin female D-type port providing internal signal monitoring and high speedlocal downloading of software and language text via a parallel dataconnection.

The fixed function LEDs on the left hand side of the front panel are used toindicate the following conditions:

Trip (Red) indicates that the relay has issued a trip signal. It is reset when theassociated fault record is cleared from the front display. (Alternatively the trip LEDcan be configured to be self-resetting)*.

Alarm (Yellow) flashes to indicate that the relay has registered an alarm. This maybe triggered by a fault, event or maintenance record. The LED will flash until thealarms have been accepted (read), after which the LED will change to constantillumination, and will extinguish when the alarms have been cleared.

Out of service (Yellow) indicates that the relay’s protection is unavailable.

Healthy (Green) indicates that the relay is in correct working order, and should beon at all times. It will be extinguished if the relay’s self-test facilities indicate thatthere is an error with the relay’s hardware or software. The state of the healthy LEDis reflected by the watchdog contact at the back of the relay.

3.1.2 Relay rear panel

The rear panel of the relay is shown in Figure 2. All current and voltage signals*,digital logic input signals and output contacts are connected at the rear of therelay. Also connected at the rear is the twisted pair wiring for the rear RS485communication port, the IRIG-B time synchronising input and the optical fibre rearcommunication port which are both optional.



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Figure 2: Relay rear view

Refer to the wiring diagram in Appendix B for complete connection details.

3.2 Introduction to the user interfaces and settings options

The relay has three user interfaces:

• the front panel user interface via the LCD and keypad.

• the front port which supports Courier communication.

• the rear port which supports one protocol of either Courier, Modbus orIEC 60870-5-103. The protocol for the rear port must be specified when therelay is ordered.

The measurement information and relay settings which can be accessed from thethree interfaces are summarised in Table 1.

D E FCBA

IRIG B

TX

PORT

1

RX

Optional IRIG-B board Digital input connections

Current* and voltageinput terminals

Digital output(relays) connections

Rear comms port(RS485)

Power supplyconnection



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Keypad/LCD Courier Modbus IEC60870Display & modification of • • •all settingsDigital I/O signal status • • • •Display/extraction of • • • •measurementsDisplay/extraction of • • •fault recordsDisplay/extraction of • • • •event & alarm recordsExtraction of disturbance • •recordsProgrammable scheme •logic settingsReset of fault & alarm • • • •recordsClear event & fault • • •recordsTime synchronisation • • •Control commands • • • •

Table 1



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3.3 Menu structure

The relay’s menu is arranged in a tabular structure. Each setting in the menu isreferred to as a cell, and each cell in the menu may be accessed by reference to arow and column address. The settings are arranged so that each column containsrelated settings, for example all of the disturbance recorder settings are containedwithin the same column. As shown in Figure 3, the top row of each columncontains the heading which describes the settings contained within that column.Movement between the columns of the menu can only be made at the columnheading level. A complete list of all of the menu settings is given in Appendix A ofthe manual.

Figure 3: Menu structure

All of the settings in the menu fall into one of three categories: protection settings,disturbance recorder settings, or control and support (C&S) settings. One of twodifferent methods is used to change a setting depending on which category thesetting falls into. Control and support settings are stored and used by the relayimmediately after they are entered. For either protection settings or disturbancerecorder settings, the relay stores the new setting values in a temporary‘scratchpad’. It activates all the new settings together, but only after it has beenconfirmed that the new settings are to be adopted. This technique is employed toprovide extra security, and so that several setting changes that are made within agroup of protection settings will all take effect at the same time.

Up to 4 protection setting groups

Columndata

settings

Column header

Control & support Group 1 Group 2

System data View records Overcurrent Ground fault Overcurrent Ground fault

Repeated for groups 2, 3 and 4



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3.3.1 Protection settings

The protection settings include the following items:

• protection element settings

• scheme logic settings

• auto-reclose and check synchronisation settings (where appropriate)*

• fault locator settings (where appropriate)*

There are four groups of protection settings, with each group containing the samesetting cells. One group of protection settings is selected as the active group, andis used by the protection elements.

3.3.2 Disturbance recorder settings

The disturbance recorder settings include the record duration and trigger position,selection of analogue and digital signals to record, and the signal sources thattrigger the recording.

3.3.3 Control and support settings

The control and support settings include:

• relay configuration settings

• open/close circuit breaker*

• CT & VT ratio settings*

• reset LEDs

• active protection setting group

• password & language settings

• circuit breaker control & monitoring settings*

• communications settings

• measurement settings

• event & fault record settings

• user interface settings

• commissioning settings

3.4 Password protection

The menu structure contains three levels of access. The level of access that isenabled determines which of the relay’s settings can be changed and iscontrolled by entry of two different passwords. The levels of access aresummarised in Table 2.



Page 10 of 21

Access level Operations enabled

Level 0 Read access to all settings, alarms, eventNo password required records and fault records.

Level 1 As level 0 plus:Password 1 or 2 required Control commands, e.g.

circuit breaker open/close.Reset of fault and alarm conditions.Reset LEDs.Clearing of event and fault records.

Level 2 As level 1 plus:Password 2 required All other settings.

Table 2

Each of the two passwords are 4 characters of upper case text. The factory defaultfor both passwords is AAAA. Each password is user-changeable once it has beencorrectly entered. Entry of the password is achieved either by a prompt when asetting change is attempted, or by moving to the ‘Password’ cell in the ‘Systemdata’ column of the menu. The level of access is independently enabled for eachinterface, that is to say if level 2 access is enabled for the rear communicationport, the front panel access will remain at level 0 unless the relevant password isentered at the front panel. The access level enabled by the password entry willtime-out independently for each interface after a period of inactivity and revert tothe default level. If the passwords are lost an emergency password can be supplied- contact ALSTOM with the relay’s serial number. The current level of accessenabled for an interface can be determined by examining the 'Access level' cell inthe 'System data' column, the access level for the front panel User Interface (UI),can also be found as one of the default display options.

The relay is supplied with a default access level of 2, such that no password isrequired to change any of the relay settings. It is also possible to set the defaultmenu access level to either level 0 or level1, preventing write access to the relaysettings without the correct password. The default menu access level is set in the‘Password control’ cell which is found in the ‘System data’ column of the menu(note that this setting can only be changed when level 2 access is enabled).

3.5 Relay configuration

The relay is a multi-function device which supports numerous different protection,control and communication features. In order to simplify the setting of the relay,there is a configuration settings column which can be used to enable or disablemany of the functions of the relay. The settings associated with any function that isdisabled are made invisible, i.e. they are not shown in the menu. To disable afunction change the relevant cell in the ‘Configuration’ column from ‘Enabled’ to‘Disabled’.

The configuration column controls which of the four protection settings groups isselected as active through the ‘Active settings’ cell. A protection setting group canalso be disabled in the configuration column, provided it is not the present activegroup. Similarly, a disabled setting group cannot be set as the active group.The column also allows all of the setting values in one group of protection settingsto be copied to another group.



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To do this firstly set the ‘Copy from’ cell to the protection setting group to becopied, then set the ‘Copy to’ cell to the protection group where the copy is to beplaced. The copied settings are initially placed in the temporary scratchpad, andwill only be used by the relay following confirmation.

To restore the default values to the settings in any protection settings group, set the‘Restore defaults’ cell to the relevant group number. Alternatively it is possible to setthe ‘Restore defaults’ cell to ‘All settings’ to restore the default values to all of therelay’s settings, not just the protection groups’ settings. The default settings willinitially be placed in the scratchpad and will only be used by the relay after theyhave been confirmed. Note that restoring defaults to all settings includes the rearcommunication port settings, which may result in communication via the rear portbeing disrupted if the new (default) settings do not match those of the masterstation.

3.6 Front panel user interface (keypad and LCD)

When the keypad is exposed it provides full access to the menu options of therelay, with the information displayed on the LCD.

The ⇐ , ⇒ , ⇑ and ⇓ keys which are used for menu navigation and setting valuechanges include an auto-repeat function that comes into operation if any of thesekeys are held continually pressed. This can be used to speed up both setting valuechanges and menu navigation; the longer the key is held depressed, the faster therate of change or movement becomes.

Figure 4: Front panel user interface

Systemfrequency

Date and time

3-phase voltage

Alarm messages

Other default displays

Column 1Sytem data

Column 2View records

Column nGroup 4

Overcurrent

Data 1.1Language

Data 2.1Last record

Data n.1|>1 function

Data 1.2Password

Data 2.2Time and date

Data n.2|>1 directional

Data 1.nPassword

level 2

Data 2.nC – A voltage

Data n.n|> char angle

Other settingcells in

column 1


column 2


column n

Other column headings

Note: The C key will return to column header from any menu cell

C

C

C



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3.6.1 Default display and menu time-out

The front panel menu has a selectable default display. The relay will time-out andreturn to the default display and turn the LCD backlight off after 15 minutes ofkeypad inactivity. If this happens any setting changes which have not beenconfirmed will be lost and the original setting values maintained.

The contents of the default display can be selected from the following options:3-phase and neutral current, 3-phase voltage, power, system frequency, date andtime, relay description, or a user-defined plant reference*. The default display isselected with the ‘Default display’ cell of the ‘Measure’t setup’ column. Also, fromthe default display the different default display options can be scrolled throughusing the ⇐ and ⇒ keys. However the menu selected default display will berestored following the menu time-out elapsing. Whenever there is an unclearedalarm present in the relay (e.g. fault record, protection alarm, control alarm etc.)the default display will be replaced by:

Alarms/Faultspresent

Entry to the menu structure of the relay is made from the default display and is notaffected if the display is showing the ‘Alarms/Faults present’ message.

3.6.2 Menu navigation and setting browsing

The menu can be browsed using the four arrow keys, following the structure shownin Figure 4. Thus, starting at the default display the ⇓ key will display the firstcolumn heading. To select the required column heading use the the ⇐ and ⇒ keys.The setting data contained in the column can then be viewed by using the⇓ and ⇑ keys. It is possible to return to the column header either by holding the [uparrow symbol] key down or by a single press of the clear key C. It is only possibleto move across columns at the column heading level. To return to the defaultdisplay press the [up arrow symbol] key or the clear key C from any of the columnheadings. It is not possible to go straight to the default display from within one ofthe column cells using the auto-repeat facility of the ⇑ key, as the auto-repeat willstop at the column heading. To move to the default display, the ⇑ key must bereleased and pressed again.

3.6.3 Password entry

When entry of a password is required the following prompt will appear:

Enter Password**** Level 1

Note: The password required to edit the setting is the prompt as shown above

A flashing cursor will indicate which character field of the password may bechanged. Press the ⇑ and ⇓ keys to vary each character between A and Z.To move between the character fields of the password, use the ⇐ and ⇒ keys.The password is confirmed by pressing the enter key ↵ . The display will revert to‘Enter Password’ if an incorrect password is entered. At this point a message willbe displayed indicating whether a correct password has been entered and if so



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what level of access has been unlocked. If this level is sufficient to edit the selectedsetting then the display will return to the setting page to allow the edit to continue.If the correct level of password has not been entered then the password promptpage will be returned to. To escape from this prompt press the clear key C.Alternatively, the password can be entered using the ‘Password’ cell of the ‘Systemdata’ column.

For the front panel user interface the password protected access will revert to thedefault access level after a keypad inactivity time-out of 15 minutes. It is possible tomanually reset the password protection to the default level by moving to the‘Password’ menu cell in the ‘System data’ column and pressing the clear key Cinstead of entering a password.

3.6.4 Reading and clearing of alarm messages and fault records

The presence of one or more alarm messages will be indicated by the defaultdisplay and by the yellow alarm LED flashing. The alarm messages can either beself-resetting or latched, in which case they must be cleared manually. To view thealarm messages press the read key . When all alarms have been viewed, butnot cleared, the alarm LED will change from flashing to constant illumination andthe latest fault record will be displayed (if there is one). To scroll through the pagesof this use the key. When all pages of the fault record have been viewed, thefollowing prompt will appear:

Press clear toreset alarms

To clear all alarm messages press C; to return to the alarms/faults present displayand leave the alarms uncleared, press . Depending on the passwordconfiguration settings, it may be necessary to enter a password before the alarmmessages can be cleared (see section on password entry). When the alarms havebeen cleared the yellow alarm LED will extinguish, as will the red trip LED if it wasilluminated following a trip.

Alternatively it is possible to accelerate the procedure, once the alarm viewer hasbeen entered using the key, the C key can be pressed, this will move thedisplay straight to the fault record. Pressing C again will move straight to the alarmreset prompt where pressing C once more will clear all alarms.

3.6.5 Setting changes

To change the value of a setting, first navigate the menu to display the relevant cell.To change the cell value press the enter key ↵ , which will bring up a flashingcursor on the LCD to indicate that the value can be changed. This will only happenif the appropriate password has been entered, otherwise the prompt to enter apassword will appear. The setting value can then be changed by pressing the ⇑ or ⇓ keys. If the setting to be changed is a binary value or a text string, the requiredbit or character to be changed must first be selected using the ⇐ and ⇒ keys.When the desired new value has been reached it is confirmed as the new settingvalue by pressing ↵ . Alternatively, the new value will be discarded either if theclear button C is pressed or if the menu time-out occurs.



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For protection group settings and disturbance recorder settings, the changes mustbe confirmed before they are used by the relay. To do this, when all requiredchanges have been entered, return to the column heading level and press the key.Prior to returning to the default display the following prompt will be given:

Upate settings?Enter or Clear

Pressing ↵ will result in the new settings being adopted, pressing C will cause therelay to discard the newly entered values. It should be noted that, the setting valueswill also be discarded if the menu time out occurs before the setting changes havebeen confirmed. Control and support settings will be updated immediately afterthey are entered, without ‘Update settings?’ prompt.

3.7 Front communication port user interface

The front communication port is provided by a 9-pin female D-type connectorlocated under the bottom hinged cover. It provides RS232 serial datacommunication and is intended for use with a PC locally to the relay (up to 15mdistance) as shown in Figure 5. This port supports the Courier communicationprotocol only. Courier is the communication language developed by ALSTOM T&DProtection & Control to allow communication with its range of protection relays.The front port is particularly designed for use with the relay settings programMiCOM S1 which is a Windows NT based software package.

Figure 5: Front port connection

The relay is a Data Communication Equipment (DCE) device. Thus the pinconnections of the relay’s 9-pin front port are as follows:

Pin no. 2 Tx Transmit data

Pin no. 3 Rx Receive data

Pin no. 5 0V Zero volts common

SK1

SK2

MiCOM relay

Laptop

Serial communication port(COM 1 or COM 2)

Serial data connector(up to 15m)

25 pindownload/monitor port

Battery9 pin

front comms port



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Figure 6: PC – relay signal connection

Having made the physical connection from the relay to the PC, the PC’scommunication settings must be configured to match those of the relay. The relay’scommunication settings for the front port are fixed as shown in the table below:

Protocol CourierBaud rate 19,200 bits/sCourier address 1Message format 11 bit - 1 start bit, 8 data bits, 1 parity bit

(even parity), 1 stop bit

The inactivity timer for the front port is set at 15 minutes. This controls how long therelay will maintain its level of password access on the front port. If no messagesare received on the front port for 15 minutes then any password access level thathas been enabled will be revoked.

None of the other pins are connected in the relay. The relay should be connectedto the serial port of a PC, usually called COM1 or COM2. PCs are normally DataTerminal Equipment (DTE) devices which have a serial port pin connection asbelow (if in doubt check your PC manual):

25 Way 9 Way

Pin no. 3 2 Rx Receive data

Pin no. 2 3 Tx Transmit data

Pin no. 7 5 0V Zero volts common

For successful data communication, the Tx pin on the relay must be connected tothe Rx pin on the PC, and the Rx pin on the relay must be connected to the Tx pinon the PC, as shown in Figure 6. Therefore, providing that the PC is a DTE with pinconnections as given above, a ‘straight through’ serial connector is required, i.e.one that connects pin 2 to pin 2, pin 3 to pin 3, and pin 5 to pin 5. Note that acommon cause of difficulty with serial data communication is connecting Tx to Txand Rx to Rx. This could happen if a ‘cross-over’ serial connector is used, i.e. onethat connects pin 2 to pin 3, and pin 3 to pin 2, or if the PC has the same pinconfiguration as the relay.

Pin 2 TxPin 3 RxPin 5 0V

Pin 2 RxPin 3 TxPin 5 0V

MiCOM relay

Serial data connector

PC

DCE DTE

Note: PC connection shown assuming 9 Way serial port



Page 16 of 21

3.8 Rear communication port user interface

The rear port can support one of three communication protocols (Courier, Modbus,IEC 60870-5-103), the choice of which must be made when the relay is ordered.The rear communication port is provided by a 3-terminal screw connector locatedon the back of the relay. See Appendix B for details of the connection terminals.The rear port provides K-Bus/RS485 serial data communication and is intended foruse with a permanently-wired connection to a remote control centre. Of the threeconnections, two are for the signal connection, and the other is for the earthshield of the cable. When the K-Bus option is selected for the rear port, thetwo signal connections are not polarity conscious, however for Modbus andIEC 60870-5-103 care must be taken to observe the correct polarity.

The protocol provided by the relay is indicated in the relay menu in the‘Communications’ column. Using the keypad and LCD, firstly check that the‘Comms settings’ cell in the ‘Configuration’ column is set to ‘Visible’, then move tothe ‘Communications’ column. The first cell down the column shows thecommunication protocol being used by the rear port.

3.8.1 Courier communication

Courier is the communication language developed by ALSTOM T&D Protection &Control to allow remote interrogation of its range of protection relays.Courier works on a master/slave basis where the slave units contain information inthe form of a database, and respond with information from the database when it isrequested by a master unit.

The relay is a slave unit which is designed to be used with a Courier master unitsuch as MiCOM S1, MiCOM S10, PAS&T, ACCESS or a SCADA system.MiCOM S1 is a Windows NT4.0/95 compatible software package which isspecifically designed for setting changes with the relay.

To use the rear port to communicate with a PC-based master station using Courier,a KITZ K-Bus to RS232 protocol converter is required. This unit is available fromALSTOM T&D Protection & Control Ltd. A typical connection arrangement is shownin Figure 7. For more detailed information on other possible connectionarrangements refer to the manual for the Courier master station software and themanual for the KITZ protocol converter. Each spur of the K-Bus twisted pair wiringcan be up to 1000m in length and have up to 32 relays connected to it.



Page 17 of 21

Figure 7: Remote communication connection arrangements

Having made the physical connection to the relay, the relay’s communicationsettings must be configured. To do this use the keypad and LCD user interface.In the relay menu firstly check that the ‘Comms settings’ cell in the ‘Configuration’column is set to ‘Visible’, then move to the ‘Communications’ column. Only twosettings apply to the rear port using Courier, the relay’s address and the inactivitytimer. Synchronous communication is used at a fixed baud rate of 64kbits/s.Move down the ‘Communications’ column from the column heading to the first celldown which indicates the communication protocol:

Twisted pair ‘K-Bus’ RS485 communications link

KITZ protocolconverter

RS232 K-Bus

MiCOM relay MiCOM relayMiCOM relay

PC

Modem

Modem

Public switchedtelephone network

PC

Remote Courier master stationeg. area control centre

Courier master stationeg. substation control room

PC serial port



Page 18 of 21

ProtocolCourier

The next cell down the column controls the address of the relay:

Remote address1

Since up to 32 relays can be connected to one K-bus spur, as indicated in Figure7, it is necessary for each relay to have a unique address so that messages fromthe master control station are accepted by one relay only. Courier uses an integernumber between 0 and 254 for the relay address which is set with this cell. It isimportant that no two relays have the same Courier address. The Courier addressis then used by the master station to communicate with the relay.

The next cell down controls the inactivity timer:

Inactivity timer10.00 mins

The inactivity timer controls how long the relay will wait without receiving anymessages on the rear port before it reverts to its default state, including revokingany password access that was enabled. For the rear port this can be set between1 and 30 minutes.

Note that protection and disturbance recorder settings that are modified using anon-line editor such as PAS&T must be confirmed with a write to the ‘Save changes’cell of the ‘Configuration’ column. Off-line editors such as MiCOM S1 do notrequire this action for the setting changes to take effect.

3.8.2 Modbus communication

Modbus is a master/slave communication protocol which can be used for networkcontrol. In a similar fashion to Courier, the system works by the master deviceinitiating all actions and the slave devices, (the relays), responding to the master bysupplying the requested data or by taking the requested action.Modbus communication is achieved via a twisted pair connection to the rear portand can be used over a distance of 1000m with up to 32 slave devices.

To use the rear port with Modbus communication, the relay’s communicationsettings must be configured. To do this use the keypad and LCD user interface.In the relay menu firstly check that the ‘Comms settings’ cell in the ‘Configuration’column is set to ‘Visible’, then move to the ‘Communications’ column. Four settingsapply to the rear port using Modbus which are described below. Move down the‘Communications’ column from the column heading to the first cell down whichindicates the communication protocol:

ProtocolModbus



Page 19 of 21

The next cell down controls the Modbus address of the relay:

Modbus address23

Up to 32 relays can be connected to one Modbus spur, and therefore it isnecessary for each relay to have a unique address so that messages from themaster control station are accepted by one relay only. Modbus uses an integernumber between 1 and 247 for the relay address. It is important that no two relayshave the same Modbus address. The Modbus address is then used by the masterstation to communicate with the relay.

The next cell down controls the inactivity timer:

Inactivity timer10.00 mins

The inactivity timer controls how long the relay will wait without receiving anymessages on the rear port before it reverts to its default state, including revokingany password access that was enabled. For the rear port this can be set between1 and 30 minutes.

The next cell down the column controls the baud rate to be used:

Baud rate9600 bits/s

Modbus communication is asynchronous. Three baud rates are supported by therelay, ‘9600 bits/s’, ‘19200 bits/s’ and ‘38400 bits/s’. It is important thatwhatever baud rate is selected on the relay is the same as that set on the Modbusmaster station.

The next cell down controls the parity format used in the data frames:

ParityNone

The parity can be set to be one of ‘None’, ‘Odd’ or ‘Even’. It is important thatwhatever parity format is selected on the relay is the same as that set on theModbus master station.



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3.8.3 IEC 60870-5 CS 103 communication

The IEC specification IEC 60870-5-103: Telecontrol Equipment and Systems,Part 5: Transmission Protocols Section 103 defines the use of standardsIEC 60870-5-1 to IEC 60870-5-5 to perform communication with protectionequipment. The standard configuration for the IEC 60870-5-103 protocol is to usea twisted pair connection over distances up to 1000m. As an option for IEC60870-5-103, the rear port can be specified to use a fibre optic connection fordirect connection to a master station. The relay operates as a slave in the system,responding to commands from a master station. The method of communication usesstandardised messages which are based on the VDEW communication protocol.

To use the rear port with IEC 60870-5-103 communication, the relay’scommunication settings must be configured. To do this use the keypad and LCDuser interface. In the relay menu firstly check that the ‘Comms settings’ cell in the‘Configuration’ column is set to ‘Visible’, then move to the ‘Communications’column. Four settings apply to the rear port using IEC 60870-5-103 which aredescribed below. Move down the ‘Communications’ column from the columnheading to the first cell which indicates the communication protocol:

ProtocolIEC 60870-5-103

The next cell down controls the IEC 60870-5-103 address of the relay:

Remote address162

Up to 32 relays can be connected to one IEC 60870-5-103 spur, and therefore itis necessary for each relay to have a unique address so that messages from themaster control station are accepted by one relay only. IEC 60870-5-103 uses aninteger number between 0 and 254 for the relay address. It is important that notwo relays have the same IEC 60870-5-103 address. The IEC 60870-5-103address is then used by the master station to communicate with the relay.

The next cell down the column controls the baud rate to be used:

Baud rate9600bits/s

IEC 60870-5-103 communication is asynchronous. Two baud rates are supportedby the relay, ‘9600 bits/s’ and ‘19200 bits/s’. It is important that whatever baudrate is selected on the relay is the same as that set on the IEC 60870-5-103 masterstation.



Page 21 of 21

The next cell down controls the period between IEC 60870-5-103 measurements:

Measure’t period30.00 s

The IEC 60870-5-103 protocol allows the relay to supply measurements at regularintervals. The interval between measurements is controlled by this cell, and can beset between 1 and 60 seconds.

The next cell down the column controls the physical media used for thecommunication:

Physical linkRS485

The default setting is to select the electrical RS485 connection. If the optional fibreoptic connectors are fitted to the relay, then this setting can be changed to ‘Fibreoptic’.

The next cell down can be used to define the primary function type for thisinterface, where this is not explicitly defined for the application by theIEC 60870-5-103 protocol*.

Function type226




Chapter 2Application Notes


ContentsPage 1 of 4

1. INTRODUCTION 11.1 Interconnection protection 11.2 MiCOM Interconnection Protection Relay 11.2.1 Protection features 21.2.2 Non-protection features 22 APPLICATION OF INDIVIDUAL PROTECTION FUNCTIONS 32.1 Configuration column 32.2 CT and VT ratios 62.3 Loss of mains protection 62.4 Rate of change of frequency protection 82.4.1 Setting guidelines for df/dt protection 92.5 Voltage vector shift protection 102.5.1 Setting guidelines for Voltage Vector Shift protection 122.6 Reconnection timer 132.6.1 Setting guidelines for the Reconnect Delay 142.7 Power protection 142.7.1 Over Power protection 162.7.1.1 Over Power setting guideline 162.7.2 Low Forward Power protection function 162.7.2.1 Low Forward Power setting guideline 172.7.3 Reverse Power protection function 172.7.3.1 Reverse Power setting guideline 192.8 Overcurrent protection 192.8.1 Transformer Magnetising Inrush 222.8.2 Application of Timer Hold facility 232.8.3 Setting guidelines 232.9 Directional overcurrent protection 242.9.1 Synchronous polarisation 252.9.2 Setting guidelines 262.10 Earth fault protection 262.10.1 Standard Earth Fault protection element 262.10.2 Sensitive Earth Fault Protection element (SEF) 292.11 Directional Earth Fault protection (DEF) 322.11.1 Residual voltage polarisation 322.11.2 Negative sequence polarisation 322.11.3 General setting guidelines for DEF 322.11.4 Application to insulated systems 332.11.5 Setting guidelines – insulated systems 362.11.6 Application to Petersen Coil earthed systems 362.12 Operation of sensitive earth fault element 422.13 Application considerations 432.13.1 Calculation of required relay settings 432.13.2 Application of settings to the relay 442.14 Restricted earth fault protection 442.14.1 High impedance restricted earth fault protection 452.14.2 Setting guidelines for high impedance REF 462.15 Residual over voltage/neutral voltage displacement protection 492.15.1 Setting guidelines for residual over voltage/neutral voltage

displacement protection 52


ContentsPage 2 of 4

2.16 Under voltage protection 532.16.1 Setting guidelines for under voltage protection 552.17 Over voltage protection 552.17.1 Setting guidelines for over voltage protection 572.18 Under frequency protection 582.18.1 Setting guidelines for under frequency protection 592.19 Over frequency protection function 612.19.1 Setting guidelines for over frequency protection 622.20 Circuit breaker fail protection (CBF) 622.20.1 Breaker failure protection configurations 622.20.2 Reset mechanisms for breaker fail timers 632.21 Typical settings 662.21.1 Breaker fail timer settings 662.21.2 Breaker fail undercurrent settings 663. OTHER PROTECTION CONSIDERATIONS 673.1 Blocked overcurrent protection 674. APPLICATION OF NON-PROTECTION FUNCTIONS 694.1 Voltage transformer supervision (VTS) 694.1.1 Loss of all three phase voltages under load conditions 694.1.2 Absence of three phase voltages upon line energisation 694.1.3 Menu settings 704.2 Current transformer supervision 714.2.1 The CT supervision feature 714.2.2 Setting the CT supervision element 724.3 Circuit breaker state monitoring 724.3.1 Circuit breaker state monitoring features 724.4 Circuit breaker control 734.5 Event & fault records 764.5.1 Types of event 774.5.1.1 Change of state of opto-isolated inputs. 774.5.1.2 Change of state of one or more output relay contacts. 784.5.1.3 Relay alarm conditions. 784.5.1.4 Protection element starts and trips 794.5.1.5 General events 794.5.1.6 Fault records. 794.5.1.7 Maintenance reports 794.5.1.8 Setting changes 794.5.2 Resetting of event/fault records 804.5.3 Viewing event records via MiCOM S1 support software 804.6 Disturbance recorder 804.7 Measurements 824.7 1 Measured voltages and currents 824.7.2 Sequence voltages and currents 824.7.3 Power and energy quantities 824.7.4 Rms. voltages and currents 834.7.5 Demand values 834.7.5.1 Fixed demand values 834.7.5.2 Rolling demand values 844.7.5.3 Peak demand values 84


ContentsPage 3 of 4

Figure 1: Typical system with embedded generation 7Figure 2a: Vector diagram representing steady state condition 11Figure 2b: Single phase line diagram showing generator parameters 11Figure 2c: Transient voltage vector change q due to change in load current DIL 11Figure 3: Typical distribution system using parallel transformers 25Figure 4: Positioning of core balance current transformers 31Figure 5: Current distribution in an insulated system with C phase fault 34Figure 6: Phasor diagrams for insulated system with C phase fault 35Figure 7: Current distribution in Peterson Coil earthed system 37Figure 8: Distribution of currents during a C phase to earth fault 38Figure 9: Theoretical case – no resistance present in XL or Xc 39Figure 10: Zero sequence network showing residual currents 40Figure 11: Practical case:- resistance present in XL and Xc 41Figure 12: Resistive components of spill current 42Figure 13: High impedance principle 45Figure 14: High impedance REF relay/CT connections 46

4.7.6 Settings 844.7.6.1 Default display 844.7.6.2 Local values 844.7.6.3 Remote values 844.7.6.4 Measurement ref 844.7.6.5 Measurement mode 844.7.6.6 Fixed demand period 854.7.6.7 Rolling sub-period and number of sub-periods 855. CT/VT REQUIREMENTS 855.1 Non-directional definite time/IDMT overcurrent & earth fault protection 855.1.1 Time-delayed phase overcurrent elements 855.1.2 Time-delayed earth fault overcurrent elements 855.2 Non-Directional instantaneous overcurrent & earth fault protection 855.2.1 CT requirements for instantaneous phase overcurrent elements 855.2.2 CT requirements for instantaneous earth fault overcurrent elements 855.3 Directional definite time/IDMT overcurrent & earth fault protection 855.3.1 Time-delayed phase overcurrent elements 855.3.2 Time-delayed earth fault overcurrent elements 855.4 Directional instantaneous overcurrent & earth fault protection 865.4.1 CT requirements for instantaneous phase overcurrent elements 865.4.2 CT requirements for instantaneous earth fault overcurrent elements 865.5 Non-directional/directional definite time/IDMT sensitive earth

fault (SEF) protection 865.5.1 Time delayed SEF protection 865.5.2 Non-directional SEF protection 865.5.3 Directional instantaneous SEF protection 865.5.4 SEF protection - as fed from a core-balance CT 865.6 High impedance restricted earth fault protection 87


ContentsPage 4 of 4

Figure 15a: Residual voltage, solidly earthed systems 50Figure 15b: Residual voltage, resistance earthed systems 51Figure 16: Co-ordination of underfrequency protection function with

system load shedding. 60Figure 17a: Simple busbar blocking scheme (single incomer) 67Figure 17b: Simple busbar blocking scheme (single incomer) 68Figure 18: Remote control of circuit breaker 74


Page 1 of 87

Section 1. INTRODUCTION

1.1 Interconnection protectionSmall-scale generators can be found in a wide range of situations. These may beused to provide emergency power in the event of loss of the main supply.Alternatively the generation of electrical power may be a by-product of a heat/steam generation process. Where such embedded generation capacity exists it canbe economic to run the machines in parallel with the local Public ElectricitySupplier’s (PES) network. This can reduce a sites overall power demand or peakload. Additionally, excess generation may be exported and sold to the local PES.If parallel operation is possible great care must be taken to ensure that theembedded generation does not cause any dangerous conditions to exist on thelocal PES network.PES networks have in general been designed for operation where the generation issupplied from central sources down into the network. Generated voltages andfrequency are closely monitored to ensure that values at the point of supply arewithin statutory limits. Tap changers and tap changer control schemes areoptimised to ensure that supply voltages remain within these limits. Embeddedgeneration can affect the normal flow of active and reactive power on the networkleading to unusually high or low voltages being produced and may also lead toexcessive fault current that could exceed the rating of the installed distributionswitchgear/cables.It may also be possible for the embedded generators to become disconnected fromthe main source of supply but be able to supply local load on the PES network.Such islanded operation must be avoided for several reasons• to ensure that unearthed operation of the PES network is avoided• to ensure that automatic reclosure of system circuit breakers will not result in

connecting unsynchronised supplies causing damage to the generators• to ensure that system operations staff cannot attempt unsynchronised manual

closure of an open circuit breaker.• to ensure that there is no chance of faults on the PES system being undetectable

due to the low fault supplying capability of the embedded generator• to ensure that the voltage and frequency supplied to PES customers remains

within statutory limitsBefore granting permission for the generation to be connected to their system thePES must be satisfied that no danger will result. The type and extent of protectionrequired at the interconnection point between PES system and embeddedgeneration will need to be analysed.

1.2 MiCOM Interconnection Protection RelayMiCOM relays are a new range of products from ALSTOM T&D Protection &Control Ltd. Using the latest numerical technology the platform includes devicesdesigned for the application to a wide range of power system plant such asmotors, generators, feeders, overhead lines and cables.Each relay is designed around a common hardware and software platform inorder to achieve a high degree of commonality between products. One suchproduct in the range is the P341 Interconnection Protection Relay. The relay hasbeen designed to provide a wide range of protection functions required to preventdangerous conditions that could be present when embedded generators provide


Page 2 of 87

power to local power supply networks when the main connection with theElectricity Supply system is lost.The relays also include a comprehensive range of non-protection features to aidwith power system diagnosis and fault analysis. All these features can be accessedremotely from one of the relay’s remote serial communications options.

1.2.1 Protection features

The P341 relay contains a wide variety of protection functions, these aresummarised below:• Phase Fault Overcurrent Protection – Four stage back-up protection.• Earth Fault Overcurrent Protection – Four stage back-up protection.• Neutral Displacement Protection – Provides protection against earth faults on

impedance earthed/un-earthed systems.• Under/Over Voltage Protection – Two stage protection to prevent the supply of

unusual voltages to external supply network.• Under/Over Frequency Protection – Six stage frequency protection to prevent

the supply of unusual frequencies to the external supply network.• Reverse Power – Protection against prime mover failure of a generator.• Low Forward Power – Provides an interlock for non urgent tripping.• Over Power – Back-up overload protection, or protection against excessive

export power to local network• Rate of Change of Frequency Protection – To detect the loss of connection to

main Grid supply network.• Voltage Vector Shift Protection – To detect the loss of connection to main Grid

supply network.• Voltage Transformer Supervision – To prevent mal-operation of voltage

dependent protection elements upon loss of a VT input signal.• Programmable Scheme Logic – Allowing user defined protection and control

logic to suit particular customer applications.

1.2.2 Non-protection features

Below is a summary of the P341 relay non-protective features.• Measurements – Various measurements of value for display on the relay or

accessed from the serial communications, eg. currents, voltages etc.• Fault/Event/Disturbance Records – Available from the serial communications or

on the relay display (fault/event records only on relay display).• Four Setting Groups – Independent setting groups to cater for alternative power

system and protection arrangements or special applications.• Remote Serial Communications – To allow remote access to the relays.

The following communications protocols are supported; Courier, MODBUS andIEC 60870-5-103 (VDEW).

• Continuous Self Monitoring – Power-on diagnostics and self checking routines toprovide maximum relay reliability and availability.

• Commissioning test facilities.


Page 3 of 87

Section 2 APPLICATION OF INDIVIDUAL PROTECTIONFUNCTIONS

The following sections detail the individual protection functions in addition towhere and how they may be applied. Each section also gives an extract from therespective menu columns to demonstrate how the settings are actually applied tothe relay.

2.1 Configuration columnThe P340 relays include a column in the menu called the “CONFIGURATION”column. This affects the operation of each of the individual protection functions.The aim of this column is to allow general configuration of the relay from a singlepoint in the menu. Any of the functions that are disabled or made invisible from thiscolumn do not then appear within the main relay menu.The following table shows the relay menu for the Configuration column, withdefault settings. The brief description of the function of each setting is alsoprovided.

Menu text Default setting Available settings Function

CONFIGURATION

Restore Defaults No Operation No Operation Restore defaultAll Settings settings to any or

Setting Group 1 all groups of settingsSetting Group 2Setting Group 3Setting Group 4

Setting Group Select via Menu Select via Menu Change settingSelect via Optos groups by?

Active Settings Group 1 Group 1 Select active settingGroup 2 group used forGroup 3 protection settingsGroup 4

Save Changes No Operation No Operation Saves all settingSave changes fromAbort stored settings

buffer memory intostored settings

Copy From Group 1 Group1,2,3 or 4 Selects a groupof settings to copy

to the groupdesignated in“Copy to” cell


Page 4 of 87


Copy To No Operation Group1,2,3 or 4 Copies the group ofsettings selected in

the “Copy from” cellto the selectedsetting group

Setting Group 1 Enabled Enabled or Disabled Selects if Group 1settings are available

on the relay

Setting Group 2 Disabled Enabled or Disabled Selects if Group 2settings are available

on the relay


on the relay


on the relay

Power Enabled Enabled or Disabled Makes settings visiblein the relay menu

Overcurrent Enabled Enabled or Disabled Makes settings visiblein the relay menu

Earth Fault Enabled Enabled or Disabled Makes settings visiblein the relay menu

SEF/REF Prot’n Disabled Enabled or Disabled Makes settings visiblein the relay menu

Residual O/V NVD Enabled Enabled or Disabled Makes settings visiblein the relay menu

df/dt Disabled Enabled or Disabled Makes settings visiblein the relay menu

V Vector Shift Disabled Enabled or Disabled Makes settings visiblein the relay menu

Reconnect Delay Disabled Enabled or Disabled Makes settings visiblein the relay menu

Volt Protection Enabled Enabled or Disabled Makes settings visiblein the relay menu


Page 5 of 87


Freq Protection Enabled Enabled or Disabled Makes settings visiblein the relay menu

CB Fail Disabled Enabled or Disabled Makes settings visiblein the relay menu

Supervision Disabled Enabled or Disabled Makes settings visiblein the relay menu

Input Labels Visible Invisible or Visible Makes settings visiblein the relay menu

Output Labels Visible Invisible or Visible Makes settings visiblein the relay menu

CT & VT Ratios Visible Invisible or Visible Makes settings visiblein the relay menu

Event Recorder Invisible Invisible or Visible Makes settings visiblein the relay menu

Disturb Recorder Invisible Invisible or Visible Makes settings visiblein the relay menu

Measure’t Setup Invisible Invisible or Visible Makes settings visiblein the relay menu

Comms Settings Visible Invisible or Visible Makes settings visiblein the relay menu

Commission Tests Visible Invisible or Visible Makes settings visiblein the relay menu

Setting Values Primary Primary or Selects if relaySecondary protection settings

are displayed inprimary or secondarycurrent/voltage values


Page 6 of 87

2.2 CT and VT ratiosThe P340 relay allows the current and voltage settings to be applied to the relay ineither primary or secondary quantities. This is done by programming the “SettingValues” cell of the “CONFIGURATION” column to either ‘Primary’ or ‘Secondary’.When this cell is set to ‘Primary’, all current, voltage and impedance setting valuesare scaled by the programmed CT and VT ratios. These are found in the “VT & CTRATIOS” column, settings for which are shown below.

Menu text Default setting Setting range Step size

Min Max

CT & VT RATIOS

Main VT Primary 110V 100V 1000000V 1V

Main VT Sec’y 110 V 80V 140V 110V(Vn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)

400V 360V 480V 400V(Vn=400/440V) (Vn=400/440V) (Vn=400/440V) (Vn=400/440V)

NVD VT Primary 110 V 100 V 1000000 V 1 V

NVD VT Secondary 110 V 80V 140V 110V(Vn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


Phase CT Primary 1 1 30000 1

Phase CT Sec’y 1 1 5 4

E/F CT Primary 1 1 30000 1

E/F CT Secondary 1 1 5 4

SEF CT Primary 1 1 30000 1

SEF CT Secondary 1 1 5 4

2.3 Loss of mains protectionIf the capacity of an embedded generator exceeds the locally connected load it isconceivable that it could supply the local load in island mode. Fault clearance maydisconnect part of the public supply system from the main source of supply resultingin the embedded generation feeding the local loads, ie. a ‘Loss of Mains’ or ‘Lossof Grid’ condition. This is illustrated in Figure 1. A fault at F will result in thetripping of CB1 disconnecting substations S1, S2 and S3 from the main source ofsupply. Also note that transformer T1 was supplying the earth connection for S1,S2 and S3, this earth connection is lost when CB1 opens. Should the load atsubstations S1 and S2 greatly exceed the rating of EG1, the generator will slowdown quickly and underfrequency and/or undervoltage relays could operate to


Page 7 of 87

disconnect EG1 from the system. The worst scenario is when the external load issmaller than the generator rating, in this case the generator can continue tooperate normally supplying the external loads. The local system will now beoperating unearthed and overcurrent protection may be inoperative at S1 and S2due to the low fault supplying capacity of generator EG1. The embeddedgenerator may also lose synchronism with the main system supply leading toserious problems if CB1 has auto reclosing equipment.An even more serious problem presents itself if manual operation of distributionswitchgear is considered. System Operation staff may operate circuit breakers byhand. In these circumstances it is essential that unsynchronised reclosure isprevented as this could have very serious consequences for the operator,particularly if the switchgear is not designed, or rated, to be operated whenswitching onto a fault. To protect personnel, the embedded machine must bedisconnected from the system as soon as the system connection is broken, this willensure that manual unsynchronised closure is prevented.

Figure 1: Typical system with embedded generation

Where the embedded generator does not export power under normal conditions itmay be possible to use directional power or directional overcurrent protectionrelays to detect the export of power under loss of mains conditions. If export ofpower into the system is allowed it may not be possible to set directional relaysusing settings sensitive enough to detect the loss of the mains connection. In suchcircumstances a Rate of Change of Frequency and/or Voltage Vector Shiftprotection can be applied. These detect the slight variation in generator speed thatoccurs when the main supply connection is disconnected and the generatorexperiences a step change in load.The type of protection required to detect Loss of Mains conditions will depend on anumber of factors, eg. the generator rating, size of local load, ability to exportpower, and configuration of supply network etc. Protection requirements should bediscussed and agreed with the local Public Electricity Supplier before permission toconnect the embedded generator in parallel with the system is granted.A number of protection elements that may be sensitive to the Loss of Mainsconditions are offered in the P341 relay; Rate of Change of Frequency, Voltage

S2

S1S3

EG1

CB2 CB1 T1

F

PESsystem


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Vector Shift, Over Power Protection, Directional Overcurrent Protection, FrequencyProtection, Voltage Protection. Application of each of these elements is discussed inthe following sections.

2.4 Rate of change of frequency protectionWhen a machine is running in parallel with the main power supply the frequencyand hence speed of the machine will be governed by the grid supply. When theconnection with the grid is lost, as described in Section 2.3, the now islandedmachine is free to slow down or speed up as determined by the new loadconditions, machine rating and governor response. Where there is a significantchange in load conditions between the synchronised and islanded condition themachine will speed up or slow down before the governor can respond.The rate of change of speed, or frequency, following a power disturbance can beapproximated by

where P = Change in power output between synchronised and islandedoperation

f = Rated frequencyG = Machine rating in MVAH = Inertia constant

This simple expression assumes that the machine is running at rated frequency andthat the time intervals are short enough that AVR and governor dynamics can beignored. From this equation it is clear that the rate of change of frequency isdirectly proportional to the change in power output between two conditions.Provided there is a small change in load between the synchronised and islanded(loss of mains) condition the rate of change of frequency as the machine adjusts tothe new load conditions can be detectable. The change in speed of the machine isalso proportional to the inertia constant and rating of the machine and so will beapplication dependent.Care must be taken in applying this type of protection as the prime consideration isdetecting the loss of grid connection. Failure to detect this condition may result inunsynchronised re-connection via remote re-closing equipment. However if toosensitive a setting is chosen there is a risk of nuisance tripping due to frequencyfluctuations caused by normal heavy load switching or fault clearance. Guidancecan be given for setting a rate of change of frequency element but these settingsmust be thoroughly tested on site to prove their accuracy for a given machine andload.A single stage, definite time delayed, rate of change of frequency element isprovide in the P341 relay. The element calculates the rate of change of frequencyevery 3 cycles by calculating the frequency difference over the 3-cycle period asshown.

Two consecutive calculations must give a result above the setting threshold before atrip decision can be initiated.

df dt 2GH= ∆P.f

df =dtn n–3cyclef – f

3cycle


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The element also allows the user to set a frequency band within which the elementis blocked. This provides additional stability for non loss of grid disturbances whichdo not affect the machine frequency significantly.A DDB (Digital Data Bus) signal is available to indicate that the element hasoperated (DDB 202). A second DDB signal is available to indicate that the elementhas started (DDB 318). These signals are used to operate the output relays (asprogrammed into the Programmable Scheme Logic (PSL)) and trigger thedisturbance recorder. The state of the DDB signals can also be programmed to beviewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in therelay.The following table shows the relay menu for the rate of change of frequency ordf/dt protection element, including the available setting ranges and factorydefaults:-


Min Max

GROUP 1df/dt

df/dt Status Enabled Enabled, Disabled

df/dt Setting 0.2 Hz/s 0.1 Hz/s 10 Hz/s 0.01 Hz/s

df/dt Time Delay 0.5 s 0 s 100 s 0.1 s

df/dt f low 49.5 Hz 45 Hz 65 Hz 0.01 Hz

df/dt f high 50.5 Hz 45 Hz 65 Hz 0.01 Hz

2.4.1 Setting guidelines for df/dt protection

The rate of change of frequency, or df/dt, protection can be selected by setting the“df/dt Status” cell to ‘Enabled’.The rate of change of frequency setting threshold, “df/dt Setting”, should be set tothe desired level.The time delay setting, “df/dt Time Delay”, can be used to provide a degree ofstability against normal load switching events which will cause a change in thefrequency before governor correction.The frequency dead band can be set by setting the upper and lower frequencythresholds, “df/dt f High”, “df/dt f Low”, respectively.The setting thresholds should be set such that the loss of mains condition can bedetected, this can be determined by system switching during initial commissioning.System simulation testing has shown that the following settings can provide stableoperation for external faults, and load switching events, whilst operating for a lossof mains event which causes a 10% change in the machine output, for a typical4MW machine. These can be used as a guide but will by no means be acceptablein all applications. Machine rating, governor response, local load and systemload, will all affect the dynamic response of a machine to a loss of mains event.


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df/dt Setting – 0.2Hz/sdf/dt Time Delay – 0.5sdf/dt f High – 50.5Hzdf/dt f Low – 49.5HzOnce installed, the settings should be periodically reviewed to ensure that they areadequate to detect a loss of grid connection event, but not too sensitive such thatunwanted tripping occurs during normal fault clearance, or load switching, thatdoes not lead to the loss of mains condition. Safety of personnel is paramount andthis should be kept in mind when optimising settings; non-synchronised manualoperation of circuit breakers must be prevented by disconnection of the embeddedmachine when the system becomes separated.

2.5 Voltage vector shift protectionAn expression for a sinusoidal mains voltage waveform is generally given by thefollowing:

V = Vp sin (wt) or V = Vp sin θ(t)

where θ(t) = wt = 2πft

If the frequency is changing at constant rate Rf from a frequency fo then thevariation in the angle θ(t) is given by:

θ(t) = 2π ∫f dt,

which gives θ(t) = 2π (fo t + t Rf t/2),

and V = V sin 2π (fo + t Rf/2)t

Hence the angle change ∆θ(t) after time t is given by:

∆θ(t) = π Rf t2,

Therefore the phase of the voltage with respect to a fixed frequency referencewhen subject to a constant rate of change of frequency changes in proportion tot2. This is a characteristic difference from a rate of change of frequency function,which in most conditions can be assumed as changing linearly with time.A rate of change of frequency of 10 Hz/s results in an angular voltage vector shiftof only 0.72 degrees in the first cycle after the disturbance. This is too small to bedetected by vector shift relays. In fact a typical setting for a voltage vector shiftrelay is, normally between 6 and 13 degrees. Therefore a voltage vector shift relayis not sensitive to the change in voltage phase brought about by change offrequency alone.To understand the relation between the resulting voltage vector angle changefollowing a disturbance and the embedded generator characteristics a simplifiedsingle phase equivalent circuit of a synchronous generator or induction generatoris shown in Figure 2. The voltage VT is the symmetrical terminal voltage of thegenerator and the voltage E is the internal voltage lying behind the machineimpedance which is largely reactive (X). When a disturbance causes a change incurrent the terminal voltage will jump with respect to its steady state position.The resultant voltage vector is dependent on the rate of change in current, and thesubtransient impedance of the machine, which is the impedance the generatorpresents to a sudden load change. In turn the current change depends on howstrong the source is (short circuit capacity) and the voltage regulation at thegenerator terminal which is also affected by the reactive power load connected tothe machine.


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Figure 2a: Vector diagram representing steady state condition

Figure 2b; Single phase line diagram showing generator parameters

Figure 2c: Transient voltage vector change θ due to change in load current ∆IL

The voltage vector shift function is designed to respond within one to two full mainscycles when its threshold is exceeded. Discrimination between a loss of mainscondition and a circuit fault is therefore achievable only by selecting the anglethreshold to be above expected fault levels. This setting can be quantified bycalculating the angular change due to islanding. However this angular changedepends on system topology, power flows and very often also on the instant of thesystem faults. For example a bolted three phase short circuit which occurs close tothe relay may cause a problem in that it inherently produces a vector shift angle atthe instant of the fault which is bigger than any normal setting, independent of themains condition. This kind of fault would cause the relay to trip shortly after theinstant of its inception. Although this may seem to be a disadvantage of the vector

E

I

I X

I RV

L

L

LT

E

RI

V

jX

T

L

E

I

I XI RV

L

L

LT

∆I X”L

θ

VT

∆IL


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shift function, isolating the embedded generator at the instant of a bolted threephase fault is of advantage to the PES. This is because the mains short circuitcapacity and consequently the energy feeding the short circuit is limited by theinstant operation of the relay. The fast operation of this vector shift function rendersit to operate at the instant of a disturbance rather than during a gradual changecaused by a gradual change of power flow. Operation can occur at the instant ofinception of the fault, at fault clearance or following non-synchronised reclosure,which affords additional protection to the embedded generator.The P341 has a single stage Voltage Vector Shift protection element. This elementmeasures the change in voltage angle over successive power system half-cycles.The element operates by measuring the time between zero crossings on the voltagewaveforms. A measurement is taken every half cycle for each phase voltage.Over a power system cycle this produces 6 results, a trip is issued if 5 of the 6calculations for the last power system cycle are above the set threshold. Checkingall three phases makes the element less susceptible to incorrect operation due toharmonic distortion or interference in the measured voltage waveform.A DDB (Digital Data Bus) signal is available to indicate that the element hasoperated (DDB 203). The state of the DDB signal can also be programmed to beviewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in therelay.The following table shows the relay menu for the Voltage Vector Shift protectionelement, including the available setting ranges and factory defaults:-


Min Max

GROUP 1V Vector Shift

V Shift Status Enabled Enabled, Disabled

V Shift Angle 10º 2º 30º 1º

2.5.1 Setting guidelines for Voltage Vector Shift protection

The element can be selected by setting the “V Shift Status” cell to ‘Enabled’.The angle change setting threshold, “V Shift Angle”, should be set to the desiredlevel.The setting threshold should be set such that the loss of mains condition can bedetected, this can be determined by system switching during initial commissioning.System simulation testing has shown that a “V Shift Angle” setting of 10º canprovide stable operation for external faults, and load switching events, whilstoperating for a loss of mains event which causes a 10% change in the machineoutput for a typical 4MW machine. Although in some circumstances, this settingmay prove to be too sensitive, it is recommended to achieve a successful loss ofmains trip in as many cases as possible. Although the vector shift function may tripthe relay due to a bolted 3 phase fault, it is also essential in securing a trip at theinstant of an out-of-phase autoreclose, where the df/dt function does not trip.


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This setting should be used as a guide but will by no means be acceptable in allapplications. Machine rating, governor response, local load and system load, willall affect the dynamic response of a machine to a loss of mains event.Once installed the settings should be periodically reviewed to ensure that they areadequate to detect a loss of grid connection event, but not too sensitive such thatunwanted tripping occurs during normal fault clearance that does not lead to theloss of mains condition. Safety of personnel is paramount and this should be keptin mind when optimising settings; non-synchronised manual operation of circuitbreakers must be prevented by disconnection of the embedded machine when thesystem becomes separated.

2.6 Reconnection timerAs explained in sections 2.4 and 2.5, due to the sensitivity of the settings appliedto the df/dt and/or the Voltage Vector Shift element, false operation for non loss ofmains events may occur. This could, for example, be due to a close up three phasefault which can cause operation of a Voltage Vector Shift element. Such operationswill lead to the disconnection of the embedded machine from the external networkand prevent export of power. Alternatively the loss of mains protections mayoperate correctly, and auto re-closure equipment may restore the grid supplyfollowing a transient fault.Disconnection of an embedded generator could lead to a simple loss of revenue.or in cases where the licensing arrangement demands export of power at times ofpeak load may lead to penalty charges being imposed. To minimise the disruptioncaused, the P341 includes a reconnection timer. This timer is initiated followingoperation of any protection element that could operate due to a loss of mainsevent, ie. df/dt, voltage vector shift, under/over frequency, power and under/overvoltage. The timer is blocked should a short circuit fault protection element operate,i.e residual overvoltage, overcurrent, and earth fault. Once the timer delay hasexpired the element will provide a pulsed output signal. This signal can be used toinitiate external synchronising equipment that can re-synchronise the machine withthe system and reclose the CB.A DDB (Digital Data Bus) signal is available to indicate that the element hasoperated (DDB 315). The state of the DDB signal can also be programmed to beviewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in therelay.The following table shows the relay menu for the Reconnect Delay, including theavailable setting ranges and factory defaults:-


Min Max

GROUP 1RECONNECTDELAY

Reconnect Status Enabled Enabled, Disabled

Reconnect Delay 60 s 0 s 300 s 0.01 s

Reconnect tPULSE 1 s 0.01 s 30 s 0.01 s


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2.6.1 Setting guidelines for the Reconnect Delay

The element can be selected by setting the “Reconnect Status” cell to ‘Enabled’.The timer setting, “Reconnect Delay”, should be set to the desired delay, this wouldtypically be longer than the dead time of system auto reclose equipment to ensurethat re-synchronisation is only attempted after the system has been returned to anormal state. The signal pulse time, “Reconnect tPULSE” should be set such that theoutput pulse is sufficient to securely initiate the auto synchronising equipment whenrequired.

2.7 Power protectionThe power protection elements of the P341 relay calculate the three phase activepower based on the following formula, using the current measured at the IA, IB,IC inputs on the relay.

P = Vala cosφa + Vblb cosφb + Vclc cosφc

Two stages of power protection are provided, these can be independently selectedas either Reverse Power, Over Power, Low Forward Power or Disabled, operationin each mode is described in the following sections. The power elements may beselectively disabled, via fixed logic, so that they can be inhibited when used formachine protection and the protected machine CB is open. This will prevent falseoperation and nuisance flagging of any stage selected to operate as Low Forwardpower.Where the local licensing agreement prevents the export of power into the localsupply Over Power protection may be used as a simple Loss of Mains protection.In these cases the element can be used to provide alarm and trip stages allowingthe machine operators to closely monitor the machine export capability.DDB signals are available to indicate starting and tripping of each stage(Starts: DDB274, DDB275, Trips: DDB237, 238). The state of the DDB signals canbe programmed to be viewed in the “Monitor Bit x” cells of the “COMMISSIONTESTS” column in the relay.Setting ranges for the Power elements are shown in the following table


Page 15 of 87


Min Max

GROUP 1 POWER

Power1 Function Reverse Disabled, Reverse, Low Forward, Over

-P>1 Setting 20 x In W 14 x In W 40 x In W 0.5 x In W(Vn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)

80 x In W 56 x In W 160 x In W 2 x In W (Vn=400/440V) (Vn=400/440V) (Vn=400/440V) (Vn=400/440V)

P<1 Setting 20 x In W 14 x In W 40 x In W 0.5 x In W(Vn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)

80 x In W 56 x In W 160 x In W 2 x In W(Vn=400/440V) (Vn=400/440V) (Vn=400/440V) (Vn=400/440V)

P>1 Setting 5 x In W 14 x In W 300 x In W 0.5 x In WVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


Power1 TimeDelay 5 s 0 s 100 s 0.01 s

Power1 DO Timer 0 s 0 s 100 s 0.01 s

P1 Poledead Inh Enabled Enabled, Disabled

Power2 Function Low Forward Disabled, Reverse, Low Forward, Over

–P>2 Setting 5 x In W 14 x In W 40 x In W 0.5 x In WVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


P<2 Setting 5 x In W 14 x In W 40 x In W 0.5 x In WVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


P>2 Setting 5 x In W 14 x In W 300 x In W 0.5 x In WVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


Power2 TimeDelay 5 s 0 s 100 s 0.01 s

Power2 DO Timer 0 s 0 s 100 s 0.01 s

P2 Poledead Inh Enabled Enabled, Disabled


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2.7.1 Over Power protection

The Over Power function is a directional element that will operate when powerflows in the forward direction. From the convention, this means power flowingaway from the busbar into the interconnection feeder or out of the protectedmachine.Over Power protection can be used as simple overload indication, or as a back upprotection for failure of governor and control equipment, and would be set abovethe maximum power rating of the machine.Alternatively the Over Power function can be used as protection against excessiveexport power for an embedded generator. In some installations the machine maybe allowed to operate in parallel with the external supply but the exportation ofpower into the external supply may be forbidden. In these cases a simple OverPower element can be used to monitor the power flow at the interconnection circuitbreaker and trip if power is seen to be exported into the system. For small standbygenerators this may be accepted as the Loss of Mains protection.

2.7.1.1 Over Power setting guideline

Each stage of power protection can be selected to operate as an Over Powerstage by selecting the “Power1 Function” or “Power2 Function” cell to ‘Over’.The power threshold setting of the Over Power protection, “P>1 Setting” or “P>2Setting”, should be set greater than the machine full load rated power if providingoverload protection. If the element is used to prevent the export of power into theexternal system then the threshold can be set to minimum or just in excess of thepower export allowance.A time delay setting, “Power1 TimeDelay” or “Power2 TimeDelay” can be applied.The delay on reset timer, “Power1 DO Timer” or “Power2 DO Timer”, wouldnormally be set to zero.

2.7.2 Low Forward Power protection function

Low forward power may be used where the P341 relay is being used to protect asmall generator. When the CB connecting the generator to the system is tripped,the electrical load on the machine is cut. This could lead to generator over-speed ifthe mechanical input power is not reduced quickly. To reduce the risk of overspeed damage, it is sometimes chosen to interlock non-urgent tripping of thegenerator breaker with a low forward power check. This ensures that the generatorset circuit breaker is opened only when the output power is sufficiently low thatover speeding is unlikely. The delay in electrical tripping, until prime mover inputpower has been removed, may be deemed acceptable for ‘non-urgent’ protectiontrips; e.g. stator earth fault protection for a high impedance earthed generator. For‘urgent’ trips, e.g. stator short circuit protection the low forward power interlockshould not be used. With the low probability of ‘urgent’ trips, the risk of overspeed and possible consequences must be accepted.The Low Forward Power protection can be arranged to interlock ‘non-urgent’tripping using the relay programmable scheme logic. It can also be arranged toprovide a contact for external interlocking of manual tripping, if desired.To prevent unwanted relay alarms and flags, a Low Forward Power protectionelement can be disabled when the circuit breaker is opened via ‘poledead’ logic.


Page 17 of 87

2.7.2.1 Low Forward Power setting guideline

Each stage of power protection can be selected to operate as a Low ForwardPower stage by selecting the “Power1 Function” or “Power2 Function” cell to ‘LowForward’.When required, the threshold setting of the Low Forward Power protectionfunction, “P<1 Setting” or “P<2 Setting”, should be less than 50% of the powerlevel that could result in a dangerous over speed transient on loss of electricalloading. The generator set manufacturer should be consulted for a rating for theprotected machine.The time delay associated with the Low Forward Power protection function,“Power1 TimeDelay” or “Power2 TimeDelay”, could be set to zero. However, somedelay is desirable so that permission for a non-urgent electrical trip is not given inthe event of power fluctuations arising from sudden steam valve/throttle closure.A typical time delay for this reason is 2s.The delay on reset timer, “Power1 DO Timer” or “Power2 DO Timer”, wouldnormally be set to zero when selected to operate Low Forward power elements.To prevent unwanted relay alarms and flags, a Low Forward Power protectionelement can be disabled when the circuit breaker is open via ‘poledead’ logic.This is controlled by setting the power protection inhibit cells, “P1 Poledead Inh” or“P2 Poledead Inh”, to ‘Enabled’.

2.7.3 Reverse Power protection function

Reverse Power protection may be used where the P341 relay is being used toprotect a small generator. A generator is expected to supply power to theconnected system in normal operation. If the generator prime mover fails, agenerator that is connected in parallel with another source of electrical supply willbegin to ‘motor’. This reversal of power flow due to loss of prime mover can bedetected by the reverse power element.The consequences of generator motoring and the level of power drawn from thepower system will be dependent on the type of prime mover. Typical levels ofmotoring power and possible motoring damage that could occur for various typesof generating plant are given in Table 2.


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Prime Mover Motoring Power Possible Damage(Percentage rating)

Diesel Engine 5% – 25% Risk of fire or explosion fromunburned fuel

Motoring level depends on compression ratio and cylinder bore stiffness.Rapid disconnection is required to limit power loss and risk of damage.

Gas Turbine 10% – 15% With some gear-driven sets, damage(Split-shaft) may arise due to reverse torque on

gear teeth.>50%(Single-shaft)

Compressor load on single shaft machines leads to a high motoring powercompared to split-shaft machines. Rapid disconnection is required to limitpower loss or damage.

Hydraulic 0.2 – >2% Blade and runner cavitation mayTurbines (Blades out of water) occur with a long period of motoring.

>2.0%(Blades in water)

Power is low when blades are above tail-race water level. Hydraulic flowdetection devices are often the main means of detecting loss of drive.Automatic disconnection is recommended for unattended operation.

Table 2. Motoring power and possible damage for various types of prime mover.

In some applications, the level of reverse power in the case of prime mover failuremay fluctuate. This may be the case for a failed diesel engine. To prevent cyclicinitiation and reset of the main trip timer, and consequent failure to trip, anadjustable reset time delay is provided. This delay would need to be set longerthan the period for which the reverse power could fall below the power setting(“P<1 Setting”). This setting needs to be taken into account when setting the maintrip time delay. It should also be noted that a delay on reset in excess of half theperiod of any system power swings could result in operation of the reverse powerprotection during swings.Reverse Power Protection may also be used to interlock the opening of thegenerator set circuit breaker for ‘non-urgent’ tripping, as discussed in 2.12.1.Reverse Power interlocking is preferred over Low Forward Power interlocking bysome utilities.


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2.7.3.1 Reverse Power setting guideline

Each stage of power protection can be selected to operate as a Reverse Powerstage by selecting the “Power1 Function” or “Power2 Function” cell to ‘Reverse’.The power threshold setting of the Reverse Power protection, “–P>1 Setting” or“–P>2 Setting”, should be less than 50% of the motoring power, typical values forthe level of reverse power for generators are given in Table 2.The reverse power protection function should be time-delayed to prevent false tripsor alarms being given during power system disturbances or followingsynchronisation. A time delay setting, “Power1 TimeDelay” or “Power2 TimeDelay”of 5s should be applied typically.The delay on reset timer, “Power1 DO Timer” or “Power2 DO Timer”, wouldnormally be set to zero. When settings of greater than zero are used for the resettime delay, the pick up time delay setting may need to be increased to ensure thatfalse tripping does not result in the event of a stable power swinging event.An additional, more sensitive Reverse Power relay, may be required in the case ofhydro machines, where the minimum setting provided by the P341 relay is toohigh. Such dedicated relays can be fed from measurement class CTs providingmore accurate determination of low levels of power. An external relay can beintegrated into the overall protection/monitoring/recording scheme via the P341programmable scheme logic.

2.8 Overcurrent protectionOvercurrent relays are the most commonly used protective devices in any industrialor distribution power system. They provide main protection to both feeders andbusbars when unit protection is not used. They are also commonly applied toprovide back-up protection when unit systems, such as pilot wire schemes, areused.By a combination of time delays and relay pick-up settings, overcurrent relays maybe applied to either feeders or power transformers to provide discriminative phasefault protection (and also earth fault protection if system earth fault levels aresufficiently high). In such applications, the various overcurrent relays on the systemare co-ordinated with one another such that the relay nearest to the fault operatesfirst. This is referred to as cascade operation because if the relay nearest to thefault does not operate, the next upstream relay will trip in a slightly longer time.The overcurrent protection included in the P341 relay provides four stage non-directional/directional three phase overcurrent protection with independent timedelay characteristics. All overcurrent and directional settings apply to all threephases but are independent for each of the four stages.The first two stages of overcurrent protection have time delayed characteristicswhich are selectable between inverse definite minimum time (IDMT), or definitetime (DT). The third and fourth stages have definite time characteristics only.Various methods are available to achieve correct relay co-ordination on a system;by means of time alone, current alone or a combination of both time and current.Grading by means of current is only possible where there is an appreciabledifference in fault level between the two relay locations. Grading by time is usedby some utilities but can often lead to excessive fault clearance times at or nearsource substations where the fault level is highest. For these reasons the mostcommonly applied characteristic in co-ordinating overcurrent relays is the IDMTtype.


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Each stage can be blocked by energising the relevant DDB signal via the PSL(DDB142, DDB143, DDB144, DDB145). This allows the overcurrent protection tobe integrated into busbar protection schemes, as shown in Section 2.18, or can beused to improve grading with downstream devices. DDB signals are also availableto indicate the start and trip of each phase of each stage of protection, (Starts:-DDB276-283, Trips:- DDB239-246). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSIONTESTS” column in the relay.The following table shows the relay menu for the overcurrent protection, includingthe available setting ranges and factory defaults:-


Min Max

GROUP 1OVERCURRENT

I>1 Function IEC S Inverse Disabled, DT, IEC S Inverse, IEC V Inverse,IEC E Inverse, UK LT Inverse, IEEE M Inverse,IEEE V Inverse, IEEE E Inverse, US Inverse,

US ST Inverse

I>1 Direction Non-Directional Non-Directional, Directional Fwd,Directional Rev

I>1 Current Set 1 x In A 0.08 x In A 4.0 x In A 0.01 x In A

I>1 Time Delay 1 s 0 s 100 s 0.01 s

I>1 TMS 1 0.025 1.2 0.025

I>1 Time Dial 7 0.5 15 0.1

I>1 Reset Char DT DT or Inverse

I>1 tRESET 0 s 0 s 100 s 0.01 s

I>2Cells as for I>1above

I>3 Status Disabled Disabled or Enabled

I>3 Direction Non-Directional Non-Directional, Directional Fwd,Directional Rev

I>3 Current set 20 x In A 0.08 x In A 32 x In A 0.01 x In A

I>3 Time Delay 0 s 0 s 100 s 0.01 s


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Min Max

I>4Cells as for I>3above

I> Char Angle 45º –95° +95° 1°

I> Function Link 00001111 Bit 0 I>1 VTS Block, Bit 1 I>2 VTS Block,See Note Bit 2 I>3 VTS Block, Bit 3 I>4 VTS Block,

Bit 4, 5, 6 & 7 Not Used

Note:VTS Block – When relevant bit set to 1, operation of Voltage TransformerSupervision (VTS) will block stage if directionalised. When set to 0, stage willrevert to non-directional.The inverse time delayed characteristics listed above, comply with the followingformula:

The IEC/UK IDMT curves conform to the following formula:

t = T xK

(I/Is ) α – 1+L

The IEEE/US IDMT curves conform to the following formula:

xK

(I/Is) α – 1+Lt = TD

7

where t = operation time

K = constant

I = measured current

IS = current threshold setting

α = constant

L = ANSI/IEEE constant (zero for IEC/UK curves)

T = Time multiplier setting for IEC/UK curves

TD = Time dial setting for IEEE/US curves


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IDMT characteristics

IDMT curve Standard K α Ldescription constant constant constantStandard inverse IEC 0.14 0.02 0Very inverse IEC 13.5 1 0Extremely inverse IEC 80 2 0Long time inverse UK 120 1 0Moderately inverse IEEE 0.0515 0.02 0.114Very inverse IEEE 19.61 2 0.491Extremely inverse IEEE 28.2 2 0.1217Inverse US-C08 5.95 2 0.18Short time inverse US-C02 0.02394 0.02 0.01694

Note that the IEEE and US curves are set differently to the IEC/UK curves, withregard to the time setting. A time multiplier setting (TMS) is used to adjust theoperating time of the IEC curves, whereas a time dial setting is employed for theIEEE/US curves. Both the TMS and Time Dial settings act as multipliers on the basiccharacteristics but the scaling of the time dial is approximately 10 times that of theTMS, as shown in the previous menu. The menu is arranged such that if an IEC/UKcurve is selected, the ‘I> Time Dial’ cell is not visible and vice versa for the TMSsetting.

2.8.1 Transformer Magnetising Inrush

When applying overcurrent protection to the HV side of a power transformer, it isusual to apply a high set instantaneous overcurrent element, in addition to the timedelayed low-set, to reduce fault clearance times for HV fault conditions. Typically,this will be set to approximately 1.3 times the LV fault level, such that it will onlyoperate for HV faults. A 30% safety margin is sufficient due to the low transientoverreach of the third and fourth overcurrent stages. Transient overreach definesthe response of a relay to DC components of fault current and is quoted as apercentage. A relay with a low transient overreach will be largely insensitive to aDC offset and may therefore be set more closely to the steady state AC waveform.The second requirement for this element is that it should remain inoperative duringtransformer energisation, when a large primary current flows for a transientperiod. In most applications, the requirement to set the relay above the LV faultlevel will automatically result in settings that will be above the level of magnetisinginrush current.Due to the nature of operation of the third and fourth overcurrent stages in theP341 relays, it is possible to apply settings corresponding to 35% of the peakinrush current, whilst maintaining stability for the condition.This is important where low-set instantaneous stages are used to initiate autorecloseequipment. In such applications, the instantaneous stage should not operate forinrush conditions, which may arise from small teed-off transformer loads forexample. However, the setting must also be sensitive enough to provide fastoperation under fault conditions.Where an instantaneous element is required to accompany the time delayedprotection, as described above, the third or fourth overcurrent stage of the P341relay should be used, as they have wider setting ranges.


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2.8.2 Application of Timer Hold facility

The first two stages of overcurrent protection in the P341 relays are provided witha timer hold facility, which may either be set to zero or to a definite time value.(Note that if an IEEE/US operate curve is selected, the reset characteristic may beset to either definite or inverse time in cell ‘I>1 Reset Char’; otherwise this settingcell is not visible in the menu). Setting of the timer to zero means that theovercurrent timer for that stage will reset instantaneously once the current fallsbelow 95% of the current setting. Setting of the hold timer to a value other thanzero delays the resetting of the protection element timers for this period. This maybe useful in certain applications, for example when grading with upstreamelectromechanical overcurrent relays which have inherent reset time delays.Another situation where the timer hold facility may be used to reduce faultclearance times is where intermittent faults may be experienced. An example ofthis may occur in a plastic insulated cable. In this application it is possible that thefault energy melts and reseals the cable insulation, thereby extinguishing the fault.This process repeats to give a succession of fault current pulses, each of increasingduration with reducing intervals between the pulses, until the fault becomespermanent.When the reset time of the overcurrent relay is instantaneous the relay will berepeatedly reset and not be able to trip until the fault becomes permanent.By using the Timer Hold facility the relay will integrate the fault current pulses,thereby reducing fault clearance time.The timer hold facility can be found for the first and second overcurrent stages assettings ‘I>1 tRESET’ and ‘I>2 tRESET’, respectively. Note that this cell is not visibleif an inverse time reset characteristic has been selected, as the reset time is thendetermined by the programmed time dial setting.

2.8.3 Setting guidelines

When applying the overcurrent protection provided in the P341 relays, standardprinciples should be applied in calculating the necessary current and time settingsfor co-ordination. The setting example detailed below shows a typical settingcalculation and describes how the settings are actually applied to the relay.Assume the following parameters for a relay feeding an LV switchboard:CT Ratio = 500/1Full Load Current of circuit = 450ASlowest downstream protection = 100A FuseThe current setting employed on the P341 relay must account for both themaximum load current and the reset ratio of the relay itself:-I> must be greater than: 450/0.95 = 474AThe P341 relay allows the current settings to be applied to the relay in eitherprimary or secondary quantities. Programming the ‘Setting Values’ cell of the“CONFIGURATION” column to either ‘Primary’ or ‘Secondary’ does this.When this cell is set to primary, all phase overcurrent setting values are scaled bythe programmed CT ratio. This is found in column 0A of the relay menu, entitled“VT & CT RATIOS”, where cells ‘Phase CT Primary’ and ‘Phase CT Sec’y’ can beprogrammed with the primary and secondary CT ratings, respectively.In this example, assuming primary currents are to be used, the ratio should beprogrammed as 500/1.The required setting is therefore 0.95A in terms of secondary current or 475A interms of primary.


Page 24 of 87

A suitable time delayed characteristic will now need to be chosen. When co-ordinating with downstream fuses, the applied relay characteristic should beclosely matched to the fuse characteristic. Therefore, assuming IDMT co-ordinationis to be used, an Extremely Inverse (EI) characteristic would normally be chosen.As previously described, this is found under ‘I>1 Function’ and should therefore beprogrammed as ‘IEC E Inverse’.Finally, a suitable time multiplier setting (TMS) must be calculated and entered incell ‘I>1 TMS’.For more detailed information regarding overcurrent relay co-ordination, referenceshould be made to ALSTOM’s ‘Protective Relay Application Guide’ – Chapter 9.

2.9 Directional overcurrent protectionIf fault current can flow in both directions through a relay location, it is necessaryto add directionality to the overcurrent relays in order to obtain correct co-ordination. Typical systems that require such protection are parallel feeders (bothplain and transformer) and ring main systems, each of which are relativelycommon in distribution networks.In order to give directionality to an overcurrent relay, it is necessary to provide itwith a suitable reference, or polarising, signal. The reference generally used is thesystem voltage, as it’s angle remains relatively constant under fault conditions.The phase fault elements of the P341 relay are internally polarised by thequadrature phase-phase voltages, as shown in the table below:-

Phase of protection Operate current Polarising voltageA Phase IA VBCB Phase IB VCAC Phase IC VAB

It is therefore important to ensure the correct phasing of all current and voltageinputs to the relay, in line with the supplied application diagram.Under system fault conditions, the fault current vector will lag it’s nominal phasevoltage by an angle dependent upon the system X/R ratio. It is therefore arequirement that the relay operates with maximum sensitivity for currents lying inthis region. This is achieved by means of the relay characteristic angle (RCA)setting; this defines the angle by which the current applied to the relay must bedisplaced from the voltage applied to the relay to obtain maximum relay sensitivity.This is set in cell ‘I>Char Angle’ in the Overcurrent menu.Figure 3 shows a typical distribution system utilising parallel power transformers.In such an application, a fault at ‘F’ could result in the operation of both R3 and R4relays and the subsequent loss of supply to the 11kV busbar. Hence, with thissystem configuration, it is necessary to apply directional relays at these locationsset to “look into” their respective transformers. These relays should co-ordinate withthe non-directional relays, R1 and R2; hence ensuring discriminative relayoperation during such fault conditions.In such an application, relays R3 and R4 may commonly require non-directionalovercurrent protection elements to provide protection to the 11kV busbar, inaddition to providing a back-up function to the overcurrent relays on the outgoingfeeders (R5).When applying the P341 relays in the above application, stage 1 of theovercurrent protection of relays R3 and R4 would be set non-directional and time


Page 25 of 87

Figure 3: Typical distribution system using parallel transformers

graded with R5, using an appropriate time delay characteristic. Stage 2 couldthen be set directional, looking back into the transformer, also having acharacteristic which provided correct co-ordination with R1 and R2. IDMT or DTcharacteristics are selectable for both stages 1 and 2 and directionality of each ofthe overcurrent stages is set in cell ‘I> Direction’Note that the principles previously outlined for the parallel transformer applicationare equally applicable for plain feeders which are operating in parallel.

2.9.1 Synchronous polarisation

For a fault condition that occurs close to the relaying point, the faulty phasevoltage will reduce to a value close to zero volts. For single or double phase faults,there will always be at least one healthy phase voltage present for polarisation ofthe phase overcurrent elements. For example, a close up A to B fault condition willresult in the collapse of the A and B phase voltages. However, the A and B phaseelements are polarised from VBC and VCA respectively. As such a polarisingsignal will be present, allowing correct relay operation.For a close up three phase fault, all three voltages will collapse to zero and nohealthy phase voltages will be present. For this reason, the P341 relays include asynchronous polarisation feature that stores the pre-fault voltage information andcontinues to apply it to the DOC elements for a time period of 3.2 seconds.This ensures that either instantaneous or time delayed DOC elements will beallowed to operate, even with a three phase voltage collapse.

33kV

R1OC/EF

R2OC/EF

R3DOC/DEF

OC/EF

R4DOC/DEF

OC/EF

SBEF

F

11kV

R5OC/EF

Loads


Page 26 of 87

2.9.2 Setting guidelines

The applied current settings for directional overcurrent relays are dependent uponthe application in question. In a parallel feeder arrangement, load current isalways flowing in the non-operate direction. Hence, the relay current setting maybe less than the full load rating of the circuit; typically 50% of In.Note that the minimum setting that may be applied has to take into account thethermal rating of the relay. Some electro-mechanical directional overcurrent relayshave continuous withstand ratings of only twice the applied current setting andhence 50% of rating was the minimum setting that could be applied. With modernrelays such as the P341, the continuous current rating is 3 x rated current and so itis possible to apply much more sensitive settings, if required. However a setting of50% of rating provides extra security against mal-operation for HV side faults inparallel transformer applications where forward current may be seen in one ormore phases of a reverse looking relay.The required characteristic angle settings for directional relays will differdepending on the exact application in which they are used.Recommended characteristic angle settings are as follows:-• Plain feeders, or applications with an earthing point (zero sequence source)

behind the relay location, should utilise a +30º RCA setting.• Transformer feeders, or applications with a zero sequence source in front of the

relay location, should utilise a +45º RCA setting.On the P341 relay, it is possible to set characteristic angles anywhere in the range–95º to +95º. Whilst it is possible to set the RCA to exactly match the system faultangle, it is recommended that the above guidelines are adhered to, as thesesettings have been shown to provide satisfactory performance and stability under awide range of system conditions.

2.10 Earth fault protectionThe P341 relay has a total of four input current transformers; one for each of thephase current inputs and one for supplying the sensitive earth fault protectionelement. Residual, or earth fault, current can be derived from the sum of the phasecurrent inputs. With this flexible input arrangement, various combinations ofstandard, sensitive (SEF) and restricted earth fault (REF) protection may beconfigured within the relay.It should be noted that in order to achieve the sensitive setting range that isavailable in the P341 relay for SEF protection, the input CT is designed specificallyto operate at low current magnitudes. This common input is used to drive either theSEF or REF protection which are enabled / disabled accordingly within the relaymenu.

2.10.1 Standard Earth Fault protection element

The four stage Standard Earth Fault protection operates from earth fault currentwhich is derived internally from the summation of the three phase currents.The first and second stages have selectable IDMT or DT characteristics, whilst thethird and fourth stages are DT only. Each stage is selectable to be either non-directional, directional forward or directional reverse. The Timer Hold facility,previously described for the overcurrent elements, is available on each of the firsttwo stages.


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Each stage can be blocked by energising the relevant DDB signal via the PSL(DDB146, DDB147, DDB148, DDB149). This allows the overcurrent protection tobe integrated into busbar protection schemes, as shown in Section 2.18, or can beused to improve grading with downstream devices. DDB signals are also availableto indicate the start and trip of each phase of each stage of protection,(Starts:- DDB292-295, Trips:- DDB204-207). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSIONTESTS” column in the relay.The following table shows the relay menu for the Earth Fault protection, includingthe available setting ranges and factory defaults.:-


Min Max

GROUP 1EARTH FAULT 1

IN>1 Function IEC S Inverse Disabled, DT, IEC S Inverse,IEC V Inverse, IEC E Inverse, UK LT Inverse,

IEEE M Inverse, IEEE V Inverse, IEEE E Inverse,US Inverse, US ST Inverse

IN>1 Direction Non-Directional Non-Directional, Directional Fwd,Directional Rev

IN>1 Current 0.2 x In A 0.08 x In A 4.0 x In A 0.01 x In A

IN>1 Time Delay 1 s 0 s 100 s 0.01 s

IN1>1 TMS 1 0.025 1.2 0.025

IN1>1 Time Dial 7 0.5 15 0.1

IN>1 Reset Char DT DT or Inverse

IN>1 tRESET 0 s 0 s 100 s 0.01 s

IN>2Cells as for IN>1above

IN>3 Status Disabled Disabled or Enabled

IN>3 Direction Non-Directional Non-Directional, Directional Fwd, Directional Rev

IN>3 Current set 20 x In A 0.08 x In A 32 x In A 0.01 x In A

IN>3 Time Delay 0 s 0 s 100 s 0.01 s


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Min Max

IN>4Cells as for IN>3above

IN> Function LinkSee Note 00001111 Bit 0 I>1 VTS Block, Bit 1 I>2 VTS Block,

Bit 2 I>3 VTS Block, Bit 3 I>4 VTS Block,Bit 4, 5 6&7 Not Used

IN> DIRECTIONAL Sub Heading

IN> Char Angle –60º –95° +95° 1°

IN1> Pol Zero Sequence Zero Sequence , Neg Sequence

IN1>VNpol Set 5 V 0.5V 22V 0.5VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


IN1>V2pol Set 5 V 0.5V 22V 0.5VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


IN1>I2pol Set 0.08 x In A 0.08 x In A 1 x In A 0.015 x In A

Note:VTS Block - When relevant bit set to 1, operation of VTS will block stage ifdirectionalised. When set to 0, stage will revert to non-directional.For the range of available inverse time delayed characteristics, refer to those of thephase overcurrent elements, Section 2.9.The multiple stages may be enabled in the relay at the same time, this providessome application advantages. For example, the parallel transformer applicationshown in Figure 1 requires directional earth fault protection at locations R3 andR4, to provide discriminative protection. However, in order to provide back-upprotection for the busbar and other downstream earth fault devices, non-directionalearth fault protection can also be applied.Where a neutral earthing resistor (NER) is used to limit the earth fault level, it ispossible that an earth fault condition could cause a flashover of the NER andhence a dramatic increase in the earth fault current. For this reason, it may beappropriate to apply two stage EF protection. The first stage should have currentand time characteristics which co-ordinate with downstream earth fault protection.A second stage may then be set with a higher current setting greater than the NERlimited fault current but with zero time delay; hence providing fast clearance of anearth fault which gives rise to an NER flashover.


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2.10.2 Sensitive Earth Fault Protection element (SEF)

If a system is earthed through high impedance, or is subject to high ground faultresistance, the earth fault level will be severely limited. Consequently, the appliedearth fault protection requires both an appropriate characteristic and a sensitivesetting range in order to be effective. A separate 4 stage Sensitive Earth Faultelement is provided within the P341 relay for this purpose, this has a dedicated CTinput.Each stage can be blocked by energising the relevant DDB signal via the PSL(DDB150, DDB151, DDB152, DDB153). This allows the overcurrent protection tobe integrated into busbar protection schemes, as shown in Section 2.18, or can beused to improve grading with downstream devices. DDB signals are also availableto indicate the start and trip of each phase of each stage of protection,(Starts:- DDB296-299, Trips:- DDB209-212). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSIONTESTS” column in the relay.The following table shows the relay menu for the ‘Sensitive Earth Fault ‘ protection,including the available setting ranges and factory defaults.


Min Max

GROUP 1SEF/REF PROT’N

Sens E/F Options SEF SEF, Wattmetric, Hi Z REF

ISEF>1 Function DT Disabled, DT, IEC S Inverse, IEC V Inverse,IEC E Inverse, UK LT Inverse, IEEE M Inverse,IEEE V Inverse, IEEE E Inverse, US Inverse,

US ST Inverse

ISEF>1 Direction Non-Directional Non-Directional, Directional Fwd, Directional Rev

ISEF>1 Current 0.05 x In A 0.002 x In A 0.1 x In A 0.00025 x In A

ISEF>1 Time Delay 1 s 0 s 200 s 0.01 s

ISEF>1 TMS 1 0.025 1.2 0.025

ISEF>1 Time Dial 7 0.5 15 0.1

ISEF>1 Reset Char DT DT or Inverse

ISEF>1 tRESET 1 s 0 s 100 s 0.01 s

ISEF>2Cells as for ISEF>1above

ISEF>3 Status Disabled Disabled or Enabled


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Min Max

ISEF>3 Direction Non-Directional Non-Directional, Directional Fwd, Directional Rev

ISEF>3 Current 0.2 x In A 0.002 x In A 0.8 x In A 0.002 x In A

ISEF>3 Time Delay 1 s 0 s 100 s 0.01 s

ISEF>4Cells as for ISEF>3above

ISEF> Func LinkSee Note 00001111 Bit 0 ISEF>1 VTS Block, Bit 1 ISEF>2 VTS Block,

Bit 2 ISEF>3 VTS Block, Bit 3 ISEF>4 VTS Block,Bit 4, 5, 6 & 7 Not Used

ISEF DIRECTIONAL Sub Heading

ISEF> Char Angle 90º –95° +95° 1°

ISEF>VNpol Set 5 V 0.5V 22V 0.5VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


WATTMETRIC SEF Sub Heading

PN> Setting 9 x In W 0 x In W 20 x In W 0.05 x In WVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)

36 x In W 0 x In W 80 x In W 0.2 x In W(Vn=400/440V) (Vn=400/440V) (Vn=400/440V) (Vn=400/440V)

Note:VTS Block - When relevant bit set to 1, operation of VTS will block stage ifdirectionalised. When set to 0, stage will revert to non-directional.For the range of available inverse time delayed characteristics, refer to those of thephase overcurrent elements, Section 2.9 .Notes:-As can be seen from the menu, the ‘Sens E/F Options’ cell has a number of settingoptions. To enable standard, four stage SEF protection, the ‘SEF’ option should beselected, which is the default setting. However, if wattmetric or restricted earth faultprotection is required, then one of the remaining options should be selected. Theseare described in more detail in Sections 2.11.6 and 2.11.7. The ‘WATTMETRIC’and ‘RESTRICTED E/F’ cells will only appear in the menu if the functions have beenselected in the Options cell.As shown in the previous menu, each SEF stage is selectable to be either non-directional, directional forward or directional reverse in the ‘ISEF> Direction’ cell.


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The Timer Hold facility, previously described for the overcurrent elements in section2.9, is available on each of the first two stages and is set in the same manner.Settings related to directionalising the SEF protection are described in detail in thefollowing section.SEF would normally be fed from a core balance current transformer (CBCT)mounted around the three phases of the feeder cable. However, care must betaken in the positioning of the CT with respect to the earthing of the cable sheath.See Figure 4 below:-

Figure 4: Positioning of core balance current transformers

As can be seen from the diagram, if the cable sheath is terminated at the cablegland and earthed directly at that point, a cable fault (from phase to sheath) willnot result in any unbalance current in the core balance CT. Prior to earthing, theconnection must be brought back through the CBCT and earthed on the feederside. This ensures correct relay operation during earth fault conditions.

Cable gland

Cable gland/sheathearth connection

Cable box

SEF

SEFNo operation

SEF

Operation

“Incorrect”

“Correct”


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2.11 Directional Earth Fault protection (DEF)Each of the four stages of standard earth fault protection and SEF protection maybe set to be directional if required. Consequently, as with the application ofdirectional overcurrent protection, a voltage supply is required by the relay toprovide the necessary polarisation.With the standard earth fault protection element in the P341 relay, two options areavailable for polarisation; Residual Voltage or Negative Sequence.

2.11.1 Residual voltage polarisation

With earth fault protection, the polarising signal requires to be representative ofthe earth fault condition. As residual voltage is generated during earth faultconditions, this quantity is commonly used to polarise DEF elements. The P341relay can internally derive this voltage from the 3 phase voltage input, or canmeasure the voltage via the neutral displacement or residual overvoltage input.The method of measuring the polarising signal is set in the “IN> Vnpol Input” cell.Where the residual voltage is derived from the 3 phase voltages a 5-limb or threesingle phase VT’s must be used. These types of VT design allow the passage ofresidual flux and consequently permit the relay to derive the required residualvoltage. In addition, the primary star point of the VT must be earthed. A three limbVT has no path for residual flux and is therefore unsuitable to supply the relay.It is possible that small levels of residual voltage will be present under normalsystem conditions due to system imbalances, VT inaccuracies, relay tolerances etc.Hence, the P341 relay includes a user settable threshold, “IN>VNpol Set”, whichmust be exceeded in order for the DEF function to be operational. The residualvoltage measurement provided in the “MEASUREMENTS 1” column of the menumay assist in determining the required threshold setting during the commissioningstage, as this will indicate the level of standing residual voltage present.Note that residual voltage is nominally 180º out of phase with residual current.Consequently, the DEF relays are polarised from the ‘–Vres’ quantity. This 180ºphase shift is automatically introduced within the P341 relay.

2.11.2 Negative sequence polarisation

In certain applications, the use of residual voltage polarisation of DEF may eitherbe not possible to achieve, or problematic. An example of the former case wouldbe where a suitable type of VT was unavailable, for example if only a three limbVT was fitted. An example of the latter case would be an HV/EHV parallel lineapplication where problems with zero sequence mutual coupling may exist.In either of these situations, the problem may be solved by the use of negativephase sequence (nps) quantities for polarisation. This method determines the faultdirection by comparison of nps voltage with nps current. The operate quantity,however, is still residual current. This is available for selection on the derived earthfault element but not on the SEF protection. It requires a voltage and currentthreshold to be set in cells “IN> V2pol Set” & “IN> I2pol Set”, respectively.

2.11.3 General setting guidelines for DEF

When setting the relay characteristic angle (RCA) for the directional overcurrentelement, a positive angle setting was specified. This was due to the fact that thequadrature polarising voltage lagged the nominal phase current by 90º ie. theposition of the current under fault conditions was leading the polarising voltageand hence a positive RCA was required. With DEF, the residual current under faultconditions lies at an angle lagging the polarising voltage. Hence, negative RCAsettings are required for DEF applications. This is set in cell ‘I>Char Angle’ in therelevant earth fault menu.


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The following angle settings are recommended for a residual voltage polarisedrelay:-

Resistance earthed systems ⇒ 0ºDistribution systems (solidly earthed) ⇒ –45ºTransmission Systems (solidly earthed) ⇒ –60º

For negative sequence polarisation, the RCA settings must be based on the angleof the nps source impedance.

2.11.4 Application to insulated systems

The advantage gained by running a power system which is insulated from earth isthe fact that during a single phase to earth fault condition, no earth fault current isallowed to flow. Consequently, it is possible to maintain power flow on the systemeven when an earth fault condition is present. However, this advantage is offset bythe fact that the resultant steady state and transient overvoltages on the soundphases can be very high. It is generally the case, therefore, that insulated systemswill only be used in low/medium voltage networks where it does not prove toocostly to provide the necessary insulation against such overvoltages. Higher systemvoltages would normally be solidly earthed or earthed via a low impedance.Operational advantages may be gained by the use of insulated systems. However,it is still vital that detection of the fault is achieved. This is not possible by means ofstandard current operated earth fault protection. One possibility for fault detectionis by means of a residual overvoltage device. This functionality is included withinthe P341 relays and is detailed in Section 2.12. However, fully discriminativeearth fault protection on this type of system can only be achieved by theapplication of a sensitive earth fault element. This type of relay is set to detect theresultant imbalance in the system charging currents that occurs under earth faultconditions. It is therefore essential that a core balance CT is used for thisapplication. This eliminates the possibility of spill current that may arise from slightmismatches between residually connected line CT’s. It also enables a much lowerCT ratio to be applied, thereby allowing the required protection sensitivity to bemore easily achieved.Consider Figure 5:-


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Figure 5: Current distribution in an insulated system with C phase fault

From Figure 5, it can be seen that the relays on the healthy feeders see theunbalance in the charging currents for their own feeder. The relay on the faultedfeeder, however, sees the charging current from the rest of the system (IH1 andIH2 in this case), with it’s own feeders charging current (IH3) becoming cancelledout. This is further illustrated by the phasor diagrams shown in Figure 6.

- jXc1

Ιa1

Ιb1

- jXc2

Ιa2

Ιb2

- jXc3

Ιa3Ιb3

ΙH3 ΙH1 + ΙH2

ΙH2

ΙH1

ΙR3 = ΙH1 + ΙH2 + ΙH3 - ΙH3

ΙR3 = ΙH1 + ΙH2

ΙH1 + ΙH2 + ΙH3

ΙR2

ΙR1

ΙR3


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Figure 6: Phasor diagrams for insulated system with C phase fault

Referring to the phasor diagram, it can be seen that the C phase to earth faultcauses the voltages on the healthy phases to rise by a factor of √3. The A phasecharging current (Ia1), is then shown to be leading the resultant A phase voltageby 90º. Likewise, the B phase charging current leads the resultant Vb by 90º.The unbalance current detected by a core balance current transformer on thehealthy feeders can be seen to be the vector addition of Ia1 and Ib1, giving aresidual current which lies at exactly 90º lagging the polarising voltage (–3Vo).As the healthy phase voltages have risen by a factor of √3, the charging currentson these phases will also be √3 times larger than their steady state values.Therefore, the magnitude of residual current, IR1, is equal to 3 x the steady stateper phase charging current.The phasor diagrams indicate that the residual currents on the healthy and faultedfeeders, IR1 and IR3 respectively, are in anti-phase. A directional element couldtherefore be used to provide discriminative earth fault protection.If the polarising voltage of this element, equal to –3Vo, is shifted through +90º, theresidual current seen by the relay on the faulted feeder will lie within the operateregion of the directional characteristic and the current on the healthy feeders willfall within the restrain region.As previously stated, the required characteristic angle setting for the SEF elementwhen applied to insulated systems, is +90º. It should be noted though, that thisrecommended setting corresponds to the relay being connected such that it’sdirection of current flow for operation is from the source busbar towards thefeeder, as would be the convention for a relay on an earthed system. However, ifthe forward direction for operation was set as being from the feeder into thebusbar, (which some utilities may standardise on), then a –90( RCA would berequired. The correct relay connections to give a defined direction for operationare shown on the relay connection diagram.Note that discrimination can be provided without the need for directional control.This can only be achieved if it is possible to set the relay in excess of the chargingcurrent of the protected feeder and below the charging current for the rest of thesystem.

Operate

VapfIR1

Ia1

Ib1

Vaf

Restrain

Vbf

VbpfVcpf

Vres(=–3Vo)

An RCA setting of +90°shifts the MTA to here IR3 = – (IH1+ IH2)


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2.11.5 Setting guidelines – insulated systems

As has been previously shown, the residual current detected by the relay on thefaulted feeder is equal to the sum of the charging currents flowing from the rest ofthe system. Further, the addition of the two healthy phase charging currents oneach feeder gives a total charging current which has a magnitude of three timesthe per phase value. Therefore, the total unbalance current detected by the relay isequal to three times the per phase charging current of the rest of the system.A typical relay setting may therefore be in the order of 30% of this value, ie. equalto the per phase charging current of the remaining system. Practically though, therequired setting may well be determined on site, where suitable settings can beadopted based upon practically obtained results. The use of the P140 relays’comprehensive measurement and fault recording facilities may prove useful in thisrespect.

2.11.6 Application to Petersen Coil earthed systems

Power systems are usually earthed in order to limit transient overvoltages duringarcing faults and also to assist with detection and clearance of earth faults.Impedance earthing has the advantage of limiting damage incurred by plantduring earth fault conditions and also limits the risk of explosive failure ofswitchgear, which is a danger to personnel. In addition, it limits touch and steppotentials at a substation or in the vicinity of an earth fault.If a high impedance device is used for earthing the system, or the system isunearthed, the earth fault current will be reduced but the steady state and transientovervoltages on the sound phases can be very high. Consequently, it is generallythe case that high impedance earthing will only be used in low/medium voltagenetworks in which it does not prove too costly to provide the necessary insulationagainst such overvoltages. Higher system voltages would normally be solidlyearthed or earthed via a low impedance.A special case of high impedance earthing via a reactor occurs when the inductiveearthing reactance is made equal to the total system capacitive reactance to earthat system frequency. This practice is widely referred to as Petersen (or resonant)Coil Earthing. With a correctly tuned system, the steady state earthfault current willbe zero, so that arcing earth faults become self extinguishing. Such a system can,if designed to do so, be run with one phase earthed for a long period until thecause of the fault is identified and rectified. With the effectiveness of this methodbeing dependent upon the correct tuning of the coil reactance to the systemcapacitive reactance, an expansion of the system at any time would clearlynecessitate an adjustment of the coil reactance. Such adjustment is sometimesautomated.Petersen Coil earthed systems are commonly found in areas where the powersystem consists mainly of rural overhead lines and can be particularly beneficial inlocations which are subject to a high incidence of transient faults. Transient earthfaults caused by lightning strikes, for example, can be extinguished by the PetersenCoil without the need for line outages.Figure 7 shows a source of generation earthed through a Petersen Coil, with anearth fault applied on the A Phase. Under this situation, it can be seen that the Aphase shunt capacitance becomes short circuited by the fault. Consequently, thecalculations show that if the reactance of the earthing coil is set correctly, theresulting steady state earth fault current will be zero.


Page 37 of 87

Figure 7: Current distribution in Peterson Coil earthed system

Prior to actually applying protective relays to provide earth fault protection onsystems which are earthed via a Petersen Coil, it is imperative to gain anunderstanding of the current distributions that occur under fault conditions on suchsystems. With this knowledge, it is then possible to decide on the type of relay thatmay be applied, ensuring that it is both set and connected correctly.Figure 8 shows a radial distribution system having a source which is earthed via aPetersen Coil. Three outgoing feeders are present, the lower of which has a phaseto earth fault applied on the C phase.

-Ib-Ic

Vba-jXc

Vca-jXc

(-Ic)(-Ib)

-jXc -jXc-jXcIf

(IL)Vba-jXc

jXL

If = -Ib - Ic + VanjXL

= 0 if Van = Ib + Ic jXL

ILA

-IB

N

BC

-IC

Current vectors for A phase fault


Page 38 of 87

Figure 8: Distribution of currents during a C phase to earth fault

Figures 9 (a, b and c) show vector diagrams for the previous system, assuming thatit is fully compensated (i.e. coil reactance fully tuned to system capacitance), inaddition to assuming a theoretical situation where no resistance is present either inthe earthing coil or in the feeder cables.Referring to the vector diagram illustrated in figure 9a, it can be seen that the Cphase to earth fault causes the voltages on the healthy phases to rise by a factor of√3. The A phase charging currents (Ia1, Ia2 and Ia3), are then shown to beleading the resultant A phase voltage by 90° and likewise for the B phasecharging currents with respect to the resultant Vb.The unbalance current detected by a core balance current transformer on thehealthy feeders can be seen to be a simple vector addition of Ia1 and Ib1, givinga residual current which lies at exactly 90° lagging the residual voltage (Figure9b). Clearly, as the healthy phase voltages have risen by a factor of √3, thecharging currents on these phases will also be √3 times larger than their steadystate values. Therefore, the magnitude of residual current, IR1, is equal to 3 x thesteady state per phase charging current.

-jXc1

Ia1Ib1

IR1

-jXc2

Ia2Ib2

IR2

-jXc3

Ia3Ib3

IR3

Ic3=IF

IH1

IH2

IH1+IH2IH3IF

IL

IL = IF + IH1 + IH2 - IH3

IL

jXL


Page 39 of 87

Figure 9: Theoretical case – no resistance present in XL or Xc

Note:The actual residual voltage used as a reference signal for directional earth faultrelays is phase shifted by 180° and is therefore shown as –3Vo in the vectordiagrams. This phase shift is automatically introduced within the P140 relays.On the faulted feeder, the residual current is the addition of the charging currenton the healthy phases (IH3) plus the fault current (IF).The net unbalance is thereforeequal to IL-IH1-IH2, as shown in Figure 9c.This situation may be more readily observed by considering the zero sequencenetwork for this fault condition. This is depicted in Figure 10.

IR1 = IH1

Ib1

Ia1

Vres = -3Vo

IL A

IH2

N

BC

IH3

IH1

Ia1

Ib1

3Vo

-IH2

IR3

Vres=-3Vo

–IH1

IL

a) Capacitive & inductive currents

b) Unfaulted line c) Faulted line IR3 = IF + IH3= IL – IH1 – IH2


Page 40 of 87

Figure 10: Zero sequence network showing residual currents

In comparing the residual currents occurring on the healthy and on the faultedfeeders (Figures 9b & 9c), it can be seen that the currents would be similar in bothmagnitude and phase; hence it would not be possible to apply a relay which couldprovide discrimination.However, as previously stated, the scenario of no resistance being present in thecoil or feeder cables is purely theoretical. Further consideration therefore needs tobe given to a practical application in which the resistive component is no longerignored – consider Figure 11.

–Vo3XL

IL

IR0F

IR0HIR0H

IH3 IH2 IH1

Xco

I0F

Faulted feeder

Healthy feeders

Key:

IR0F = Residual current on faulted feederIR0H = Residual current on healthy feederIt can therefore be seen that:-I0F = IL – IH1 – IH2 – IH3IR0F = IH3 + I0FSo:IR0F = IL – IH1 – IH2


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Figure 11: Practical case:- resistance present in XL and Xc

Figure 11a again shows the relationship between the capacitive currents, coilcurrent and residual voltage. It can now be seen that due to the presence ofresistance in the feeders, the healthy phase charging currents are now leadingtheir respective phase voltages by less than 90°. In a similar manner, the resistancepresent in the earthing coil has the effect of shifting the current, IL, to an angle lessthan 90° lagging. The result of these slight shifts in angles can be seen in Figures11b and 11c.The residual current now appears at an angle in excess of 90° from the polarisingvoltage for the unfaulted feeder and less than 90° on the faulted feeder. Hence, adirectional relay having a characteristic angle setting of 0° (with respect to thepolarising signal of –3Vo) could be applied to provide discrimination. i.e. thehealthy feeder residual current would appear within the restrain section of thecharacteristic but the residual current on the faulted feeder would lie within theoperate region – as shown in diagrams 11b and 11c.In practical systems, it may be found that a value of resistance is purposely insertedin parallel with the earthing coil. This serves two purposes; one is to actuallyincrease the level of earth fault current to a more practically detectable level andthe second is to increase the angular difference between the residual signals;again to aid in the application of discriminating protection.

b) Unfaulted lineIR1 = IH1

Vres = –3Vo

Zero torque line for 0° RCA

RestrainOperate

IL’ A

N

BC

(IH1 + IH2 + IH3)’3Vo

Resistive component in feederResistive componentin grounding coil

c) Faulted line

IR3 = IF + IH3= IL – IH1 – IH2

IR3

Vres =- 3Vo

-IH1 -IH2

IL

Restrain

Zero torque linefor 0° RCA

Operate

a) Capacitive & inductive currents with resistive components


Page 42 of 87

2.12 Operation of sensitive earth fault elementIt has been shown that the angular difference between the residual currents on thehealthy and faulted feeders allows the application of a directional relay whosezero torque line passes between the two currents. Two possibilities exist for thetype of protection element that may consequently be applied for earth faultdetection;1) A suitably sensitive directional earth fault relay having a relay characteristic

angle setting (RCA) of zero degrees, with the possibility of fine adjustmentabout this threshold.

2) A sensitive directional zero sequence wattmetric relay having similarrequirements to 1. above with respect to the required RCA settings.

Both stages 1 and 2 of the sensitive earth fault element of the P140 relay aresettable down to 0.2% of rated current and would therefore fulfill the requirementsof the first method listed above and could therefore be applied successfully.However, many utilities (particularly in central Europe) have standardized on thewattmetric method of earth fault detection, which is described in the followingsection.Zero sequence power measurement, as a derivative of Vo and Io, offers improvedrelay security against false operation with any spurious core balance CT output fornon earth fault conditions. This is also the case for a sensitive directional earth faultrelay having an adjustable Vo polarising threshold.Wattmetric CharacteristicThe previous analysis has shown that a small angular difference exists between thespill current on the healthy and faulted feeders. It can be seen that this angulardifference gives rise to active components of current which are in antiphase to oneanother. This is shown in Figure 12 below;

Figure 12: Resistive components of spill current

Consequently, the active components of zero sequence power will also lie insimilar planes and so a relay capable of detecting active power would be able tomake a discriminatory decision. i.e. if the wattmetric component of zero sequencepower was detected in the forward direction, then this would be indicative of afault on that feeder; if power was detected in the reverse direction, then the faultmust be present on an adjacent feeder or at the source.

IR3

Vres = –3Vo

–IH1 –IH2

IL

RestrainZero torque linefor 0° RCA

Operate

IR1

Active componentof residual current:Faulted Feeder

Active componentof residual current:Healthy Feeder


Page 43 of 87

For operation of the directional earth fault element within the P140 relays, all threeof the settable thresholds on the relay must be exceeded; namely the current"ISEF>", the voltage "ISEF>VNpol Set" and the power "PN> Setting".As can be seen from the following formula, the power setting within the relay menuis called PN> and is therefore calculated using residual rather than zero sequencequantities. Residual quantities are three times their respective zero sequence valuesand so the complete formula for operation is as shown below:Vres x Ires X Cos (φ – φc) = 9 x Vo x Io x Cos (φ – φc)where;φ = Angle between the Polarising Voltage (-Vres) and the Residual Currentφc = Relay Characteristic Angle (RCA) Setting (ISEF> Char Angle)Vres = Residual VoltageIres = Residual CurrentVo = Zero Sequence VoltageIo = Zero Sequence CurrentThe action of setting the PN> threshold to zero would effectively disable thewattmetric function and the relay would operate as a basic, sensitive directionalearth fault element. However, if this is required, then the 'SEF' option can beselected from the 'Sens E/F Options' cell in the menu.A further point to note is that when a power threshold other than zero is selected, aslight alteration is made to the angular boundaries of the directional characteristic.Rather than being ±90° from the RCA, they are made slightly narrower at ±85°.

2.13 Application considerationsRequired relay current and voltage connectionsReferring to the relevant application diagram for the P140 Relay, it should beapplied such that it’s direction for forward operation is looking down into theprotected feeder (away from the busbar), with a 0° RCA setting.As illustrated in the relay application diagram, it is usual for the earth fault elementto be driven from a core balance current transformer (CBCT). This eliminates thepossibility of spill current that may arise from slight mismatches between residuallyconnected line CT’s. It also enables a much lower CT ratio to be applied, therebyallowing the required protection sensitivity to be more easily achieved.

2.13.1 Calculation of required relay settings

As has been previously shown, for a fully compensated system, the residual currentdetected by the relay on the faulted feeder is equal to the coil current minus thesum of the charging currents flowing from the rest of the system. Further, as statedin the previous section, the addition of the two healthy phase charging currents oneach feeder gives a total charging current which has a magnitude of three timesthe steady state per phase value. Therefore, for a fully compensated system, thetotal unbalance current detected by the relay is equal to three times the per phasecharging current of the faulted circuit. A typical relay setting may therefore be inthe order of 30% of this value, i.e. equal to the per phase charging current of thefaulted circuit. Practically though, the required setting may well be determined onsite, where system faults can be applied and suitable settings can be adoptedbased upon practically obtained results.


Page 44 of 87

Also, it should be noted that in most situations, the system will not be fullycompensated and consequently a small level of steady state fault current will beallowed to flow. The residual current seen by the relay on the faulted feeder maythus be a larger value, which further emphasizes the fact that relay settings shouldbe based upon practical current levels, wherever possible.The above also holds true regarding the required Relay Characteristic Angle (RCA)setting. As has been shown earlier, a nominal RCA setting of 0º is required.However, fine tuning of this setting will require to be carried out on site in order toobtain the optimum setting in accordance with the levels of coil and feederresistances present. The loading and performance of the CT will also have an effectin this regard. The effect of CT magnetising current will be to create phase lead ofcurrent. Whilst this would assist with operation of faulted feeder relays it wouldreduce the stability margin of healthy feeder relays. A compromize can thereforebe reached through fine adjustment of the RCA. This is adjustable in 1° steps onthe P140 relays.

2.13.2 Application of settings to the relay

All of the relevant settings can be found under the SENSITIVE E/F column within therelay menu. Within the Sens E/F Options cell, there are two possibilities forselecting wattmetric earth fault protection; either on it’s own or in conjunction withlow impedance REF protection, which is described in Section 2.10.Note that the residual power setting, PN>, is scaled by the programmed CT andVT ratios in the relay.

2.14 Restricted earth fault protectionEarth faults occurring on a transformer winding or terminal may be of limitedmagnitude, either due to the impedance present in the earth path or by thepercentage of transformer winding that is involved in the fault. In general,particularly as the size of the transformer increases, it becomes unacceptable torely on time delayed protection to clear winding or terminal faults as this wouldlead to an increased amount of damage to the transformer. A common requirementis therefore to provide instantaneous phase and earth fault protection. Applyingdifferential protection across the transformer may fulfill these requirements.However, an earth fault occurring on the LV winding, particularly if it is of a limitedlevel, may not be detected by the differential relay, as it is only measuring thecorresponding HV current. Therefore, instantaneous protection that is restricted tooperating for transformer earth faults only is applied. This is referred to asrestricted, or balanced, earth fault protection (REF or BEF). The BEF terminology isusually used when the protection is applied to a delta winding.When applying differential protection such as REF, some technique must beemployed to give the protection stability under external fault conditions, ensuringthat relay operation only occurs for faults on the transformer winding/connections.Two methods are commonly used; bias or high impedance. The biasing techniqueoperates by measuring the level of through current flowing and altering the relaysensitivity accordingly. The high impedance technique ensures that the relay circuitis of sufficiently high impedance such that the differential voltage that may occurunder external fault conditions is less than that required to drive setting currentthrough the relay.The REF protection in the P341 should be applied as a high impedance differentialelement.Note that the high impedance REF element of the relay shares the same CT input asthe SEF protection. Hence, only one of these elements may be selected.


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A single DDB signal is available to indicate that the REF protection has tripped,DDB208. The state of the DDB signals can be programmed to be viewed in the“Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.All of the REF settings can be found at the bottom of the ‘SEF/REF Prot’n’ columnand are shown below, in addition to the SEF setting options:-


Min Max

GROUP 1SEF/REF PROT’N

Sens E/F Options SEF SEF, Wattmetric, Hi Z REF

IREF> Is 0.2 x In A 0.05 x In A 1 x In A 0.01 x In A

Note that CT requirements for REF protection are included in Section 6

2.14.1 High impedance restricted earth fault protection

The high impedance principle is best explained by considering a differentialscheme where one CT is saturated for an external fault, as shown in Figure 13.

Figure 13: High impedance principle

Healthy CT

Zm

RCT1

RL1

VS RST

RL2 RL4

RL3

R

RCT2

Zm A – G

Saturated CTProtected

circuit

Voltage across relay circuit

I F

VS = I F (RCT + 2RL )

S

Stabilising resistor RST limits spill current to IS (relay setting)

Where RR = relay burden

RST = VS – RRI


Page 46 of 87

If the relay circuit is considered to be a very high impedance, the secondarycurrent produced by the healthy CT will flow through the saturated CT. If CTmagnetising impedance of the saturated CT is considered to be negligible, themaximum voltage across the relay circuit will be equal to the secondary faultcurrent multiplied by the connected impedance, (RL3 + RL4 + RCT2).The relay can be made stable for this maximum applied voltage by increasing theoverall impedance of the relay circuit, such that the resulting current through therelay is less than its current setting. As the impedance of the relay input alone isrelatively low, a series connected external resistor is required. The value of thisresistor, RST, is calculated by the formula shown in Figure 13.The necessary relay connections for high impedance REF are shown in Figure 14:As can be seen from Figure 14, the high impedance protection uses an externaldifferential connection between the line CT’s and neutral CT. The SEF input is thenconnected to the differential circuit with a stabilising resistor in series.

Figure 14: High impedance REF relay/CT connections

2.14.2 Setting guidelines for high impedance REF

From the ‘Sens E/F Options’ cell, ‘Hi Z REF’ must be selected to enable thisprotection. The only setting cell then visible is ‘IREF> Is1’, which may beprogrammed with the required differential current setting. This would typically beset to give a primary operating current of either 30% of the minimum earth faultlevel for a resistance earthed system or between 10 and 60% of rated current fora solidly earthed system.The primary operating current (Iop) will be a function of the current transformerratio, the relay operating current (IREF> Is1), the number of current transformers inparallel with a relay element (n) and the magnetising current of each currenttransformer (Ie) at the stability voltage (Vs). This relationship can be expressed inthree ways:

RSTAB

A

B

C

SEF Input


Page 47 of 87

RST =Vs

IREF >Is1

Vp = 2 √ 2Vk ( Vf – Vk )

Ie < 1 xnIop

CT ratio– IREF >Is1

[IREF >Is1] <Iop

CT ratio– nIe

i. To determine the maximum current transformer magnetising current to achieve aspecific primary operating current with a particular relay operating current.

ii. To determine the maximum relay current setting to achieve a specific primaryoperating current with a given current transformer magnetising current.

iii. To express the protection primary operating current for a particular relayoperating current and with a particular level of magnetising current.

Iop = (CT ratio) x (IREF> Is1 = nIe)

In order to achieve the required primary operating current with the currenttransformers that are used, a current setting (IREF> Is1) must be selected for thehigh impedance element, as detailed in expression (ii) above. The setting of thestabilising resistor (RST) must be calculated in the following manner, where thesetting is a function of the required stability voltage setting (Vs) and the relaycurrent setting (IREF> Is1).

The above equation assumes negligible relay burden.The stabilising resistor supplied is continuously adjustable up to its maximumdeclared resistance.USE OF “METROSIL” NON-LINEAR RESISTORSMetrosils are used to limit the peak voltage developed by the current transformersunder internal fault conditions, to a value below the insulation level of the currenttransformers, relay and interconnecting leads, which are normally able towithstand 3000V peak.The following formulae should be used to estimate the peak transient voltage thatcould be produced for an internal fault. The peak voltage produced during aninternal fault will be a function of the current transformer kneepoint voltage and theprospective voltage that would be produced for an internal fault if currenttransformer saturation did not occur. This prospective voltage will be a function ofmaximum internal fault secondary current, the current transformer ratio, the currenttransformer secondary winding resistance , the current transformer lead resistanceto the common point, the relay lead resistance and the stabilising resistor value.

Vf = I‘f (RCT + 2RL + RST)


Page 48 of 87

I(rms) = 0.52Vs (rms) x √ 2

C

4

where Vp = peak voltage developed by the c.t. under internal fault conditions.Vk = current transformer knee-point voltage.Vf = maximum voltage that would be produced if c.t. saturation did not

occur.I‘f = maximum internal secondary fault current.RCT = current transformer secondary winding resistance.RL = maximum lead burden from current transformer to relay.RST = relay stabilising resistor.

When the value given by the formulae is greater than 3000V peak, metrosilsshould be applied. They are connected across the relay circuit and serve thepurpose of shunting the secondary current output of the current transformer fromthe relay in order to prevent very high secondary voltages.Metrosils are externally mounted and take the form of annular discs.Their operating characteristics follow the expression:

V = CI0.25

where V = Instantaneous voltage applied to the non-linear resistor(“metrosil”)

C = constant of the non-linear resistor (“metrosil” )I = instantaneous current through the non-linear resistor

(“metrosil”) .With a sinusoidal voltage applied across the metrosil, the RMS current would beapproximately 0.52x the peak current. This current value can be calculated asfollows;

where Vs(rms) = rms value of the sinusoidal voltage applied across themetrosil.

This is due to the fact that the current waveform through the non-linear resistor(“metrosil”) is not sinusoidal but appreciably distorted.For satisfactory application of a non-linear resistor (“metrosil”), it’s characteristicshould be such that it complies with the following requirements:i. At the relay voltage setting, the non-linear resistor (“metrosil”) current should be

as low as possible, but no greater than approximately 30mA r.m.s. for 1Acurrent transformers and approximately 100mA r.m.s. for 5A currenttransformers.

ii. At the maximum secondary current, the non-linear resistor (“metrosil”) shouldlimit the voltage to 1500V r.m.s. or 2120V peak for 0.25 second. At higherrelay voltage settings, it is not always possible to limit the fault voltage to1500V r.m.s., so higher fault voltages may have to be tolerated.

The following tables show the typical Metrosil types that will be required,depending on relay current rating, REF voltage setting etc.


Page 49 of 87

Metrosil Units for Relays with a 1 Amp CTThe Metrosil units with 1 Amp CTs have been designed to comply with thefollowing restrictions:-1. At the relay voltage setting, the Metrosil current should less than 30mA rms2. At the maximum secondary internal fault current the Metrosil unit should limit the

voltage to 1500V rms if possible.The Metrosil units normally recommended for use with 1Amp CT's are as shown inthe following table:

Relay voltage Nominal Recommended Metrosil typesetting characteristic

C β Single pole relay Triple pole relay

Up to 125V rms 450 0.25 600A/S1/S256 600A/S3/1/S802

125 to 300V rms 900 0.25 600A/S1/S1088 600A/S3/1/S1195

Note: Single pole Metrosil units are normally supplied without mounting bracketsunless otherwise specified by the customer

2.15 Residual over voltage/neutral voltage displacement protectionOn a healthy three phase power system, the addition of each of the three phase toearth voltages is nominally zero, as it is the vector addition of three balancedvectors at 120º to one another. However, when an earth fault occurs on theprimary system this balance is upset and a ‘residual’ voltage is produced.This could be measured, for example, at the secondary terminals of a voltagetransformer having a “broken delta” secondary connection. Hence, a relay thatmeasures residual voltage can be used to offer earth fault protection on such asystem. Note that this condition causes a rise in the neutral voltage with respect toearth that is commonly referred to as “neutral voltage displacement” or NVD.Alternatively, if the system is impedance or distribution transformer earthed, theneutral displacement voltage can be measured directly in the earth path via asingle phase VT.This type of protection can be used to provide earth fault protection irrespective ofwhether the system is connected to earth or not, and irrespective of the form ofearth connection and earth fault current level.Where embedded generation can be run in parallel with the external distributionsystem it is essential that this type of protection is provided at the interconnectionwith the external system. This will ensure that if the connection with the main supplysystem is lost due to external switching events, some type of reliable earth faultprotection is provided to isolate the generator from an earth fault. Loss ofconnection with the external supply system may result in the loss of the earthconnection, where this is provided at a distant transformer, and hence currentbased earth fault protection may be unreliable.


Page 50 of 87

Figure 15a: Residual voltage, solidly earthed systems

The residual over voltage protection function of the P341 relay consists of twostages with adjustable time delays.Two stages are included for the element to account for applications that requireboth alarm and trip stages, for example, an insulated system. It is common in sucha case for the system to have been designed to withstand the associated healthyphase over voltages for a number of hours following an earth fault. In suchapplications, an alarm is generated soon after the condition is detected, whichserves to indicate the presence of an earth fault on the system. This gives time forsystem operators to locate and isolate the fault. The second stage of the protectioncan issue a trip signal if the fault condition persists.A dedicated voltage input is provided for this protection function, this may be usedto measure the residual voltage supplied from either an open delta connected VT.Alternatively, the residual voltage may be derived internally from the three phaseto neutral voltage measurements. Where derived measurement is used the 3 phaseto neutral voltage must be supplied from either a 5-limb or three single phase VTs.

E SZS ZL

F

A - G

VA

VBVC

VA

VBVC VC VB

VB

VC

VRES

VRESVA

VC

VB

VA

VB

VC

Residual voltage at R (relay point) is dependant upon ZS /ZL ratio.

VRES2ZS1 ZS0 2ZL1 ZL0+ + +

= x 3 EZS0

G

R


Page 51 of 87

Figure 15b: Residual voltage, resistance earthed systems

These types of VT design allow the passage of residual flux and consequentlypermit the relay to derive the required residual voltage. In addition, the primarystar point of the VT must be earthed. A three limb VT has no path for residual fluxand is therefore unsuitable to supply the relay when residual voltage is required tobe derived from the phase to neutral voltage measurement.The residual voltage signal also provides a polarising voltage signal for thesensitive directional earth fault protection.Each stage of protection can be blocked by energising the relevant DDB signal,via the PSL (DDB156, DDB157), this can be used to improve grading withdownstream devices. DDB signals are also available to indicate the start and tripof each stage of protection, (Starts:- DDB256, DDB257, Trips:- DDB213,DDB214). The state of the DDB signals can be programmed to be viewed in the“Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.

A - G

E

N

G

ZE

SZS ZL

R F

VA - GS

G,F

VC - G VB - G

VC - GVB - G

RVA - GG,F G,F

VB - G

VC - G

VRES

VA - G

VC - G

VB - G

VRES

VA - G

VC - G

VB - G

VRES

VC - G

VB - G

VRES2ZS1 ZS0 2ZL1 ZL0+ + +

= x 3 EZS0

3ZE+

3ZE+


Page 52 of 87

Setting ranges and default settings for this element are shown in the following table


Min Max

GROUP 1RESIDUAL O/V NVD

VN Input Measured Measured, Derived

VN>1 Function DT 0.02 x In A 4 x In A 0.01 x In A

VN>1 Voltage Set 5 V 1V 50V 1VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


VN>1 Time Delay 1 s 0 s 100 s 0.01 s

VN>1 TMS 1 0.5 100 0.5

VN>1 tRESET 0 s 0 s 100 s 0.01 s

VN>2 Status DT Disabled or DT

VN>2 Voltage Set 5 V 1V 50V 1VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


VN>2 Time Delay 0 s 0 s 100 s 0.01 s

The IDMT characteristic available on the first stage is defined by the followingformula:

t = K x 40 / (1 – M)where;

K = Time Multiplier Setting (“VN>1 TMS”)t = Operating Time in SecondsM = Measured Residual Voltage/Relay Setting Voltage

(“VN>1 Voltage Set”)

2.15.1 Setting guidelines for residual over voltage/neutral voltage displacement protection

Stage 1 may be selected as either ‘IDMT’ (inverse time operating characteristic),‘DT’ (definite time operating characteristic) or ‘Disabled’, within the “VN>1Function” cell. Stage 2 operates with a definite time characteristic and is Enabled/Disabled in the “VN>2 Status” cell. The time delay (“VN>1 TMS” – for IDMTcurve; “V>1 Time Delay” , “V>2 Time Delay”– for definite time) should be selectedin accordance with normal relay co-ordination procedures to ensure correctdiscrimination for system faults.


Page 53 of 87

The Residual Over voltage protection can be set to operate from the voltagemeasured at the Vn input VT terminals or the residual voltage derived from thePhase-Neutral voltage inputs as selected by “VN Input”.The voltage setting applied to the elements is dependent upon the magnitude ofresidual voltage that is expected to occur during the earth fault condition. This inturn is dependent upon the method of system earthing employed and may becalculated by using the formulae previously given in Figs.15a and 15b. It mustalso be ensured that the relay is set above any standing level of residual voltagethat is present on the system.Note that IDMT characteristics are selectable on the first stage of NVD in orderthat elements located at various points on the system may be time graded with oneanother.It must also be ensured that the voltage setting of the element is set above anystanding level of residual voltage that is present on the system. A typical setting forresidual over voltage protection is 5V.The second stage of protection can be used as an alarm stage on unearthed orvery high impedance earthed systems where the system can be operated for anappreciable time under an earth fault condition.

2.16 Under voltage protectionWhere the P341 relay is being used as interconnection protection the undervoltage element is used to prevent power being exported to external loads at avoltage below normal allowable limits. Under voltage protection may also be usedfor back-up protection for a machine where it may be difficult to provide adequatesensitivity with phase current measuring elements.For an isolated generator, or isolated set of generators, a prolonged under voltagecondition could arise for a number of reasons. This could be due to failure ofautomatic voltage regulation (AVR) equipment or excessive load followingdisconnection from the main grid supply. Where there is a risk that a machinecould become disconnected from the main grid supply and energise external loadit is essential that under voltage protection is used. The embedded generator mustbe prevented from energising external customers with voltage below the statutorylimits imposed on the electricity supply authorities.A two stage under voltage element is provided. The element can be set to operatefrom phase-phase or phase-neutral voltages. Each stage has an independent timedelay that can be set to zero for instantaneous operation. Selectable, fixed Logic isincluded within the relay to allow the operation of the element to be inhibitedduring periods when the machine is isolated from the external system.Each stage of under voltage protection can be blocked by energising the relevantDDB signal via the PSL, (DDB158, DDB159). DDB signals are also available toindicate a 3 phase and per phase start and trip, (Starts:- DDB258-265, Trips:-DDB215-222). The state of the DDB signals can be programmed to be viewed inthe “Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.Setting ranges for this element are shown in the following table:


Page 54 of 87


Min Max

GROUP 1VOLT PROTECTION

UNDERVOLTAGE Sub Heading

V< Measur’t Mode Phase-Neutral Phase-Phase, Phase-Neutral

V< Operate Mode Any-phase Any Phase, Three phase

V<1 Function DT Disabled, DT, IDMT

V<1 Voltage Set 80 V 10V 120V 1VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


V<1 Time Delay 1 s 0 s 100 s 0.01 s

V<1 TMS 1 0.5 100 0.5

V<1 Poledead Inh Enabled Disabled, Enabled

V<2 Function DT Disabled, DT

V<2 Voltage Set 80 V 10V 120V 1VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


V<2 Time Delay 1 s 0 s 100 s 0.01 s

V<1 Poledead Inh Enabled Disabled, Enabled


t = K / (1 - M)where;

K = Time Multiplier Setting (V>1 TMS)t = Operating Time in SecondsM = Measured Voltage/Relay Setting Voltage (V<1 Voltage Set)


Page 55 of 87

2.16.1 Setting guidelines for under voltage protection

Stage 1 may be selected as either ‘IDMT’ (for inverse time delayed operation) ,‘DT’ (for definite time delayed operation) or ‘Disabled’, within the “V<1 Function”cell. Stage 2 is definite time only and is Enabled/Disabled in the “V<2 Status” cell.The time delay.(“V<1 TMS” - for IDMT curve; “V<1 Time Delay”, “V<2 TimeDelay” – for definite time) should be adjusted accordingly.The under voltage protection can be set to operate from Phase-Phase or Phase-Neutral voltage as selected by “V< Measur’t Mode”. Single or three phaseoperation can be selected in “V<1 Operate Mode”. When ‘Any Phase’ is selected,the element will operate if any phase voltage falls below setting, when ‘ThreePhase’ is selected the element will operate when all three phase voltages arebelow the setting.The under voltage threshold for each stage is set in the “V>1 Voltage Set” and“V>2 Voltage Set” cells.Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (eg. requirements ofG59 in the UK), the local electricity supply authority will advise settings for theelement. The settings must prevent the generator from exporting power to thesystem with voltage outside of the statutory limits imposed on the supply authority.For this mode of operation the element must be set to operate from phase to neutralvoltage, which will provide an additional degree of earth fault protection.The operating characteristic would normally be set to definite time, set “V<1Function” to ‘DT’. The time delay, “V<1 Time Delay”, should be set to co-ordinatewith downstream. Additionally, the delay should be long enough to preventunwanted operation of the under voltage protection for transient voltage dips.These may occur during clearance of faults further into the power system or bystarting of local machines. The required time delay would typically be in excess of3s – 5s.As previously stated, local regulations for operating a generator in parallel with theexternal electricity supply may dictate the settings used for the under voltageprotection. For example in the UK the protection should be set to measure phase toneutral voltage and trip at 90% of nominal voltage in a time of less than 0.5s.The second stage can be used as an alarm stage to warn the user of unusualvoltage conditions so that corrections can be made. This could be useful if themachine is being operated with the AVR selected to manual control.To prevent operation of any under voltage stage during normal shutdown of thegenerator “poledead” logic is included in the relay. This is facilitated by selecting“V Poledead Inh” to ‘Enabled’. This will ensure that when a poledead condition isdetected (ie. all phase currents below the undercurrent threshold or CB Open, asdetermined by an opto isolator and the PSL) the under voltage element will beinhibited.

2.17 Over voltage protectionAn over voltage condition could arise when a generator is running but notconnected to a power system, or where a generator is providing power to anislanded power system. Such an over voltage could arise in the event of a faultwith automatic voltage regulating equipment or if the voltage regulator is set formanual control and an operator error is made. Over voltage protection should beset to prevent possible damage to generator insulation, prolonged over-fluxing ofthe generating plant, or damage to power system loads.


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When a generator is synchronised to a power system with other sources, an overvoltage could arise if the generator is lightly loaded supplying a high level ofpower system capacitive charging current. An over voltage condition might alsobe possible following a system separation, where a generator might experiencefull-load rejection whilst still being connected to part of the original power system.The automatic voltage regulating equipment and machine governor should quicklyrespond to correct the over voltage condition in these cases. However, overvoltage protection is advisable to cater for a possible failure of the voltageregulator or for the regulator having been set to manual control.A two stage over voltage element is provided. The element can be set to operatefrom phase-phase or phase-neutral voltages. Each stage has an independent timedelay which can be set to zero for instantaneous operation.Each stage of over voltage protection can be blocked by energising the relevantDDB signal via the PSL, (DDB160, DDB161). DDB signals are also available toindicate a 3 phase and per phase start and trip, (Starts:- DDB266-273, Trips:-DDB223-230). The state of the DDB signals can be programmed to be viewed inthe “Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.Setting ranges for this element are shown in the following table


Min Max

GROUPVOLT PROTECTION

OVERVOLTAGE Sub Heading

V> Measur’t Mode Phase-Neutral Phase-Phase, Phase-Neutral,

V> Operate Mode Any-phase Any Phase, Three phase

V>1 Function DT Disabled, DT, IDMT

V>1 Voltage Set 150 V 60V 185V 1VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


V>1 Time Delay 1 s 0 s 100 s 0.01 s

V>1 TMS 1 0.5 100 0.5

V>2 Status DT Disabled, DT

V>2 Voltage Set 130 V 60V 185V 1VVn=100/120V) (Vn=100/120V) (Vn=100/120V) (Vn=100/120V)


V>2 Time Delay 1 s 0 s 100 s 0.01 s


Page 57 of 87


t = K / (M - 1)where;

K = Time Multiplier Setting (“V>1 TMS”)t = Operating Time in SecondsM = Measured Voltage/Relay Setting Voltage (“V>1 Voltage Set”)

2.17.1 Setting guidelines for over voltage protection

Stage 1 may be selected as either ‘IDMT’ (for inverse time delayed operation), ‘DT’(for definite time delayed operation) or ‘Disabled’, within the “V>1 Function” cell.Stage 2 has a definite time delayed characteristic and is Enabled/Disabled in the“V>2 Status” cell. The time delay.(“V>1 TMS” - for IDMT curve; “V>1 Time Delay”,“V>2 Time Delay” - for definite time) should be selected accordingly.The over voltage protection can be set to operate from Phase-Phase or Phase-Neutral voltage as selected by “V> Measur’t Mode” cell. Single or three phaseoperation can be selected in “V> Operate Mode” cell. When ‘Any Phase’ isselected the element will operate if any phase voltage falls below setting, when‘Three Phase’ is selected the element will operate when all three phase voltages areabove the setting.Generators can typically withstand a 5% over voltage condition continuously.The withstand times for higher over voltages should be declared by the generatormanufacturer.To prevent operation during earth faults, the element should operate from thephase-phase voltages, to achieve this “V>1 Measur’t Mode” can be set to ‘Phase-Phase’ with “V>1 Operating Mode” set to ‘Three-Phase’. The over voltagethreshold, “V>1 Voltage Set”, should typically be set to 100%-120% of the nominalphase-phase voltage seen by the relay. The time delay, “V>1 Time Delay”, shouldbe set to prevent unwanted tripping of the delayed over voltage protection functiondue to transient over voltages that do not pose a risk to the generating plant; eg.following load rejection where correct AVR/Governor control occurs. The typicaldelay to be applied would be 1s – 3s, with a longer delay being applied for lowervoltage threshold settings.The second stage can be used to provide instantaneous high-set over voltageprotection. The typical threshold setting to be applied, “V>2 Voltage Set”, wouldbe 130 – 150% of the nominal phase-phase voltage seen by the relay, dependingon plant manufacturers’ advice. For instantaneous operation, the time delay, “V>2Time Delay”, should be set to 0s.Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (eg. requirements ofG59 in the UK), the local electricity supply authority may advise settings for theelement. The settings must prevent the generator from exporting power to thesystem with voltages outside of the statutory limits imposed on the supply authority.For example in the UK the protection should be set to measure phase to neutralvoltage and trip at 110% of nominal voltage in a time of less than 0.5s.If phase to neutral operation is selected, the element may operate during earthfaults, where the phase-neutral voltage can rise significantly.


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2.18 Under frequency protectionUnder frequency operation of a generator will occur when the power system loadexceeds the prime mover capability of an islanded generator or group ofgenerators. Power system overloading can arise when a power system becomessplit, with load left connected to a set of ‘islanded’ generators that is in excess oftheir capacity. Automatic load shedding could compensate for such events. In thiscase, under frequency operation would be a transient condition. This characteristicmakes under frequency protection a simple form of “Loss of Mains” protection onsystem where it is expected that the islanded load attached to the machine whenthe grid connection fails exceeds the generator capacity. In the event of the loadshedding being unsuccessful, the generators should be provided with backupunder frequency protection. Where the P341 relay is being used asinterconnection protection the under frequency element is also used to preventpower being exported to external loads at a frequency below normal allowablelimits.Four independent definite time-delayed stages of under frequency protection areoffered. Two additional over frequency stages can also be reconfigured as underfrequency protection by reprogramming the Programmable Scheme Logic. As wellas being able to initiate generator tripping, the under frequency protection canalso be arranged to initiate local load-shedding, where appropriate.Energising the relevant DDB signal, via the PSL (DDB162-DDB165), can block eachstage of underfrequency protection. DDB signals are also available to indicate startand trip of each stage, (Starts:- DDB301-304, Trips:- DDB231-234). The state ofthe DDB signals can be programmed to be viewed in the “Monitor Bit x” cells ofthe “COMMISSION TESTS” column in the relay.Setting ranges for this element are shown in the following table.


Page 59 of 87


Min Max

GROUP 1FREQ PROTECTION

UNDER FREQUENCY Sub Heading

F<1 Status Enabled Disabled, Enabled

F<1 Setting 49.5 Hz 45 Hz 65 Hz 0.01 Hz

F<1 Time Delay 4s 0s 100s 0.01s


F>2 Setting 49.5 Hz 45 Hz 65 Hz 0.01 Hz

F<2 Time Delay 4 s 0s 100 s 0.01s





F<4 Setting 49.5 Hz 45 Hz 65 Hz 0.01 Hz


F< Function Link 1111 Bit 0 - Enable Block F<1 during PoledeadBit 1 - Enable Block F<2 during PoledeadBit 2 - Enable Block F<3 during PoledeadBit 3 - Enable Block F<4 during Poledead

2.18.1 Setting guidelines for under frequency protection

Each stage of under frequency protection may be selected as ‘Enabled’ or‘Disabled’, within the “F<x Status” cells. The frequency pickup setting,“F<x Setting”, and time delays, “F<x Time Delay”, for each stage should beselected accordingly.The protection function should be set so that declared frequency-time limits for thegenerating set or system are not infringed. Typically, a 10% under frequencycondition should be continuously sustainable by the machine however systemconsiderations may mean that settings much closer to the nominal frequency arespecified.For industrial generation schemes, where generation and loads may be undercommon control/ownership, the P341 under frequency protection function couldbe used to initiate local system load-shedding. Four stage under frequency/load


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shedding can be provided. The final stage of under frequency protection shouldbe used to trip the generator.Where separate load shedding equipment is provided, the under frequencyprotection should co-ordinate with it. This will ensure that generator tripping willnot occur in the event of successful load shedding following a system overload.Two stages of under frequency protection could be set-up, as illustrated in Figure16, to co-ordinate with multi-stage system load-shedding.

Figure 16: Co-ordination of underfrequency protection function with system loadshedding.

To prevent operation of any under frequency stage during normal shutdown of thegenerator “poledead” logic is included in the relay. This is facilitated for eachstage by setting the relevant bit in “F< Function Link”. For example if “F< FunctionLink” is set to 0111,Stage 1, 2 and 3 of under frequency protection will beblocked when the generator CB is open. Selective blocking of the frequencyprotection stages in this way will allow a single stage of protection to be enabledduring synchronisation or offline running to prevent unsynchronised over fluxing ofthe machine. When the machine is synchronised, and the CB closed, all stages offrequency protection will be enabled providing a multi stage load shed scheme ifdesired.

B

Frequency

fn

F1<

F2<

t2 t1 Time

Turbine prohibited area

C

B

A

System frequency response withminimum load shed for recovery

System frequency response withunder shedding of load

Optimum underfrequencyprotection characteristic

A

C


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Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (eg. requirements ofG.59 in the UK), the local electricity supply authority may advise settings for theelement. The settings must prevent the generator from exporting power to thesystem with frequency outside of the statutory limits imposed on the supplyauthority. For example, in the UK the under frequency protection should be set to47Hz with a trip time of less than 0.5s.

2.19 Over frequency protection functionOver frequency running of a generator arises when the mechanical power input tothe alternator is in excess of the electrical load and mechanical losses. The mostcommon occurrence of over frequency is after substantial loss of load. When a risein running speed occurs, the governor should quickly respond to reduce themechanical input power, so that normal running speed is quickly regained.Over frequency protection may be required as a backup protection function tocater for governor or throttle control failure following loss of load or duringunsynchronised or islanded running.Moderate over frequency operation of a generator is not as potentially threateningto the generator and other electrical plant as under frequency running. Action canbe taken at the generating plant to correct the situation without necessarily shuttingdown the generator. However, where the P341 relay is being used asinterconnection protection the under frequency element will prevent power beingexported to external loads at a frequency higher than normal allowable limits.Two independent time-delayed stages of over frequency protection are provided.Each stage of protection can be blocked by energising the relevant DDB signal viathe PSL, (DDB166, DDB167). DDB signals are also available to indicate start andtrip of each stage, (Starts:- DDB301-304, Trips:- DDB231-234). The state of theDDB signals can be programmed to be viewed in the “Monitor Bit x” cells of the“COMMISSION TESTS” column in the relay.Setting ranges for this element are shown in the following table


Min Max

GROUP 1FREQ PROTECTION

OVER FREQUENCY Sub Heading

F>1 Status Enabled Disabled, Enabled


F>1 Time Delay 4s 0s 100s 0.01s

F>2 Status Enabled Disabled, Enabled


F>2 Time Delay 4s 0s 100s 0.01s


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2.19.1 Setting guidelines for over frequency protection

Each stage of over frequency protection may be selected as Enabled or Disabled,within the “F>x Status” cells. The frequency pickup setting, “F>x Setting”, and timedelays, “F>x Time Delay”, for each stage should be selected accordingly.The P341 over frequency settings should be selected to co-ordinate with normal,transient over frequency excursions following full-load rejection. The generatormanufacturer should declare the expected transient over frequency behaviour,which should comply with international governor response standards. A typicalover frequency setting would be 10% above nominal.Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (e.g. requirements ofG.59 in the UK), the local electricity supply authority may advise settings for theelement. The settings must prevent the generator from exporting power to thesystem with frequency outside of the statutory limits imposed on the supplyauthority. For example in the UK over frequency protection should be set to 50.5Hzwith a trip time of less than 0.5s.

2.20 Circuit breaker fail protection (CBF)Following inception of a fault one or more main protection devices will operateand issue a trip output to the circuit breaker(s) associated with the faulted circuit.Operation of the circuit breaker is essential to isolate the fault, and preventdamage/further damage to the power system. For transmission/sub-transmssionsystems, slow fault clearance can also threaten system stability. It is thereforecommon practice to install circuit breaker failure protection, which monitors that thecircuit breaker has opened within a reasonable time. If the fault current has notbeen interrupted following a set time delay from circuit breaker trip initiation,breaker failure protection (CBF) will operate.CBF operation can be used to backtrip upstream circuit breakers to ensure that thefault is isolated correctly. CBF operation can also reset all start output contacts,ensuring that any blocks asserted on upstream protection are removed.

2.20.1 Breaker failure protection configurations

The circuit breaker failure protection incorporates two timers, "CB Fail 1 Timer"and "CB Fail 2 Timer", allowing configuration for the following scenarios:• Simple CBF, where only "CB Fail 1 Timer" is enabled. For any protection trip,

the "CB Fail 1 Timer" is started, and normally reset when the circuit breakeropens to isolate the fault. If breaker opening is not detected, "CB Fail 1 Timer"times out and closes an output contact assigned to breaker fail (using theprogrammable scheme logic). This contact is used to backtrip upstreamswitchgear, generally tripping all infeeds connected to the same busbar section.

• A re-tripping scheme, plus delayed backtripping. Here, "CB Fail 1 Timer" isused to route a trip to a second trip circuit of the same circuit breaker.This requires duplicated circuit breaker trip coils, and is known as re-tripping.Should re-tripping fail to open the circuit breaker, a backtrip may be issuedfollowing an additional time delay. The backtrip uses "CB Fail 2 Timer", whichis also started at the instant of the initial protection element trip.

CBF elements "CB Fail 1 Timer" and "CB Fail 2 Timer" can be configured tooperate for trips triggered by protection elements within the relay or via anexternal protection trip. The latter is acheived by allocating one of the relay opto-isolated inputs to "External Trip" using the programmable scheme logic.


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2.20.2 Reset mechanisms for breaker fail timers

It is common practice to use low set undercurrent elements in protection relays toindicate that circuit breaker poles have interrupted the fault or load current, asrequired. This covers the following situations:• Where circuit breaker auxiliary contacts are defective, or cannot be relied

upon to definitely indicate that the breaker has tripped.• Where a circuit breaker has started to open but has become jammed.

This may result in continued arcing at the primary contacts, with an additionalarcing resistance in the fault current path. Should this resistance severely limitfault current, the initiating protection element may reset. Thus, reset of theelement may not give a reliable indication that the circuit breaker has openedfully.

For any protection function requiring current to operate, the relay uses operationof undercurrent elements (I<) to detect that the necessary circuit breaker poleshave tripped and reset the CB fail timers. However, the undercurrent elements maynot be reliable methods of resetting circuit breaker fail in all applications.For example:• Where non-current operated protection, such as under/overvoltage or under/

overfrequency, derives measurements from a line connected voltagetransformer. Here, I< only gives a reliable reset method if the protected circuitwould always have load current flowing. Detecting drop-off of the initiatingprotection element might be a more reliable method.

• Where non-current operated protection, such as under/overvoltage or under/overfrequency, derives measurements from a busbar connected voltagetransformer. Again using I< would rely upon the feeder normally being loaded.Also, tripping the circuit breaker may not remove the initiating condition fromthe busbar, and hence drop-off of the protection element may not occur. In suchcases, the position of the circuit breaker auxiliary contacts may give the bestreset method.

Resetting of the CBF is possible from a breaker open indication (from the relay'spole dead logic) or from a protection reset. In these cases resetting is only allowedprovided the undercurrent elements have also reset. The resetting options aresummarized in the following table.


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Initiation (Menu selectable) CB fail timer reset mechnaism

Current based protection The resetting mechanism is fixed(eg. 50/51/46/21/87..)[IA< operates] &[IB< operates] &[IC< operates] &[IN< operates]

Sensitive earth fault element The resetting mechanism is fixed.[ISEF< operates]

Non-current based protection Three options are available. The user can(eg. 27/59/81/32L..) select from the following options.

[All I< and IN< elements operate][Protection element reset] AND [All I< andIN< elements operate]CB open (all 3 poles) AND [All I< and IN<elements operate]

External protection Three options are available.The user can select any or all of the options.[All I< and IN< elements operate][External trip reset] AND [All I< and IN<elements operate]CB open (all 3 poles) AND [All I< and IN<elements operate]


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The selection in the relay menu is grouped as follows:


Min Max

NEG SEQ O/CGROUP 1

BREAKER FAIL Sub-Heading

CB Fail 1 Status Enabled Enabled, Disabled

CB Fail 1 Timer 0.2s 0s 10s 0.01s

CB Fail 2 Status Disabled Enabled, Disabled

CB Fail 2 Timer 0.4s 0s 10s 0.01s

Volt Prot Reset CB Open & I< I< Only, CB Open & I<, Prot Reset & I<

Ext Prot Reset CB Open & I< I< Only, CB Open & I<, Prot Reset & I<

UNDERCURRENT Sub-Heading

I< Current Set 0.1In 0.02In 3.2In 0.01In

IN< Current Set 0.1In 0.02In 3.2In 0.01In

ISEF< Current 0.02In 0.001In 0.8In 0.0005In

BLOCKED O/C Sub-Heading

CBF Blocks I> Disabled Enabled, Disabled

CBF Blocks IN> Disabled Enabled, Disabled

The "CBF Blocks I>" and "CBF Blocks IN>" settings are used to remove startsissued from the overcurrent and earth elements respectively following a breaker failtime out. The start is removed when the cell is set to Enabled.


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2.21 Typical settings

2.21.1 Breaker fail timer settings

Typical timer settings to use are as follows:

CB fail reset mechanism tBF time delay Typical delay for2º cycle circuitbreaker

Initiating element reset CB interrupting time + 50 + 50 + 10 + 50element reset time (max.) = 160 ms+ error in tBF timer + safety margin

CB open CB auxiliary contacts 50 + 10 + 50opening/closing time = 110 ms(max.) + error in tBF timer+ safety margin

Undercurrent elements CB interrupting time + 50 + 25 + 50undercurrent element = 125 ms(max.) + safety marginoperating time

Note that all CB Fail resetting involves the operation of the undercurrent elements.Where element reset or CB open resetting is used the undercurrent time settingshould still be used if this proves to be the worst case.The examples above consider direct tripping of a 2º cycle circuit breaker.Note that where auxiliary tripping relays are used, an additional 10-15ms must beadded to allow for trip relay operation.

2.21.2 Breaker fail undercurrent settings

The phase undercurrent settings (I<) must be set less than load current, to ensurethat I< operation indicates that the circuit breaker pole is open. A typical settingfor overhead line or cable circuits is 20% In, with 5% In common for generatorcircuit breaker CBF.The sensitive earth fault protection (SEF) and standard earth fault undercurrentelements must be set less than the respective trip setting, typically as follows:

ISEF<= (ISEF> trip) / 2IN< = (IN> trip) / 2


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Section 3. OTHER PROTECTION CONSIDERATIONS

3.1 Blocked overcurrent protectionBlocked overcurrent protection involves the use of start contacts from downstreamrelays wired onto blocking inputs of upstream relays. This allows identical currentand time settings to be employed on each of the relays involved in the scheme, asthe relay nearest to the fault does not receive a blocking signal and hence tripsdiscriminatively. This type of scheme therefore reduces the amount of requiredgrading stages and consequently fault clearance times.The principle of blocked overcurrent protection may be extended by setting fastacting overcurrent elements on the P341 which are then arranged to be blockedby start contacts from the relays protecting the outgoing feeders. The fast actingelement is thus allowed to trip for a fault condition on the busbar but is stable forexternal feeder faults by means of the blocking signal. This type of schemetherefore provides much reduced fault clearance times for busbar faults than wouldbe the case with conventional time graded overcurrent protection. The availabilityof multiple overcurrent and earth fault stages means that back-up time gradedovercurrent protection is also provided. This is shown in Figures 17a and 17b.

Figure 17a: Simple busbar blocking scheme (single incomer)

Generator

P341Block highset element

CB fail backtrip

O/Pfromstart

contact

P140 P140 P140 P140

Feeder 1 Feeder 2 Feeder 3 Feeder 4

CBfailbacktrip


Page 68 of 87

Figure 17b: Simple busbar blocking scheme (single incomer)

The P140/P341 relays have start outputs available from each stage of each of theovercurrent and earth fault elements, including sensitive earth fault. These startsignals may then be routed to output contacts by programming accordingly.Each stage is also capable of being blocked by being programmed to the relevantopto-isolated input.Note that the P341 relays provide a 50V field supply for powering the opto-inputs. Hence, in the unlikely event of the faulure of this supply, blocking of thatrelay would not be possible. For this reason, the field supply is supervized and if afailure is detected, it is possible, via the relays programmable scheme logic, toprovide an output alarm contact. This contact can then be used to signal an alarmwithin the substation. Alternatively, the relays scheme logic could be arranged toblock any of the overcurrent/earth fault stages that would operate non-discriminatively due to the blocking signal failure.For further guidance on the use of blocked overcurrent schemes refer to ALSTOMT&D Protection & Control Ltd.

10.0

1.0

0.10.08

0.011.0 10.0 100.0

Time(secs)

Current (kA)

P341 IDMT elementIDMT margin

Feeder IDMT elementP341 high set element

Feeder start contactTime to block


Page 69 of 87

Section 4. APPLICATION OF NON-PROTECTION FUNCTIONS

4.1 Voltage transformer supervision (VTS)The voltage transformer supervision (VTS) feature is used to detect failure of the acvoltage inputs to the relay. This may be caused by internal voltage transformerfaults, overloading, or faults on the interconnecting wiring to relays. This usuallyresults in one or more VT fuses blowing. Following a failure of the ac voltage inputthere would be a misrepresentation of the phase voltages on the power system, asmeasured by the relay, which may result in maloperation.The VTS logic in the relay is designed to detect the voltage failure, andautomatically adjust the configuration of protection elements whose stability wouldotherwise be compromized. A time-delayed alarm output is also available.There are three main aspects to consider regarding the failure of the VT supply.These are defined below:1. Loss of one or two phase voltages2. Loss of all three phase voltages under load conditions3. Absence of three phase voltages upon line energisationThe VTS feature within the relay operates on detection of negative phase sequence(nps) voltage without the presence of negative phase sequence current. This givesoperation for the loss of one or two phase voltages. Stability of the VTS function isassured during system fault conditions, by the presence of nps current. The use ofnegative sequence quantities ensures correct operation even where three-limb or‘V’ connected VT’s are used.Negative Sequence VTS Element:The negative sequence thresholds used by the element are V2 = 10V (or 40V on a380/440V rated relay), and I2 = 0.05 to 0.5In settable (defaulted to 0.05In).

4.1.1 Loss of all three phase voltages under load conditions

Under the loss of all three phase voltages to the relay, there will be no negativephase sequence quantities present to operate the VTS function. However, undersuch circumstances, a collapse of the three phase voltages will occur. If this isdetected without a corresponding change in any of the phase current signals(which would be indicative of a fault), then a VTS condition will be raised. Inpractice, the relay detects the presence of superimposed current signals, which arechanges in the current applied to the relay. These signals are generated bycomparison of the present value of the current with that exactly one cyclepreviously. Under normal load conditions, the value of superimposed currentshould therefore be zero. Under a fault condition a superimposed current signalwill be generated which will prevent operation of the VTS.The phase voltage level detectors are fixed and will drop off at 10V (40V on 380/440V relays) and pickup at 30V (120V on 380/440V relays).The sensitivity of the superimposed current elements is fixed at 0.1In.

4.1.2 Absence of three phase voltages upon line energisation

If a VT were inadvertently left isolated prior to line energisation, incorrectoperation of voltage dependent elements could result. The previous VTS elementdetected three phase VT failure by absence of all 3 phase voltages with nocorresponding change in current. On line energisation there will, however, be achange in current (as a result of load or line charging current for example).


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An alternative method of detecting 3 phase VT failure is therefore required on lineenergisation.The absence of measured voltage on all 3 phases on line energisation can be as aresult of 2 conditions. The first is a 3 phase VT failure and the second is a close upthree phase fault. The first condition would require blocking of the voltagedependent function and the second would require tripping. To differentiatebetween these 2 conditions an overcurrent level detector (VTS I> Inhibit) is usedwhich will prevent a VTS block from being issued if it operates. This element shouldbe set in excess of any non-fault based currents on line energisation (load, linecharging current, transformer inrush current if applicable) but below the level ofcurrent produced by a close up 3 phase fault. If the line is now closed where a 3phase VT failure is present the overcurrent detector will not operate and a VTSblock will be applied. Closing onto a three phase fault will result in operation ofthe overcurrent detector and prevent a VTS block being applied.This logic will only be enabled during a live line condition (as indicated by therelays pole dead logic) to prevent operation under dead system conditions ie.where no voltage will be present and the VTS I> Inhibit overcurrent element will notbe picked up.

4.1.3 Menu settings

The VTS settings are found in the ‘SUPERVISION’ column of the relay menu.The relevant settings are detailed below.


Min Max

SUPERVISION

VTS Status Blocking Blocking, Indication

VTS Reset Mode Manual Manual, Auto

VTS Time Delay 5s 1s 10s 0.1s

VTS I> Inhibit 10In 0.08In 32In 0.01In

VTS I2> Inhibit 0.05In 0.05In 0.5In 0.01In

The relay may respond as follows, on operation of any VTS element:• VTS set to provide alarm indication only.• Optional blocking of voltage dependent protection elements.• Optional conversion of directional overcurrent elements to non-directional

protection (available when set to Blocking mode only). These settings are foundin the Function Links cell of the relevant protection element columns in the menu.

The VTS I> Inhibit or VTS I2> Inhibit elements are used to override a VTS block inthe event of a fault occurring on the system which could trigger the VTS logic.Once the VTS block has been established, however, it would be undesirable forsubsequent system faults to override the block. The VTS block will therefore belatched after a user settable time delay ‘VTS Time Delay’.


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Once the signal has latched then two methods of resetting are available. The first ismanually via the front panel interface (or remote communications) provided theVTS condition has been removed and secondly, when in ‘Auto’ mode, by therestoration of the 3 phase voltages above the phase level detector settingsmentioned previously.A VTS indication will be given after the VTS Time Delay has expired. In the casewhere the VTS is set to indicate only the relay may potentially maloperate,depending on which protection elements are enabled. In this case the VTSindication will be given prior to the VTS time delay expiring if a trip signal isgiven.Where a miniature circuit breaker (MCB) is used to protect the voltage transformerac output circuits, it is common to use MCB auxiliary contacts to indicate a threephase output disconnection. As previously described, it is possible for the VTS logicto operate correctly without this input. However, this facility has been provided forcompatibility with various utilities current practices. Energising an opto-isolatedinput assigned to “MCB Open” on the relay will therefore provide the necessaryblock.Where directional overcurrent elements are converted to non-directional protectionon VTS operation, it must be ensured that the current pick-up setting of theseelements is higher than full load current.

4.2 Current transformer supervisionThe current transformer supervision feature is used to detect failure of one or moreof the ac phase current inputs to the relay. Failure of a phase CT or an open circuitof the interconnecting wiring can result in incorrect operation of any currentoperated element. Additionally, interruption in the ac current circuits risksdangerous CT secondary voltages being generated.

4.2.1 The CT supervision feature

The CT supervision feature operates on detection of derived zero sequence current,in the absence of corresponding derived zero sequence voltage that wouldnormally accompany it.The voltage transformer connection used must be able to refer zero sequencevoltages from the primary to the secondary side. Thus, this element should only beenabled where the VT is of five limb construction, or comprizes three single phaseunits, and has the primary star point earthed.Operation of the element will produce a time-delayed alarm visible on the LCD andevent record (plus DDB 115: CT Fail Alarm), with an instantaneous block (DDB290: CTS Block) for inhibition of protection elements. Protection elements operatingfrom derived quantities (Broken Conductor, Earth Fault2, Neg Seq O/C) arealways blocked on operation of the CT supervision element; other protections canbe selectively blocked by customising the PSL, integrating DDB 290: CTS Blockwith the protection function logic.The following table shows the relay menu for the CT Supervision element, includingthe available setting ranges and factory defaults:-


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Min Max

GROUP 1SUPERVISION

CT Supervision Sub Heading

CTS Status Disabled Enabled/Disabled N/A

CTS VN< Inhibit 1 0.5/2V 22/88V 0.5/2VFor For For

110/440V 110/440V 110/440Vrespectively respectively respectively

CTS IN> Set 0 0.08 x In 4 x In 0.01 x In

CTS Time Delay 5 0s 10s 1s

4.2.2 Setting the CT supervision element

The residual voltage setting, "CTS Vn< Inhibit" and the residual current setting,"CTS In> set", should be set to avoid unwanted operation during healthy systemconditions. For example "CTS Vn< Inhibit" should be set to 120% of the maximumsteady state residual voltage. The "CTS In> set" will typically be set belowminimum load current. The time-delayed alarm, "CTS Time Delay", is generally setto 5 seconds.Where the magnitude of residual voltage during an earth fault is unpredictable, theelement can be disabled to prevent protection elements being blocked during faultconditions.

4.3 Circuit breaker state monitoringAn operator at a remote location requires a reliable indication of the state of theswitchgear. Without an indication that each circuit breaker is either open orclosed, the operator has insufficient information to decide on switching operations.The relay incorporates circuit breaker state monitoring, giving an indication of theposition of the circuit breaker, or, if the state is unknown, an alarm is raised.

4.3.1 Circuit breaker state monitoring features

MiCOM relays can be set to monitor normally open (52a) and normally closed(52b) auxiliary contacts of the circuit breaker. Under healthy conditions, thesecontacts will be in opposite states. Should both sets of contacts be open, this wouldindicate one of the following conditions:• Auxiliary contacts/wiring defective• Circuit Breaker (CB) is defective• CB is in isolated positionShould both sets of contacts be closed, only one of the following two conditionswould apply:• Auxiliary contacts/wiring defective• Circuit Breaker (CB) is defective


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A normally open/normally closed output contact can be assigned to this functionvia the programmable scheme logic (PSL). The time delay is set to avoid unwantedoperation during normal switching duties.In the CB CONTROL column of the relay menu there is a setting called ‘CB StatusInput’. This cell can be set at one of the following four options:None52A52BBoth 52A and 52BWhere ‘None’ is selected no CB status will be available. This will directly affectany function within the relay that requires this signal, for example CB control, auto-reclose, etc. Where only 52A is used on its own then the relay will assume a 52Bsignal from the absence of the 52A signal. Circuit breaker status information willbe available in this case but no discrepancy alarm will be available. The above isalso true where only a 52B is used. If both 52A and 52B are used then statusinformation will be available and in addition a discrepancy alarm will be possible,according to the following table. 52A and 52B inputs are assigned to relay opto-isolated inputs via the PSL.

Auxiliary contact position CB state detected Action

52A 52B

Open Closed Breaker open Circuit breaker healthy

Closed Open Breaker closed Circuit breaker healthy

Closed Closed CB failure Alarm raised if thecondition persists forgreater than 5s

Open Open State unknown Alarm raised if thecondition persists forgreater than 5s

4.4 Circuit breaker controlThe relay includes the following options for control of a single circuit breaker:• Local tripping and closing, via the relay menu• Local tripping and closing, via relay opto-isolated inputs• Remote tripping and closing, using the relay communicationsIt is recommended that separate relay output contacts are allocated for remotecircuit breaker control and protection tripping. This enables the control outputs tobe selected via a local/remote selector switch as shown in Figure 18. Where thisfeature is not required the same output contact(s) can be used for both protectionand remote tripping.


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Figure 18: Remote control of circuit breaker

The following table is taken from the relay menu and shows the available settingsand commands associated with circuit breaker control. Depending on the relaymodel some of the cells may not be visible:

+ve

Trip0Close

LocalRemote

Trip Close

–ve

Protectiontrip

Remotecontroltrip

Remotecontrolclose


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Min Max

CB CONTROL

CB control by Disabled Disabled, Local, Remote, Local+Remote,Opto, Opto+Local, Opto+Remote,

Opto+Rem+Local

Close Pulse Time 0.5s 0.01s 10s 0.01s

Trip Pulse Time 0.5s 0.01s 5s 0.01s

Man Close Delay 10s 0.01s 600s 0.01s

Healthy Window 5s 0.01s 9999s 0.01s

C/S Window 5s 0.01s 9999s 0.01s

Lockout Reset No No, Yes

Reset Lockout By CB Close User Interface, CB Close

Man Close RstDly 5s 0.01s 600s 0.01s

CB Status Input None None, 52A, 52B, Both 52A and 52B

A manual trip will be permitted provided that the circuit breaker is initially closed.Likewise, a close command can only be issued if the CB is initially open.To confirm these states it will be necessary to use the breaker 52A and/or 52Bcontacts (the different selection options are given from the ‘CB Status Input’ cellabove). If no CB auxiliary contacts are available then this cell should be set toNone. Under these circumstances no CB control (manual or auto) will be possible.Once a CB Close command is initiated the output contact can be set to operatefollowing a user defined time delay (‘Man Close Delay’). This would givepersonnel time to move away from the circuit breaker following the closecommand. This time delay will apply to all manual CB Close commands.The length of the trip or close control pulse can be set via the ‘Trip Pulse Time’ and‘Close Pulse Time’ settings respectively. These should be set long enough to ensurethe breaker has completed its open or close cycle before the pulse has elapsed.Note that the manual close commands are found in the SYSTEMDATA column of the menu.If an attempt to close the breaker is being made, and a protection trip signal isgenerated, the protection trip command overrides the close command.Where the check synchronism function is set, this can be enabled to supervizemanual circuit breaker close commands. A circuit breaker close output will only beissued if the check synchronism criteria are satisfied. A user settable time delay isincluded (‘C/S Window’) for manual closure with check synchronising. If thechecksynch criteria are not satisfied in this time period following a close commandthe relay will lockout and alarm.


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In addition to a synchronism check before manual reclosure there is also a CBHealthy check if required. This facility accepts an input to one of the relays opto-isolators to indicate that the breaker is capable of closing (circuit breaker energyfor example). A user settable time delay is included "Healthy Window" for manualclosure with this check. If the CB does not indicate a healthy condition in this timeperiod following a close command then the relay will lockout and alarm.Where auto-reclose is used it may be desirable to block its operation whenperforming a manual close. In general, the majority of faults following a manualclosure will be permanent faults and it will be undesirable to auto-reclose.The "Man Close RstDly" timer setting is the time for which auto-reclose will bedisabled following a manual closure of the breaker.If the CB fails to respond to the control command (indicated by no change in thestate of CB Status inputs) a "CB Failed to Trip" or "CB Failed to Close" alarm willbe generated after the relevant trip or close pulses have expired. These alarms canbe viewed on the relay LCD display, remotely via the relay communications, or canbe assigned to operate output contacts for annunciation using the relaysprogrammable scheme logic (PSL).Note that the "Healthy Window" timer and "C/S Window" timer set under thismenu section are applicable to manual circuit breaker operations only. Thesesettings are duplicated in the Auto-reclose menu for Auto-reclose applications.The "Lockout Reset" and "Reset Lockout by" setting cells in the menu are applicableto CB Lockouts associated with manual circuit breaker closure, CB Conditionmonitoring (Number of circuit breaker operations, for example) and auto-recloselockouts.

4.5 Event & fault recordsThe relay records and time tags up to 250 events and stores them in non-volatile(battery backed up) memory. This enables the system operator to establish thesequence of events that occurred within the relay following a particular powersystem condition, switching sequence etc. When the available space is exhausted,the oldest event is automatically overwritten by the new one.The real time clock within the relay provides the time tag to each event, to aresolution of 1ms.The event records are available for viewing either via the frontplate LCD orremotely, via the communications ports.Local viewing on the LCD is achieved in the menu column entitled "VIEWRECORDS". This column allows viewing of event, fault and maintenance recordsand is shown the following table:-


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VIEW RECORDS

LCD Reference Description

Select Event Setting range from 0 to 249. This selects the requiredevent record from the possible 250 that may be stored.A value of 0 corresponds to the latest event and so on.

Time & Date Time & Date Stamp for the event given by the internalReal Time Clock

Event Text Up to 32 Character description of the Event refer tofollowing sections)

Event Value Up to 32 Bit Binary Flag or integer representative of theEvent (refer to following sections)

Select Fault Setting range from 0 to 4. This selects the required faultrecord from the possible 5 that may be stored. A valueof 0 corresponds to the latest fault and so on.

The following cells show all the fault flags, protectionstarts, protection trips, fault location, measurements etc.associated with the fault, i.e. the complete fault record.

Select Report Setting range from 0 to 4. This selects the requiredmaintenance report from the possible 5 that may bestored. A value of 0 corresponds to the latest report andso on.

Report Text Up to 32 Character description of the occurrence(refer to following sections)

Report Type These cells are numbers representative of theoccurrence. They form a specific error code whichshould be quoted in any related correspondence toReport Data

Reset Indication Either Yes or No. This serves to reset the trip LEDindications provided that the relevant protection elementhas reset.

For extraction from a remote source via communications, refer to Chapter 5, wherethe procedure is fully explained.Note that a full list of all the event types and the meaning of their values is given inAppendix A.

4.5.1 Types of event

An event may be a change of state of a control input or output relay, an alarmcondition, setting change etc. The following sections show the various items thatconstitute an event:-

4.5.1.1 Change of state of opto-isolated inputs.If one or more of the opto (logic) inputs has changed state since the last time thatthe protection algorithm ran, the new status is logged as an event. When this eventis selected to be viewed on the LCD, three applicable cells will become visible asshown below;


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Time & date of event

“LOGIC INPUTS”

“Event Value0101010101010101”

The Event Value is an 8 or 16 bit word showing the status of the opto inputs,where the least significant bit (extreme right) corresponds to opto input 1 etc.The same information is present if the event is extracted and viewed via PC.

4.5.1.2 Change of state of one or more output relay contacts.

If one or more of the output relay contacts has changed state since the last timethat the protection algorithm ran, then the new status is logged as an event.When this event is selected to be viewed on the LCD, three applicable cells willbecome visible as shown below;

Time & date of event

“OUTPUT CONTACTS”

“Event Value010101010101010101010”

The Event Value is a 7, 14 or 21 bit word showing the status of the output contacts,where the least significant bit (extreme right) corresponds to output contact 1 etc.The same information is present if the event is extracted and viewed via PC.

4.5.1.3 Relay alarm conditions.

Any alarm conditions generated by the relays will also be logged as individualevents. The following table shows examples of some of the alarm conditions andhow they appear in the event list:-

Alarm condition Resulting event

Event Text Event ValueBattery Fail Battery Fail ON/OFF Number from 0 to 31

Field Voltage Fail Field V Fail ON/OFF Number from 0 to 31

Setting Group viaOpto invalid Setting Grp Invalid ON/OFF Number from 0 to 31

Protection Disabled Prot’n Disabled ON/OFF Number from 0 to 31

Frequency out of range Freq out of Range ON/OFF Number from 0 to 31

VTS Alarm VT Fail Alarm ON/OFF Number from 0 to 31

CB Trip Fail Protection CB Fail ON/OFF Number from 0 to 31

The previous table shows the abbreviated description that is given to the variousalarm conditions and also a corresponding value between 0 and 31. This value isappended to each alarm event in a similar way as for the input and output eventspreviously described. It is used by the event extraction software, such as MiCOMS1, to identify the alarm and is therefore invisible if the event is viewed on theLCD. Either ON or OFF is shown after the description to signify whether theparticular condition has become operated or has reset.


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4.5.1.4 Protection element starts and trips

Any operation of protection elements, (either a start or a trip condition), will belogged as an event record, consisting of a text string indicating the operatedelement and an event value. Again, this value is intended for use by the eventextraction software, such as MiCOM S1, rather than for the user, and is thereforeinvisible when the event is viewed on the LCD.

4.5.1.5 General events

A number of events come under the heading of ‘General Events’ - an example isshown below:-

Nature of event Displayed text in event Displayed valuerecord

Level 1 password modified, PW1 edited UI, F or R 0either from user interface,front or rear port

A complete list of the ‘General Events’ is given in Appendix A.

4.5.1.6 Fault records.

Each time a fault record is generated, an event is also created. The event simplystates that a fault record was generated, with a corresponding time stamp.Note that viewing of the actual fault record is carried out in the "Select Fault’" cellfurther down the "VIEW RECORDS" column, which is selectable from up to 5records. These records consist of fault flags, fault location, fault measurements etc.Also note that the time stamp given in the fault record itself will be more accuratethan the corresponding stamp given in the event record as the event is loggedsome time after the actual fault record is generated.

4.5.1.7 Maintenance reports

Internal failures detected by the self monitoring circuitry, such as watchdog failure,field voltage failure etc. are logged into a maintenance report. The MaintenanceReport holds up to 5 such ‘events’ and is accessed from the "Select Report" cell atthe bottom of the "VIEW RECORDS" column.Each entry consists of a self explanatory text string and a ‘Type’ and ‘Data’ cell,which are explained in the menu extract at the beginning of this section and infurther detail in Appendix 1.Each time a Maintenance Report is generated, an event is also created. The eventsimply states that a report was generated, with a corresponding time stamp.

4.5.1.8 Setting changes

Changes to any setting within the relay are logged as an event. Two examples areshown in the following table:-

Type of setting change Displayed text in event Displayed valuerecord

Control/Support Setting C & S Changed 0

Group 1 Change Group 1 Changed 1


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Note: Control/Support settings are communications, measurement, CT/VT ratiosettings etc, which are not duplicated within the four setting groups.When any of these settings are changed, the event record is createdsimultaneously. However, changes to protection or disturbance recordersettings will only generate an event once the settings have been confirmedat the ‘setting trap’.

4.5.2 Resetting of event/fault records

If it is required to delete either the event, fault or maintenance reports, this may bedone from within the "RECORD CONTROL" column.

4.5.3 Viewing event records via MiCOM S1 support software

When the event records are extracted and viewed on a PC they look slightlydifferent than when viewed on the LCD. The following shows an example of howvarious events appear when displayed using MiCOM S1:-

- Monday 03 November 1998 15:32:49 GMT I>1 Start ON 2147483881

ALSTOM : MiCOM

Model Number: P141

Address: 001 Column: 00 Row: 23

Event Type: Protection operation

- Monday 03 November 1998 15:32:52 GMT Fault Recorded 0

ALSTOM : MiCOM

Model Number: P141


Event Type: Fault record

- Monday 03 November 1998 15:33:11 GMT Logic Inputs 00000000

ALSTOM : MiCOM

Model Number: P141


Event Type: Logic input changed state

- Monday 03 November 1998 15:34:54 GMT Output Contacts 0010000

ALSTOM : MiCOM

Model Number: P141


Event Type: Relay output changed state

As can be seen , the first line gives the description and time stamp for the event,whilst the additional information that is displayed below may be collapsed via the+/– symbol.For further information regarding events and their specific meaning, refer toAppendix A.

4.6 Disturbance recorderThe integral disturbance recorder has an area of memory specifically set aside forrecord storage. The number of records that may be stored is dependent upon theselected recording duration but the relays typically have the capability of storing aminimum of 20 records, each of 10.5 second duration. Disturbance records


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continue to be recorded until the available memory is exhausted, at which time theoldest record(s) are overwritten to make space for the newest one.The recorder stores actual samples which are taken at a rate of 12 samples percycle.Each disturbance record consists of eight analog data channels and thirty-twodigital data channels. Note that the relevant CT and VT ratios for the analogchannels are also extracted to enable scaling to primary quantities).The "DISTURBANCE RECORDER" menu column is shown in the following table:-


Min Max

DISTURB RECORDER

Duration 1.5s 0.1s 10.5s 0.01s

Trigger Position 33.3% 0 100% 0.1%

Trigger Mode Single Single or Extended

Analog Channel 1 VAN VAN, VBN, VCN, VCHECKSYNC,IA, IB, IC, IN, IN SEF

Analog Channel 2 VBN As above

Analog Channel 3 VCN As above

Analog Channel 4 VN As above

Analog Channel 5 IA As above

Analog Channel 6 IB As above

Analog Channel 7 IC As above

Analog Channel 8 IN SEF As above

Digital Inputs 1 to 32 Relays 1 to 7/14 Any of 7 or 14 O/P Contacts orand Any of 8 or 16 Opto Inputs or

Opto’s 1 to 8/16 Internal Digital Signals

Inputs 1 to 32 Trigger No Trigger No Trigger, Trigger L/H,except Dedicated Trigger H/LTrip Relay O/P’swhich are set to

Trigger L/H

Note:The available analog and digital signals will differ between relay types andmodels and so the individual courier database in Chapter 5 should be referred towhen determining default settings etc.


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The pre and post fault recording times are set by a combination of the "Duration"and "Trigger Position" cells. "Duration" sets the overall recording time and the"Trigger Position" sets the trigger point as a percentage of the duration.For example, the default settings show that the overall recording time is set to 1.5swith the trigger point being at 33.3% of this, giving 0.5s pre-fault and 1s post faultrecording times.If a further trigger occurs whilst a recording is taking place, the recorder willignore the trigger if the "Trigger Mode" has been set to "Single". However, if thishas been set to "Extended", the post trigger timer will be reset to zero, therebyextending the recording time.As can be seen from the menu, each of the analog channels is selectable from theavailable analog inputs to the relay. The digital channels may be mapped to anyof the opto isolated inputs or output contacts, in addition to a number of internalrelay digital signals, such as protection starts, LED’s etc. The complete list of thesesignals may be found by viewing the available settings in the relay menu or via asetting file in MiCOM S1. Any of the digital channels may be selected to triggerthe disturbance recorder on either a low to high or a high to low transition, via the"Input Trigger" cell. The default trigger settings are that any dedicated trip outputcontacts (e.g. relay 3) will trigger the recorder.It is not possible to view the disturbance records locally via the LCD; they must beextracted using suitable software such as MiCOM S1. This process is fullyexplained in Chapter 5.

4.7 MeasurementsThe relay produces a variety of both directly measured and calculated powersystem quantities. These measurement values are updated on a per second basisand are summarised below:

Phase Voltages and CurrentsPhase to Phase Voltage and CurrentsSequence Voltages and CurrentsPower and Energy QuantitiesRms. Voltages and CurrentsPeak, Fixed and Rolling Demand Values

4.7 1 Measured voltages and currents

The relay produces both phase to ground and phase to phase voltage and currentvalues. The are produced directly from the DFT (Discrete Fourier Transform) used bythe relay protection functions and present both magnitude and phase anglemeasurement.

4.7.2 Sequence voltages and currents

Sequence quantities are produced by the relay from the measured Fourier values;these are displayed as magnitude values.

4.7.3 Power and energy quantities

Using the measured voltages and currents the relay calculates the apparent, realand reactive power quantities. These are produced on a phase by phase basistogether with three-phase values based on the sum of the three individual phasevalues. The signing of the real and reactive power measurements can be controlledusing the measurement mode setting. The four options are defined in the tablebelow:


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Measurement Parameter Signingmode

0 (Default) Export Power +Import Power –Lagging VArs +Leading VArs –

1 Export Power –Import Power +Lagging VArs +Leading VArs –

2 Export Power +Import Power –Lagging VArs –Leading VArs +

3 Export Power –Import Power +Lagging VArs –Leading VArs +

Table 1: Measurement mode

In addition to the measured power quantities the relay calculates the power factoron a phase by phase basis in addition to a three-phase power factor.These power values are also used to increment the total real and reactive energymeasurements. Separate energy measurements are maintained for the totalexported and imported energy. The energy measurements are incremented up tomaximum values of 1000GWhr or 1000GVARhr at which point they will reset tozero, it is also possible to reset these values using the menu or remote interfacesusing the Reset Demand cell.

4.7.4 Rms. voltages and currents

Rms. Phase voltage and current values are calculated by the relay using the sum ofthe samples squared over a cycle of sampled data.

4.7.5 Demand values

The relay produces fixed, rolling and peak demand values, using the ResetDemand menu cell it is possible to reset these quantities via the User Interface orthe remote communications.

4.7.5.1 Fixed demand values

The fixed demand value is the average value of a quantity over the specifiedinterval; values are produced for each phase current and for three phase real andreactive power. The fixed demand values displayed by the relay are those for theprevious interval, the values are updated at the end of the fixed demand period.


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4.7.5.2 Rolling demand values

The rolling demand values are similar to the fixed demand values, the differencebeing that a sliding window is used. The rolling demand window consists of anumber of smaller sub-periods. The resolution of the sliding window is the sub-period length, with the displayed values being updated at the end of each of thesub-periods.

4.7.5.3 Peak demand values

Peak demand values are produced for each phase current and the real andreactive power quantities. These display the maximum value of the measuredquantity since the last reset of the demand values.

4.7.6 Settings

The following settings under the heading Measurement setup can be used toconfigure the relay measurement function.

Measurement setup Default value Options/LimitsDefault Display Description Description/Plant Reference/

Frequency/Access Level/3Ph + NCurrent/3Ph Voltage/Power/Dateand time

Local Values Primary Primary/SecondaryRemote Values Primary Primary/SecondaryMeasurement Ref VA VA/VB/VC/IA/IB/ICMeasurement Mode 0 0 to 3 Step 1Fix Dem Period 30 minutes 1 to 99 minutes step 1 minuteRoll Sub Period 30 minutes 1 to 99 minutes step 1 minuteNum Sub Periods 1 1 to 15 step 1

4.7.6.1 Default display

This setting can be used to select the default display from a range of options, notethat it is also possible to view the other default displays whilst at the default levelusing the ⇐ and ⇒ keys. However once the 15 minute timeout elapses thedefault display will revert to that selected by this setting.

4.7.6.2 Local values

This setting controls whether measured values via the front panel user interface andthe front Courier port are displayed as primary or secondary quantities.

4.7.6.3 Remote values

This setting controls whether measured values via the rear communication port aredisplayed as primary or secondary quantities.

4.7.6.4 Measurement ref

Using this setting the phase reference for all angular measurements by the relaycan be selected.

4.7.6.5 Measurement mode

This setting is used to control the signing of the real and reactive power quantities;the signing convention used is defined in Table 1 (Section 4.7.3)


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4.7.6.6 Fixed demand period

This setting defines the length of the fixed demand window.

4.7.6.7 Rolling sub-period and number of sub-periods

These two settings are used to set the length of the window used for the calculationof rolling demand quantities and the resolution of the slide for this window.

Section 5. CT/VT REQUIREMENTS

The CT requirements for P341 are as shown below.The current transformer requirements are based on a maximum prospective faultcurrent of 50 times the relay rated current (In) and the relay having aninstantaneous setting of 25 times rated current (In). The current transformerrequirements are designed to provide operation of all protection elements.Where the criteria for a specific application are in excess of those detailed above,or the actual lead resistance exceeds the limiting value quoted, the CT requirementsmay need to be increased according to the formulae in the following sections.

Nominal Nominal Accuracy Accuracy Limitingrating output class limited lead

factor resistance

1A 2.5VA 10P 20 1.3 ohms

5A 7.5VA 10P 20 0.11 ohms

Seperate requirements for Restricted Earth Fault are given in Section 5.6 and 5.7

5.1 Non-directional definite time/IDMT overcurrent & earth faultprotection

5.1.1 Time-delayed phase overcurrent elements

VK ≥ Icp/2 * (RCT + RL + Rrp)

5.1.2 Time-delayed earth fault overcurrent elements

VK ≥ Icn/2 * (RCT + 2RL + Rrp + Rrn)

5.2 Non-Directional instantaneous overcurrent & earth fault protection

5.2.1 CT requirements for instantaneous phase overcurrent elements

VK ≥ Isp/2 * (RCT + RL + Rrp)

5.2.2 CT requirements for instantaneous earth fault overcurrent elements

VK ≥ Isn/2 * (RCT + 2RL + Rrp + Rrn)

5.3 Directional definite time/IDMT overcurrent & earth faultprotection

5.3.1 Time-delayed phase overcurrent elements

VK ≥ Icp/2 * (RCT + RL + Rrp)

5.3.2 Time-delayed earth fault overcurrent elements



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5.4 Directional instantaneous overcurrent & earth fault protection

5.4.1 CT requirements for instantaneous phase overcurrent elements

VK ≥ Ifp/2 * (RCT + RL + Rrp)

5.4.2 CT requirements for instantaneous earth fault overcurrent elements

VK ≥ Ifn/2 * (RCT + 2RL + Rrp + Rrn)

5.5 Non-directional/directional definite time/IDMT sensitive earthfault (SEF) protection

5.5.1 Time delayed SEF protection


5.5.2 Non-directional SEF protection

VK ≥ Isn/2 * (RCT + 2RL + Rrp + Rrn)

5.5.3 Directional instantaneous SEF protection

VK ≥ Ifn/2 * (RCT + 2RL + Rrp + Rrn)

5.5.4 SEF protection - as fed from a core-balance CT

Core balance current transformers of metering class accuracy are required andshould have a limiting secondary voltage satisfying the formulae given below:Time delayed element:

VK ≥ Icn/2 * (RCT + 2RL + Rrp + Rrn)Instantaneous element:

VK ≥ Ifn/2 * (RCT + 2RL + Rrp + Rrn)Note that, in addition, it should be ensured that the phase error of the applied corebalance current transformer is less than 90 minutes at 10% of rated current andless than 150 minutes at 1% of rated current.Abbreviations used in the previous formulae are explained below:-where

VK = Required CT knee-point voltage (volts),Ifn = Maximum prospective secondary earth fault current (amps),Ifp = Maximum prospective secondary phase fault current (amps),Icn = Maximum prospective secondary earth fault current or 31 times

I> setting (whichever is lower) (amps),Icp = Maximum prospective secondary phase fault current or 31 times

I> setting (whichever is lower) (amps),Isn = Stage 2 & 3 Earth Fault setting (amps),Isp = Stage 2 and 3 setting (amps),RCT = Resistance of current transformer secondary winding (ohms)RL = Resistance of a single lead from relay to current transformer (ohms),Rrp = Impedance of relay phase current input at 30In (ohms),Rrn = Impedance of the relay neutral current input at 30In (ohms).


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5.6 High impedance restricted earth fault protectionThe High Impedance Restricted Earth Fault element shall maintain stability forthrough faults and operate in less than 40ms for internal faults provided thefollowing equations are met in determining CT requirements and the value of theassociated stabilising resistor:

Rs = [0.5 * (If) * (RCT + 2RL)] / IS1

VK ≥ 4 * Is * Rswhere

VK = Required CT knee-point voltage (volts),Rs = Value of Stabilising resistor (ohms),If = Maximum through fault current level (amps).VK = CT knee point voltage (volts),IS1 = Current setting of REF element (amps),RCT = Resistance of current transformer secondary winding (ohms)RL = Resistance of a single lead from relay to current transformer (ohms).



Chapter 3Relay Description


ContentsPage 1 of 1

1. RELAY SYSTEM OVERVIEW 12. HARDWARE MODULES 32.1 Processor board 32.2 Internal communication buses 32.3 Input module 42.3.1 Transformer board 42.3.2 Input board 42.4 Power supply module (including output relays) 62.4.1 Power supply board (including RS485 communication interface) 62.4.2 Output relay board 72.5 IRIG-B Board 72.6 Mechanical Layout 73. RELAY SOFTWARE 83.1 Real-time operating system 83.2 System services software 83.3 Platform software 83.3.1 Record logging 83.3.2 Settings database 103.3.3 Database interface 103.4 Protection & Control software 103.4.1 Overview – protection & control scheduling 103.4.2 Signal processing 103.4.3 Programmable scheme logic 113.4.4 Event, fault & maintenance recording 123.4.5 Disturbance recorder 124. SELF TESTING & DIAGNOSTICS 134.1 Start-up self-testing 134.1.1 System boot 134.1.2 Initialisation software 134.1.3 Platform software initialisation & monitoring 144.2 Continuous self-testing 14


Page 1 of 14

Section 1. RELAY SYSTEM OVERVIEW

The relay hardware is based on a modular design whereby the relay is made upof an assemblage of several modules which are drawn from a standard range.Some modules are essential while others are optional depending on the user’srequirements.The different modules that can be present in the relay are as follows:• Processor board which performs all calculations for the relay and controls the

operation of all other modules within the relay. The processor board alsocontains and controls the user interfaces (LCD, LEDs, keypad andcommunication interfaces).

• Input module which converts the information contained in the analogue anddigital input signals into a format suitable for processing by the processorboard. The standard input module consists of two boards: a transformer boardto provide electrical isolation and a main input board which provides analogueto digital conversion and digital inputs.

• Power supply module which provides a power supply to all of the other modulesin the relay, at three different voltage levels. The power supply board alsoprovides the RS485 electrical connection for the rear communication port.On a second board the power supply module contains the relays which providethe output contacts.

• IRIG-B board which can be used where an IRIG-B signal is available to providean accurate time reference for the relay. There is also an option on this board tospecify a fibre optic rear communication port, for use with IEC 60870communication only. This board is optional.

All modules are connected by a parallel data and address bus which allows theprocessor board to send and receive information to and from the other modules asrequired. There is also a separate serial data bus for conveying sample data fromthe input module to the processor. Figure 1 shows the modules of the relay and theflow of information between them.The software for the relay can be conceptually split into four elements: the real-timeoperating system, the system services software, the platform software and theprotection and control software. These four elements are not distinguishable to theuser, and are all processed by the same processor board. The distinction betweenthe four parts of the software is made purely for the purpose of explanation here:• The real-time operating system is used to provide a framework for the different

parts of the relay’s software to operate within. To this end the software is splitinto tasks. The real-time operating system is responsible for scheduling theprocessing of these tasks such that they are carried out in the time available andin the desired order of priority. The operating system is also responsible for theexchange of information between tasks, in the form of messages.

• The system services software provides the low-level control of the relayhardware. For example, the system services software controls the boot of therelay’s software from the non-volatile flash EPROM memory at power-on, andprovides driver software for the user interface via the LCD and keypad, and viathe serial communication ports. The system services software provides aninterface layer between the control of the relay’s hardware and the rest of therelay software.


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Figure 1:

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Page 3 of 14

• The platform software deals with the management of the relay settings, the userinterfaces and logging of event, alarm, fault and maintenance records.All of the relay settings are stored in a database within the relay which providesdirect compatibility with Courier communications. For all other interfaces (ie. thefront panel keypad and LCD interface, Modbus and IEC 60870-5-103) theplatform software converts the information from the database into the formatrequired. The platform software notifies the protection & control software of allsettings changes and logs data as specified by the protection & controlsoftware.

• The protection & control software performs the calculations for all of theprotection algorithms of the relay. This includes digital signal processing such asFourier filtering and ancillary tasks such as the disturbance recorder.The protection & control software interfaces with the platform software forsettings changes and logging of records, and with the system services softwarefor acquisition of sample data and access to output relays and digital opto-isolated inputs.

Section 2. HARDWARE MODULES

The relay is based on a modular hardware design where each module performs aseparate function within the relay’s operation. This section describes the functionaloperation of the various hardware modules.

2.1 Processor boardThe relay is based around a TMS320C32 floating point, 32-bit digital signalprocessor (DSP) operating at a clock frequency of 20MHz. This processor performsall of the calculations for the relay, including the protection functions, control of thedata communication and user interfaces including the operation of the LCD,keypad and LEDs.The processor board is located directly behind the relay’s front panel which allowsthe LCD and LEDs to be mounted on the processor board along with the front panelcommunication ports. These comprise the 9-pin D-connector for RS232 serialcommunications (eg. using MiCOM S1 and Courier communications) and the25-pin D-connector relay test port for parallel communication. All serialcommunication is handled using a two-channel 85C30 serial communicationscontroller (SCC).The memory provided on the main processor board is split into two categories,volatile and non-volatile: the volatile memory is fast access (zero wait state) SRAMwhich is used for the storage and execution of the processor software, and datastorage as required during the processor’s calculations. The non-volatile memory issub-divided into 3 groups: 2MB of flash memory for non-volatile storage ofsoftware code and text, 256kB of battery backed-up SRAM for the storage ofdisturbance, event and fault record data, and 32kB of E2PROM memory for thestorage of configuration data, including the present setting values.

2.2 Internal communication busesThe relay has two internal buses for the communication of data between differentmodules. The main bus is a parallel link which is part of a 64-way ribbon cable.The ribbon cable carries the data and address bus signals in addition to controlsignals and all power supply lines. Operation of the bus is driven by the mainprocessor board which operates as a master while all other modules within therelay are slaves.


Page 4 of 14

The second bus is a serial link which is used exclusively for communicating thedigital sample values from the input module to the main processor board. The DSPprocessor has a built-in serial port which is used to read the sample data from theserial bus. The serial bus is also carried on the 64-way ribbon cable.

2.3 Input moduleThe input module provides the interface between the relay processor board(s) andthe analogue and digital signals coming into the relay. The input module canconsist of either two or three PCBs; the two standard boards are the main inputboard and a transformer board. Depending on the relay model, more than fivecurrent inputs can be provided by supplementing these two boards with anauxiliary transformer board which can provide up to four further current inputs.

2.3.1 Transformer board

The standard transformer board holds up to four voltage transformers (VTs) and upto five current transformers (CTs). The auxiliary transformer board adds up to fourmore CTs. The current inputs will accept either 1A or 5A nominal current (menuand wiring options) and the voltage inputs can be specified for either 110V or440V nominal voltage (order option). The transformers are used both to step-downthe currents and voltages to levels appropriate to the relay’s electronic circuitry andto provide effective isolation between the relay and the power system.The connection arrangements of both the current and voltage transformersecondaries provide differential input signals to the main input board to reducenoise.

2.3.2 Input board

The main input board is shown as a block diagram in Figure 2. It provides thecircuitry for the digital input signals and the analogue-to-digital conversion for theanalogue signals. Hence it takes the differential analogue signals from the CTs andVTs on the transformer board(s), converts these to digital samples and transmits thesamples to the main processor board via the serial data bus. On the input boardthe analogue signals are passed through an anti-alias filter before beingmultiplexed into a single analogue-to-digital converter chip. The A – D converterprovides 16-bit resolution and a serial data stream output.The signal multiplexing arrangement provides for 16 analogue channels to besampled. This allows for up to 9 current inputs and 4 voltage inputs to beaccommodated. The 3 spare channels are used to sample 3 different referencevoltages for the purpose of continually checking the operation of the multiplexerand the accuracy of the A-D converter. The sample rate is maintained at 24samples per cycle of the power waveform by a logic control circuit which which isdriven by the frequency tracking function on the main processor board.The calibration E2PROM holds the calibration coefficients which are used by theprocessor board to correct for any amplitude or phase error introduced by thetransformers and analogue circuitry.The other function of the input board is to read the state of the signals present onthe digital inputs and present this to the parallel data bus for processing. The inputboard holds 8 optical isolators for the connection of up to eight digital inputsignals. The opto-isolators are used with the digital signals for the same reason asthe transformers with the analogue signals; to isolate the relay’s electronics fromthe power system environment. A 48V ‘field voltage’ supply is provided at theback of the relay for use in driving the digital opto-inputs.


Page 5 of 14

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Page 6 of 14

The input board provides some hardware filtering of the digital signals to removeunwanted noise before buffering the signals for reading on the parallel data bus.Depending on the relay model, more than 8 digital input signals can be acceptedby the relay. This is achieved by the use of an additional opto-board whichcontains the same provision for 8 isolated digital inputs as the main input board,but does not contain any of the circuits for analogue signals which are provided onthe main input board.

2.4 Power supply module (including output relays)The power supply module contains two PCBs, one for the power supply unit itselfand the other for the output relays. The power supply board also contains the inputand output hardware for the rear communication port which provides an RS485communication interface.

2.4.1 Power supply board (including RS485 communication interface)

One of three different configurations of the power supply board can be fitted to therelay. This will be specified at the time of order and depends on the nature of thesupply voltage that will be connected to the relay. The three options are shown intable 1 below.

Nominal dc range Nominal ac range24/54V dc only48/125V 30/100V rms110/250V 100/240V rms

Table 1: Power supply options

The output from all versions of the power supply module are used to provideisolated power supply rails to all of the other modules within the relay.Three voltage levels are used within the relay, 5.1V for all of the digital circuits,±16V for the analogue electronics, eg. on the input board, and 22V for driving theoutput relay coils. All power supply voltages including the 0V earth line aredistributed around the relay via the 64-way ribbon cable. One further voltage levelis provided by the power supply board which is the field voltage of 48V. This isbrought out to terminals on the back of the relay so that it can be used to drive theoptically isolated digital inputs.The two other functions provided by the power supply board are the RS485communications interface and the watchdog contacts for the relay. The RS485interface is used with the relay’s rear communication port to providecommunication using one of either Courier, Modbus or IEC 60870-5-103protocols. The RS485 hardware supports half-duplex communication and providesoptical isolation of the serial data being transmitted and received. All internalcommunication of data from the power supply board is conducted via the outputrelay board which is connected to the parallel bus.The watchdog facility provides two output relay contacts, one normally open andone normally closed which are driven by the main processor board. These areprovided to give an indication that the relay is in a healthy state.


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2.4.2 Output relay board

The output relay board holds seven relays, three with normally open contacts andfour with changeover contacts. The relays are driven from the 22V power supplyline. The relays’ state is written to or read from using the parallel data bus.Depending on the relay model, more than seven output contacts may be provided,through the use of up to three extra relay boards. Each additional relay boardprovides a further seven output relays.

2.5 IRIG-B BoardThe IRIG-B board is an order option which can be fitted to provide a timingreference for the relay. This can be used wherever an IRIG-B signal is available.The IRIG-B signal is connected to the board via a BNC connector on the back ofthe relay. The timing information is used to synchronise the relay’s internal real-timeclock and for various other processes, for example time-tagging of event, fault anddisturbance records. The IRIG-B board is used to provide a reading of the presenttime and date. The time reading is accurate to better than 1ms.The IRIG-B board can also be specified with a fibre optic transmitter/receiverwhich can be used for the rear communication port instead of the RS485 electricalconnection (IEC 60870 only).

2.6 Mechanical LayoutThe case materials of the relay are constructed from pre-finished steel which has aconductive covering of aluminium and zinc. This provides good earthing at alljoints giving a low impedance path to earth which is essential for performance inthe presence of external noise. The boards and modules use a multi-point earthingstrategy to improve the immunity to external noise and minimise the effect of circuitnoise. Ground planes are used on boards to reduce impedance paths and springclips are used to ground the module metalwork.Heavy duty terminal blocks are used at the rear of the relay for the current andvoltage signal connections. Medium duty terminal blocks are used for the digitallogic input signals, the output relay contacts, the power supply and the rearcommunication port. A BNC connector is used for the optional IRIG-B signal.9-pin and 25-pin female D-connectors are used at the front of the relay for datacommunication.Inside the relay the PCBs plug into the connector blocks at the rear, and can beremoved from the front of the relay only. The connector blocks to the relay’s CTinputs are provided with internal shorting links inside the relay which willautomatically short the current transformer circuits before they are broken when theboard is removed.The front panel consists of a membrane keypad with tactile dome keys, an LCDand 12 LEDs mounted on an aluminium backing plate.


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Section 3. RELAY SOFTWARE

The relay software was introduced in the overview of the relay at the start of thischapter. The software can be considered to be made up of four sections:• the real-time operating system• the system services software• the platform software• the protection & control softwareThis section describes in detail the latter two of these, the platform software and theprotection & control software, which between them control the functional behaviourof the relay. Figure 3 shows the structure of the relay software.

3.1 Real-time operating systemThe software is split into tasks; the real-time operating system is used to schedulethe processing of the tasks to ensure that they are processed in the time availableand in the desired order of priority. The operating system is also responsible inpart for controlling the communication between the software tasks through the useof operating system messages.

3.2 System services softwareAs shown in Figure 3, the system services software provides the interface betweenthe relay’s hardware and the higher-level functionality of the platform software andthe protection & control software. For example, the system services softwareprovides drivers for items such as the LCD display, the keypad and the remotecommunication ports, and controls the boot of the processor and downloading ofthe processor code into SRAM from non-volatile flash EPROM at power up.

3.3 Platform softwareThe platform software has three main functions:• to control the logging of all records that are generated by the protection

software, including alarms and event, fault, disturbance and maintenancerecords.

• to store and maintain a database of all of the relay’s settings in non-volatilememory.

• to provide the internal interface between the settings database and each of therelay’s user interfaces, i.e. the front panel interface and the front and rearcommunication ports, using whichever communication protocol has beenspecified (Courier, Modbus, IEC 60870-5-103).

3.3.1 Record logging

The logging function is provided to store all alarms, events, faults and maintenancerecords. The records for all of these incidents are logged in battery backed-upSRAM in order to provide a non-volatile log of what has happened. The relaymaintains four logs: one each for up to 32 alarms, 250 event records, 5 faultrecords and 5 maintenance records. The logs are maintained such that the oldestrecord is overwritten with the newest record. The logging function can be initiatedfrom the protection software or the platform software.


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Figure 3:

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3.3.2 Settings database

The settings database contains all of the settings and data for the relay, includingthe protection, disturbance recorder and control & support settings groups.The settings are maintained in non-volatile E2PROM memory. The platformsoftware’s management of the settings database includes the responsibility ofensuring that only one user interface modifies the settings of the database at anyone time. This feature is employed to avoid confusion between different parts of thesoftware during a setting change. For changes to protection settings anddisturbance recorder settings, the platform software operates a ‘scratchpad’ inSRAM memory. This allows a number of setting changes to be made in any orderbut applied to the protection elements, and saved in the database in E2PROM, atthe same time (see also chapter 1 on the user interface). If a setting change affectsthe protection & control task, the database advises it of the new values.

3.3.3 Database interface

The other function of the platform software is to implement the relay’s internalinterface between the database and each of the relay’s user interfaces.The database of settings and measurements must be accessible from all of therelay’s user interfaces to allow read and modify operations. The platform softwarepresents the data in the appropriate format for each user interface.

3.4 Protection & Control softwareThe protection and control software task is responsible for processing all of theprotection elements and measurement functions of the relay. To achieve this it hasto communicate with both the system services software and the platform softwareas well as organise its own operations. The protection software has the highestpriority of any of the software tasks in the relay in order to provide the fastestpossible protection response. The protection & control software has a supervisortask which controls the start-up of the task and deals with the exchange ofmessages between the task and the platform software.

3.4.1 Overview - protection & control scheduling

After initialisation at start-up, the protection & control task is suspended until thereare sufficient samples available for it to process. The acquisition of samples iscontrolled by a ‘sampling function’ which is called by the system services softwareand takes each set of new samples from the input module and stores them in a two-cycle buffer. The protection & control software resumes execution when the numberof unprocessed samples in the buffer reaches a certain number. For the P341generator loss of mains protection relay, the protection task is executed twice percycle, i.e. after every 12 samples for the sample rate of 24 samples per powercycle used by the relay. The protection and control software is suspended againwhen all of its processing on a set of samples is complete. This allows operationsby other software tasks to take place.

3.4.2 Signal processing

The sampling function provides filtering of the digital input signals from the opto-isolators and frequency tracking of the analogue signals. The digital inputs arechecked against their previous value over a period of half a cycle. Hence achange in the state of one of the inputs must be maintained over at least half acycle before it is registered with the protection & control software.The frequency tracking of the analogue input signals is achieved by a recursiveFourier algorithm which is applied to one of the input signals, and works bydetecting a change in the measured signal’s phase angle. The calculated value of


Page 11 of 14

the frequency is used to modify the sample rate being used by the input module soas to achieve a constant sample rate of 24 samples per cycle of the powerwaveform. The value of the frequency is also stored for use by the protection &control task.When the protection & control task is re-started by the sampling function, itcalculates the Fourier components for the analogue signals. The Fouriercomponents are calculated using a one-cycle, 24-sample Discrete FourierTransform (DFT). The DFT is always calculated using the last cycle of samples fromthe 2-cycle buffer, i.e. the most recent data is used. The DFT used in this wayextracts the power frequency fundamental component from the signal andproduces the magnitude and phase angle of the fundamental in rectangularcomponent format. The DFT provides an accurate measurement of the fundamentalfrequency component, and effective filtering of harmonic frequencies and noise.This performance is achieved in conjunction with the relay input module whichprovides hardware anti-alias filtering to attenuate frequencies above the halfsample rate, and frequency tracking to maintain a sample rate of 24 samples percycle. The Fourier components of the input current and voltage signals are stored inmemory so that they can be accessed by all of the protection elements’ algorithms.The samples from the input module are also used in an unprocessed form by thedisturbance recorder for waveform recording and to calculate true rms values ofcurrent, voltage and power for metering purposes.

3.4.3 Programmable scheme logic

The purpose of the programmable scheme logic (PSL) is to allow the relay user toconfigure an individual protection scheme to suit their own particular application.This is achieved through the use of programmable logic gates and delay timers.The input to the PSL is any combination of the status of the digital input signals fromthe opto-isolators on the input board, the outputs of the protection elements, eg.protection starts and trips, and the outputs of the fixed protection scheme logic.The fixed scheme logic provides the relay’s standard protection schemes. The PSLitself consists of software logic gates and timers. The logic gates can beprogrammed to perform a range of different logic functions and can accept anynumber of inputs. The timers are used either to create a programmable delay,and/or to condition the logic outputs, e.g. to create a pulse of fixed duration onthe output regardless of the length of the pulse on the input. The outputs of the PSLare the LEDs on the front panel of the relay and the output contacts at the rear.The execution of the PSL logic is event driven; the logic is processed whenever anyof its inputs change, for example as a result of a change in one of the digital inputsignals or a trip output from a protection element. Also, only the part of the PSLlogic that is affected by the particular input change that has occurred is processed.This reduces the amount of processing time that is used by the PSL. The protection& control software updates the logic delay timers and checks for a change in thePSL input signals every time it runs.This system provides flexibility for the user to create their own scheme logic design.However, it also means that the PSL can be configured into a very complex system,and because of this setting of the PSL is implemented through the PC supportpackage MiCOM S1.


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3.4.4 Event, fault & maintenance recording

A change in any digital input signal or protection element output signal is used toindicate that an event has taken place. When this happens, the protection &control task sends a message to the supervisor task to indicate that an event isavailable to be processed and writes the event data to a fast buffer in SRAM whichis controlled by the supervisor task. When the supervisor task receives either anevent or fault record message, it instructs the platform software to create theappropriate log in battery backed-up SRAM. The operation of the record loggingto battery backed-up SRAM is slower than the supervisor’s buffer. This means thatthe protection software is not delayed waiting for the records to be logged by theplatform software. However, in the rare case when a large number of records tobe logged are created in a short period of time, it is possible that some will be lostif the supervisor’s buffer is full before the platform software is able to create a newlog in battery backed-up SRAM. If this occurs then an event is logged to indicatethis loss of information.Maintenance records are created in a similar manner with the supervisor taskinstructing the platform software to log a record when it receives a maintenancerecord message. However, it is possible that a maintenance record may betriggered by a fatal error in the relay in which case it may not be possible tosuccessfully store a maintenance record, depending on the nature of the problem.See also the section on self supervision & diagnostics later in this chapter.

3.4.5 Disturbance recorder

The disturbance recorder operates as a separate task from the protection & controltask. It can record the waveforms for up to 8 analogue channels and the values ofup to 32 digital signals. The recording time is user selectable up to a maximum of10 seconds. The disturbance recorder is supplied with data by the protection &control task once per cycle. The disturbance recorder collates the data that itreceives into the required length disturbance record. It attempts to limit thedemands it places on memory space by saving the analogue data in compressedformat whenever possible. This is done by detecting changes in the analogue inputsignals and compressing the recording of the waveform when it is in a steady-statecondition. The compressed disturbance records can be decompressed by MiCOMS1 which can also store the data in COMTRADE format, thus allowing the use ofother packages to view the recorded data.


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Section 4. SELF TESTING & DIAGNOSTICS

The relay includes a number of self-monitoring functions to check the operation ofits hardware and software when it is in service. These are included so that if anerror or fault occurs within the relay’s hardware or software, the relay is able todetect and report the problem and attempt to resolve it by performing a re-boot.This involves the relay being out of service for a short period of time which isindicated by the ‘Healthy’ LED on the front of the relay being extinguished and thewatchdog contact at the rear operating. If the restart fails to resolve the problem,then the relay will take itself permanently out of service. Again this will beindicated by the LED and watchdog contact.If a problem is detected by the self-monitoring functions, the relay attempts to storea maintenance record in battery backed-up SRAM to allow the nature of theproblem to be notified to the user.The self-monitoring is implemented in two stages: firstly a thorough diagnosticcheck which is performed when the relay is booted-up, eg. at power-on, andsecondly a continuous self-checking operation which checks the operation of therelay’s critical functions whilst it is in service.

4.1 Start-up self-testingThe self-testing which is carried out when the relay is started takes a few seconds tocomplete, during which time the relay’s protection is unavailable. This is signalledby the ‘Healthy’ LED on the front of the relay which will illuminate when the relayhas passed all of the tests and entered operation. If the testing detects a problem,the relay will remain out of service until it is manually restored to working order.The operations that are performed at start-up are as follows:

4.1.1 System boot

The integrity of the flash EPROM memory is verified using a checksum before theprogram code and data stored in it is copied into SRAM to be used for executionby the processor. When this has been completed the data then held in SRAM iscompared to that in the flash EPROM to ensure that the two are the same and thatno errors have occurred in the transfer of data from flash EPROM to SRAM.The entry point of the software code in SRAM is then called which is the relayinitialisation code.

4.1.2 Initialisation software

The initialisation process includes the operations of initialising the processorregisters and interrupts, starting the watchdog timers (used by the hardware todetermine whether the software is still running), starting the real-time operatingsystem and creating and starting the supervisor task. In the course of theinitialisation process the relay checks:• the status of the battery.• the integrity of the battery backed-up SRAM that is used to store event, fault and

disturbance records.• the voltage level of the field voltage supply which is used to drive the opto-

isolated inputs.• the operation of the LCD controller.• the watchdog operation.


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At the conclusion of the initialisation software the supervisor task begins theprocess of starting the platform software.

4.1.3 Platform software initialisation & monitoring

In starting the platform software, the relay checks the integrity of the data held inE2PROM with a checksum, the operation of the real-time clock, and the IRIG-Bboard if fitted. The final test that is made concerns the input and output of data; thepresence and healthy condition of the input board is checked and the analoguedata acquisition system is checked through sampling the reference voltage.At the successful conclusion of all of these tests the relay is entered into service andthe protection started-up.

4.2 Continuous self-testingWhen the relay is in service, it continually checks the operation of the critical partsof its hardware and software. The checking is carried out by the system servicessoftware (see section on relay software earlier in this chapter) and the resultsreported to the platform software. The functions that are checked are as follows:• the flash EPROM containing all program code and language text is verified by

a checksum.• the code and constant data held in SRAM is checked against the corresponding

data in flash EPROM to check for data corruption.• the SRAM containing all data other than the code and constant data is verified

with a checksum.• the E2PROM containing setting values is verified by a checksum.• the battery status.• the level of the field voltage.• the integrity of the digital signal I/O data from the opto-isolated inputs and the

relay contacts, is checked by the data acquisition function every time it isexecuted. The operation of the analogue data acquisition system is continuouslychecked by the acquisition function every time it is executed, by means ofsampling the reference voltage on a spare multiplexed channel.

• the operation of the IRIG-B board is checked, where it is fitted, by the softwarethat reads the time and date from the board.

If any of the checks detects an error within the relay’s subsystems, the platformsoftware is notified and it will attempt to log a maintenance record in batterybacked-up SRAM. If the problem is with the battery status or the IRIG-B board, therelay will continue in operation. However, for problems detected in any other areathe relay will initiate a shutdown and re-boot. This will result in a period of up to 5seconds when the protection is unavailable, but the complete restart of the relayincluding all initialisations should clear most problems that could occur.As described above, an integral part of the start-up procedure is a thoroughdiagnostic self-check. If this detects the same problem that caused the relay torestart, ie. the restart has not cleared the problem, then the relay will take itselfpermanently out of service. This is indicated by the ‘Healthy’ LED on the front of therelay, which will extinguish, and the watchdog contact which will operate.



Chapter 4Technical Data


ContentsPage 1 of 2

1. RATINGS 11.1 Currents 11.2 Voltages 11.3 Auxiliary voltage 11.4 Frequency 11.5 Logic inputs 21.6 Output relay contacts 21.7 Field voltage 21.8 Loop through connections 21.9 Wiring requirements 22. BURDENS 32.1 Current circuit 32.2 Voltage circuit 32.3 Auxiliary supply 32.4 Optically-isolated inputs 33. ACCURACY 43.1 Reference conditions 43.2 Measurement accuracy 43.3 Protection accuracy 53.4 Influencing quantities 73.5 High voltage withstand IEC 60255-5:1977 73.5.1 Dielectric withstand IEC 60255-5:1997 rear terminals only 73.5.2 Impulse 73.5.3 Insulation resistance 84. ENVIRONMENTAL COMPLIANCE 84.1 Electrical environment 84.1.1 DC supply interruptions IEC 60255-11:1979 84.1.2 AC ripple on dc supply IEC 60255-11:1979 84.1.3 Disturbances on ac supply EN61000-4-11: 1994 84.1.4 High frequency disturbance IEC 60255-22-1:1988 84.1.5 Fast transient IEC 60255-22-4:1992 & IEC 60801-4:1988 84.1.6 Electrostatic discharge IEC 60255-22-2:1996 84.1.7 Conducted emissions EN 55011:1991 94.1.8 Radiated emissions EN 55011:1991 94.1.9 Radiated immunity C37.90.2:1995 94.1.10 Conducted immunity EN50141:1993 94.1.11 Surge immunity IEC 61000-4-5:1995 94.1.12 EMC compliance 94.1.13 Power frequency interference – Electricity Association (UK) 94.2 Atmospheric environment 104.2.1 Temperature IEC 60255-6:1988 104.2.2 Humidity IEC 60068-2-3:1969 104.2.3 Enclosure protection IEC 60529:1989 104.2.4 Pollution degree IEC 61010-1 1990 104.3 Mechanical environment 104.3.1 Vibration IEC 60255-21-1:1988 104.3.2 Shock and bump IEC 60255-21-2:1988 104.3.3 Seismic IEC 60255-21-3:1993 10


ContentsPage 2 of 2

5. ANSI TEST REQUIREMENTS 105.1 ANSI/IEEE C37.90 : 1989 105.2 ANSI/IEEE C37.90.1 : 1989 105.3 ANSI/IEEE C37.90.2 : 1995 106. SAFETY 116.1 Low voltage (safety and insulation) directive 117. PROTECTION SETTING RANGES 117.1 Four stage non-directional/directional overcurrent (50/51) 117.1.1 Threshold settings 117.1.2 Time delay settings 117.1.3 Inverse time (IDMT) characteristic 117.1.4 Definite time characteristic 127.1.5 Reset characteristics 137.2 Four stage directional earth fault (50N/51N) 147.2.1 Threshold settings 147.2.2 Restricted earth fault (low impedance) 147.2.3 SBEF and SEF time delay characteristics 147.3 Neutral displacement/residual overvoltage (59N) 147.3.1 Setting ranges 147.3.2 Time delay settings 157.4 Earth fault protection of Petersen Coil earthed systems 157.5 Under voltage (27) 157.5.1 Level settings 157.5.2 Under voltage protection time delay characteristics 167.6 Over voltage (59) 167.6.1 Level settings 167.6.2 Over voltage protection time delay characteristics 177.7 Under frequency (81U) 177.8 Over frequency (81O) 177.9 Reverse power/low forward power/over power (32R /32L /32O) 187.10 Voltage transformer supervision 197.11 Nominal frequency 197.12 Breaker fail timers (tBF1 and tBF2) 198. CONTROL FUNCTION SETTINGS 208.1 Circuit breaker state monitoring 208.2 Circuit breaker control 208.3 Circuit breaker condition monitoring 208.3.1 Maintenance alarm settings 208.3.2 Lock-out alarm settings 208.4 Reconnection time delay 209. INPUT AND OUTPUT SETTING RANGES 219.1 CT and VT ratio settings 21


Page 1 of 21

Section 1. RATINGS

1.1 Currents

In = 1A or 5A ac rms (dual rated).

Separate terminals are provided for the 1A and 5A windings, with the neutralinput of each winding sharing one terminal.

CT type Operating range

Standard 0 to 64In

Sensitive 0 to 2In

Duration Withstand

Continuous rating 4In

10 seconds 30In

1 second 100In

1.2 Voltages

Maximum rated voltage relate to earth 300V dc or 300V rms.

Nominal voltage Short term above Vn

100 – 120Vph - ph rms 0 to 200Vph - ph rms

380 – 480Vph - ph rms 0 to 800Vph - ph rms

Duration Withstand Withstand(Vn = 100/120V) (Vn = 380/480V)

Continuous (2Vn) 240Vph - ph rms 880Vph - ph rms

10 seconds (2.6Vn) 312Vph - ph rms 1144Vph - ph rms

1.3 Auxiliary voltage

The relay is available in three auxiliary voltage versions, these are specified in thetable below:

Nominal ranges Operative dc Operative acrange range

24 – 48V dc 19 to 65V –48 – 110V dc (30 – 100V ac rms) ** 37 to 150V 24 to 110V110 – 250V dc 87 to 300V 80 to 265V(100 – 240V ac rms)**

** rated for ac or dc operation.

1.4 Frequency

The nominal frequency (Fn) is dual rated at 50 – 60Hz, the operate range is40Hz – 70Hz.


Page 2 of 21

1.5 Logic inputs

All the logic inputs are independent and isolated, relay type P341 provides 8inputs.

Rating Range

Logical “off” 0V dc 0 to 12V dc

Logical “on” 50V dc 30 to 60V dc

Higher voltages can be used in conjunction with an external resistor, value of theresistor is determined by the following equation:

Resistor = (Required input level – 50) x 200Ω.

1.6 Output relay contacts

Make & carry 30A for 3s

Carry 250A for 30ms5A continuous

Break dc: 50W resistivedc: 25W inductive (L/R = 40ms)ac: 1250VA resistiveac: 1250VA inductive (P.F. = 0.5)

Maxima: 5A and 300V

Loaded contact: 10,000 operation minimum

Unloaded contact: 100,000 operations minimum

Watchdog contact

Break dc: 30W resistivedc: 15W inductive (L/R = 40ms)ac: 375W indictive (P.F. = 0.7)

The maximum number of output relays that should be configured to be permanentlyenergized is 50% of those available (minimum 4)

1.7 Field voltage

The field voltage provided by the relay is nominally 48V dc with a current limit of112mA. The operating range shall be 40V to 60V with an alarm raised at <35V.

1.8 Loop through connections

Terminals D17 – D18 and F17 – F18 are internally connected together forconvenience when wiring, maxima 5A and 300V

1.9 Wiring requirements

The requirements for the wiring of the relay and cable specifications are detailed inthe installation section of the Operation Guide (Volume 2, Chapter 2)


Page 3 of 21

Section 2. BURDENS

2.1 Current circuit

CT burden (at nominal current)

1A <0.1Ω

5A <0.02Ω

2.2 Voltage circuit

Reference voltage (Vn)

Vn = 100 – 120V <0.02VA rms at 110V

Vn = 380 – 480V <0.1VA rms at 440V

2.3 Auxiliary supply

Case size Nominal* Maximum**

Size 8 15W 20W

* Nominal is with 50% of the optos energised and one relay per cardenergised

** Maximum is with all optos and all relays energised

2.4 Optically-isolated inputs

DC supply 5mA burden per input. (Current drawn at mimimum voltage)

2.5mA at minimum voltage (30V)


Page 4 of 21

Section 3. ACCURACY

For all accuracies specified, the repeatability is ±2.5% unless otherwise specified.

If no range is specified for the validity of the accuracy, then the specified accuracyshall be valid over the full setting range.

3.1 Reference conditions

Quantity Reference conditions Test toleranceGeneralAmbient temperature 20°C ±2°CAtmospheric pressure 86kPa to 106kPa –Relative humidity 45 to 75% –Input energising quantityCurrent In ±5%Voltage Vn ±5%Frequency 50 or 60Hz ±0.5%Auxiliary supply dc 48V or 110V ±5%

ac 63.5V or 110V

Settings Reference valueTime multiplier setting 1.0Time dial 10Phase angle 0º

3.2 Measurement accuracy

Quantity Range AccuracyCurrent 1.0In ±1%Voltage 1.0 Vn ±1%Frequency 40 to 70Hz ±0.025HzPhase 0 to 360° ±2°


Page 5 of 213

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Page 7 of 21

3.4 Influencing quantities

No additional errors will be incurred for any of the following influencing quantities:

Quantity Operative range (typical only)EnvironmentalTemperature –25°C to +55°CMechanical (Vibration, Shock, According toBump, Seismic) IEC 60255-21-1:1988

IEC 60255-21-2:1988IEC 60255-21-3:1995

Quantity Operative rangeElectricalFrequency 45 Hz to 65 HzHarmonics (single) 5% over the range 2nd to 17thAuxiliary voltage range 0.8 LV to 1.2 HV (dc) 0.8 LV to 1.1 HV (ac)Aux. supply ripple 12% Vn with a frequency of 2.fnPoint on wave of fault waveform 0 to 360°DC offset of fault waveform No offset to fully offsetPhase angle –90° to + 90°Magnetising inrush No operation with OC elements set to 35%

of peak anticipated inrush level.

3.5 High voltage withstand IEC 60255-5:1977

3.5.1 Dielectric withstand IEC 60255-5:1997 rear terminals only

2.0kV rms for one minute between all terminals and case earth.

2.0kV rms for one minute between all terminals of each independent circuitgrouped together, and all other terminals. This includes the output contacts andloop through connections D17/D18 and F17/F18.

1.5kV rms for one minute across dedicated normally open contacts of outputrelays.

1.0kV rms for 1 minute across normally open contacts of changeover andwatchdog output relays.

3.5.2 Impulse

The product will withstand without damage impulses of 5kV peak, 1.2/50µs,0.5J across:

Each independent circuit and the case with the terminals of each independentcircuit connected together.

Independent circuits with the terminals of each independent circuit connectedtogether.

Terminals of the same circuit except normally open metallic contacts.


Page 8 of 21

3.5.3 Insulation resistance

The insulation resistance is greater than 100MΩ at 500V dc.

Section 4. ENVIRONMENTAL COMPLIANCE

The product complies with the following specifications :

4.1 Electrical environment

4.1.1 DC supply interruptions IEC 60255-11:1979

The product will withstand a 20ms interruption in the auxiliary voltage in itsquiescent condition without de-energization.

4.1.2 AC ripple on dc supply IEC 60255-11:1979

The product will operate with 12% ac ripple on the dc auxiliary supply without anyadditional measurement errors.

4.1.3 Disturbances on ac supply EN61000-4-11: 1994

The products satisfies the requirements of EN61000-4-11 for voltage dips andshort interruptions of 20ms.

4.1.4 High frequency disturbance IEC 60255-22-1:1988

The product complies with Class III 2.5kV common mode and 1kV differentialmode for 2 seconds at 1MHz with 200Ω source impedance, without any mal-operations or additional measurement errors.

4.1.5 Fast transient IEC 60255-22-4:1992 & IEC 60801-4:1988

The product complies with all classes up to and including class IV/4kV without anymal-operations or additional measurement errors.

Fast transient disturbances on power 4kV, 5ns rise time, 50ns decay time,supply (common mode only) 5kHz repetition time, 15ms burst,

repeated every 300ms for 1min ineach polarity, with a 50Ω sourceimpedance.

Fast transient disturbances on I/O 2kV, 5ns rise time, 50ns decay time,signal, data and control lines 5kHz repetition time, 15ms burst,(common mode only) repeated every 300ms for 1min in

each polarity, with a 50Ω sourceimpedance.

4.1.6 Electrostatic discharge IEC 60255-22-2:1996

The product will withstand application of all discharge levels up to the followingwithout mal-operation:

• Class IV – 15kV discharge in air to the user interface, display and exposedmetal work.

• Class III – 8kV discharge in air to all communication ports.

• Level 3 – 6kV point contact discharge to any part of the front of theproduct without any mal-operations.


Page 9 of 21

4.1.7 Conducted emissions EN 55011:1991

Group 1 Class A limits.

0.15 – 0.5MHz, 79dBµV (quasi peak) 66dBµV (average).

0.5 – 30MHz, 73dBµV (quasi peak) 60dBµV (average).

4.1.8 Radiated emissions EN 55011:1991

Group 1 Class A limits.

30 – 230MHz, 40dBµV/m at 10m measurement distance.

230 – 1000MHz, 47dBµV/m at 10m measurement distance.

4.1.9 Radiated immunity C37.90.2:1995

25MHz to 1000MHz, zero and 100% square wave modulated. Field strength of35V/m.

4.1.10 Conducted immunity EN50141:1993

Class III – 10Vrms @ 1kHz 80% am. – 0.15 to 80MHz.

4.1.11 Surge immunity IEC 61000-4-5:1995

Class IV – 4kV peak, 1.2/50µs between all groups and case earth

– 2kV peak, 1.2/5.0µs between terminals of each group

4.1.12 EMC compliance

Compliance to the European Community Directive 89/336/EEC on EMC isclaimed via the Technical Construction File route.

Generic Standards EN 50081-2 :1994 and EN 50082-2 :1995 are used toestablish conformity.

4.1.13 Power frequency interference - Electricity Association (UK)

EA PAP Document, Environmental Test Requirements for Protection Relays andSystems Issue I, Draft 4.2.1 1995.

Class Length of comms Unbalanced Balanced Balancedcircuit comms comms comms

V rms (Unbalance (Unbalance1%) V rms 0.1%) V rms

1 1 to 10 metres 0.5 0.005 0.00052 10 to 100 metres 5 0.05 0.0053 100 to 1000 metres 50 0.5 0.054 1000 to 10,000m or > 500 5 0.5


Page 10 of 21

4.2 Atmospheric environment

4.2.1 Temperature IEC 60255-6:1988

Storage and transit –25°C to +70°C.

Operating –25°C to +55°C.

IEC 60068-2-1:1990 Cold

IEC 60068-2-2:1974 Dry heat

4.2.2 Humidity IEC 60068-2-3:1969

56 days at 93% relative humidity and 40°C.

4.2.3 Enclosure protection IEC 60529:1989

IP52 – Protected against dust and dripping water at 15° to the vertical.

4.2.4 Pollution degree IEC 61010-1 1990

Normally only non-conductive pollution occurs. Occasionally, a temporyconductivity caused by condensation must be expected.

4.3 Mechanical environment

4.3.1 Vibration IEC 60255-21-1:1988

Vibration Response Class 2 – 1g

Vibration Endurance Class 2 – 2g.

4.3.2 Shock and bump IEC 60255-21-2:1988

Shock response Class 2 – 10g

Shock withstand Class 1 – 15g

Bump Class 1 – 10g

4.3.3 Seismic IEC 60255-21-3:1993

Class 2.

Section 5. ANSI TEST REQUIREMENTS

The products shall meet the ANSI/IEEE requirements as follows :-

5.1 ANSI/IEEE C37.90 : 1989

Standards for relays and relay systems associated with electric power apparatus.

5.2 ANSI/IEEE C37.90.1 : 1989

Surge withstand capability (SWC) tests for protective relays and relay systems:-

Oscillatory test – 1MHz to 1.5MHz, 2.5kV to 3.0kV,

Fast transient test 4kV to 5kV

5.3 ANSI/IEEE C37.90.2 : 1995

Standard for withstand capability of relay systems to radiated electromagneticinterference from transceivers. 35V/m, 25 to 1000Mhz.


Page 11 of 21

Section 6. SAFETY

6.1 Low voltage (safety and insulation) directive

The product shall be compliant with the low voltage (safety/insulation) directiveEN61010-1:1993.

Products are reviewed for compliance to the LV Directive.

Section 7. PROTECTION SETTING RANGES

7.1 Four stage non-directional/directional overcurrent (50/51)

7.1.1 Threshold settings

Setting Stage Range Step sizeI>1 current set 1st stage 0.08 to 4.0In 0.01InI>2 current set 2nd stage 0.08 to 4.0In 0.01InI>3 current set 3rd stage 0.08 to 32In 0.01InI>4 current set 4th stage 0.08 to 32In 0.01In

Directional settings:

Setting Range Step sizeI> Char angle –95° to +95° 1

7.1.2 Time delay settings

Each overcurrent element has an independent time setting and each time delay canbe blocked by an optically isolated input:

Element Time delay type1st stage Definite Time (DT) or IDMT2nd stage DT or IDMT3rd stage DT4th stage DT

7.1.3 Inverse time (IDMT) characteristic

IDMT characteristics are selectable from a choice of four IEC/UK and five IEEE/UScurves as shown in the table below.

The IEC/UK IDMT curves conform to the following formula:

t = T xK

(I/Is ) α – 1+L

The IEEE/US IDMT curves conform to the following formula:

xK

(I/Is) α – 1+Lt = TD

7


Page 12 of 21

where t = operation timeK = constantI = measured currentIS = current threshold settingα = constantL = ANSI/IEEE constant (zero for IEC/UK curves)T = Time multiplier setting for IEC/UK curvesTD = Time dial setting for IEEE/US curves

IDMT characteristics

IDMT curve Standard K α Ldescription constant constant constant

Standard inverse IEC 0.14 0.02 0

Very inverse IEC 13.5 1 0

Extremely inverse IEC 80 2 0

Long time inverse UK 120 1 0

Moderately inverse IEEE 0.0515 0.02 0.114

Very inverse IEEE 19.61 2 0.491

Extremely inverse IEEE 28.2 2 0.1217

Inverse US-C08 5.95 2 0.18

Short time inverse US-C02 0.02394 0.02 0.01694

Time multiplier settings for IEC/UK curves

Setting Range Step sizeTMS 0.025 to 1.2 0.025

Time dial settings for IEC/US curves

Name Range Step sizeTD 0.5 to 15 0.1

7.1.4 Definite time characteristic

Element Range Step sizeAll stages 0 to 100s 10ms


Page 13 of 21

7.1.5 Reset characteristics

Reset options for IDMT stages:

Curve type Reset time delayIEC – UK curves DT onlyAll other IDMT or DT

The inverse reset characteristics are dependent upon the selected IEEE/US IDMTcurve as shown in the table below. Thus if IDMT reset is selected the curve selectionand time dial setting will apply to both operate and reset.

All inverse reset curves conform to the following formula:

xtr

1 – (I/Is) αt Reset =

TD7

where tReset = reset timetr = constantI = measured currentIS = current threshold settingα = constantTD = Time Dial setting (Same setting as that employed by IDMT curve)

Inverse reset characteristics

IEEE/US IDMT Standard tr αcurve description constant constant

Moderately inverse IEEE 4.85 2

Very inverse IEEE 21.6 2

Extremely inverse IEEE 29.1 2

Inverse US-C08 5.95 2

Short time inverse US-C02 2.261 2


Page 14 of 21

7.2 Four stage directional earth fault (50N/51N)

7.2.1 Threshold settings

Type Stage Range Step sze

Stand by earth fault 1st Stage 0.08 – 4.0 In 0.01 In2nd Stage 0.08 – 4.0 In 0.01 In3rd Stage 0.08 – 10 In 0.01 In

(0.01In to In)0.1 In(In to 10 In)

4th Stage 0.08 – 10 In 0.01 In(0.01In to In)0.1 In(In to 10 In)

Sensitive earth fault 1st Stage 0.005 – 0.1 In 0.00025 In2nd Stage 0.005 – 0.1 In 0.00025 In3rd Stage 0.005 – 0.8 In 0.00025 In4th Stage 0.005 – 0.8 In 0.00025 In

7.2.2 Restricted earth fault (low impedance)

Setting Range Step size

K1 0% to 20% 1 % (minimum)K2 0% to 150% 1 % (minimum)Is1 0.05In to In 0.01InIs2 0.1In to 1.5In 0.1In

7.2.3 SBEF and SEF time delay characteristics

The earth-fault measuring elements for SBEF and SEF shall be followed by anindependently selectable time delay. These time delays have an extended range of0 to 200s, but are otherwise identical to those of the phase overcurrent definitetime delay. The reset time delay is the same as the phase overcurrent reset time.

7.3 Neutral displacement/residual overvoltage (59N)

7.3.1 Setting ranges

Name Range Step sizeVN> (Vn 100/120V) 1 – 50V 1VVN>> (Vn 100/120V) 1 – 50V 1VVN> (Vn 380/440V) 4 – 200V 4VVN>> (Vn 380/440V) 4 – 200V 4V


Page 15 of 21

7.3.2 Time delay settings

The inverse characteristic shall be given by the following formula :

where, K = Time multiplier setting

t = operating time in seconds

M = Applied input voltage/relay setting voltage (Vs)

Definite time and TMS setting ranges.

Range Step sizeTMS setting (K) 0.5 – 100s 0.5DT reset setting 0 – 100s 0.01s

7.4 Earth fault protection of Petersen Coil earthed systems

Name Range Step sizePN> 0 – 20W (Rating = 1A, 100/120V) 0.05W

0 – 100W (Rating = 5A, 100/120V) 0.25W0 – 80W (Rating = 1A, 380/440V) 0.20W

7.5 Under voltage (27)

7.5.1 Level settings

Name Range Step sizeVph – N<1 & Vph - ph<1

(Vn = 100/120V) 10 – 120V 1V

Vph – N<1 & Vph - ph<1

(Vn = 380/440V) 40 – 480V 4V


(Vn = 100/120V) 10 – 120V 1V


(Vn = 380/440V) 40 – 480V 4V

t = KM –1


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7.5.2 Under voltage protection time delay characteristics

Under voltage measuring elements are followed by an independently selectabletime delay.

The first element have time delay characteristics selectable as either Inverse Time orDefinite Time. The remaining element shall have an associated Definite Time delaysetting.

Each measuring element time delay is capable of being blocked by the operationof a user defined logic (optical isolated) input.

The inverse characteristic shall be given by the following formula :


t = Operating time in seconds


Definite time and TMS setting ranges.

Range Step sizeDT setting 0 – 100s 0.1sTMS setting (K) 0.5 – 100 0.5

Timer accuracy should be <2% (or 50ms whichever is greater).

7.6 Over voltage (59)

7.6.1 Level settings

Name Range Step sizeVph – N>1 & Vph - ph>1

(Vn = 100/120V) 60 – 185V 1VVph – N>1 & Vph - ph>1

(Vn = 380/440V) 240 –740V 4VVph – N>2 & Vph - ph>2

(Vn = 100/120V) 60 – 185V 1VVph – N>2 & Vph - ph>2

(Vn = 380/440V) 240 – 740V 4V

t = K1 –M


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7.6.2 Over voltage protection time delay characteristics

Over voltage measuring elements are followed by an independently selectabletime delay.

The first elements have time delay characteristics selectable as either Inverse Timeor Definite Time. The remaining element shall have an associated Definite Timedelay setting.

Each measuring element time delay is capable of being blocked by the operationof a user defined logic (optical isolated) input.

The inverse characteristics are given by the following formula :


t = Operating time in seconds


Definite time and TMS setting ranges

Range Step sizeDT setting 0 – 100s 0.1sTMS setting (K) 0.5 – 100 0.5

7.7 Under frequency (81U)

Range Step sizef (for all stages) 45 – 65 Hz 0.01 Hzt (for all stages) 0 – 100s 0.01s

7.8 Over frequency (81O)

Range Step sizef (for all stages) 45 – 65 Hz 0.01 Hzt (for all stages) 0 – 100s 0.01s

t = KM –1


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7.9 Reverse power/low forward power/over power (32R /32L /32O)

Settings Range Step size

Stage 1 Enable/disable

Mode Reverse/low forward/over

-P> (reverse power) 14W – 40W (In=1A, Vn=100/120V) 2W

56W – 160W (In=1A, Vn=400/440V) 8W

70W – 200W (In=5A, Vn=100/120V) 10W

280W – 800W (In=5A, Vn=400/440V) 40W

P< (low forwardpower) 14W – 40W (In=1A, Vn=100/120V) 2W

56W – 160W (In=1A, Vn=400/440V) 8W

70W – 200W (In=5A, Vn=100/120V) 10W

280W – 800W (In=5A, Vn=400/440V) 40W

P> (over power) 14W – 300W (In=1A, Vn=100/120V) 2W

56W – 1200W (In=1A, Vn=400/440V) 8W

70W – 1500W (In=5A, Vn=100/120V) 10W

280W – 6000W (In=5A, Vn=400/440V) 40W

DT 0 – 100s 0.1s

DO timer 0 – 10s 0.1s

VTS block Enable/disable

Stage 2 Same as Stage 1


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7.10 Voltage transformer supervision

Name Range Step size

Voltage threshold (V2) 10V (100/120V Fixed

40V (380/440V)

Phase overvoltage P.U. 30V, D.O. 10V Fixed

(100/120V) P.U.120V,

D.O.40V (380/440V)

Phase overcurrent 0.08In to 32In (Model 1)

0.08In to 10In (Models 2&3) 0.01In

Superimposed current 0.1In Fixed

Current threshold (I2) 0.1In Fixed

Timer 1.0 – 10s 0.1s

7.11 Nominal frequency

Setting Range Step size

Frequency 50 to 60 Hz 10 Hz

7.12 Breaker fail timers (tBF1 and tBF2)

These timers can be enabled or disabled via a setting.

Timer Setting range Step sizetBF1 0 to 10s 0.01stBF2 0 to 10s 0.01s

The timers are reset by:

• undercurrent elements operating, or

• initiating element drop-off (loss of external initiating signal), or

• circuit breaker open auxiliary contact (if current operation/external deviceis not applicable)


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Section 8. CONTROL FUNCTION SETTINGS

8.1 Circuit breaker state monitoring

Circuit breaker state monitoring shall be based on the monitoring of discrepancybetween circuit breaker auxiliary contacts 52a and 52b.

If these contacts remain simultaneously open or simultaneously closed for >5s, thenthe trip circuit alarm shall be indicated.

8.2 Circuit breaker control

Name Range Step sizeTrip pulse time 0.1 to 5s 0.01sClose pulse time 0.1 to 10s 0.01sDelay time before close 0.1 to 600s 0.01s

8.3 Circuit breaker condition monitoring

8.3.1 Maintenance alarm settings

Name Range Step sizeOperation threshold 1– 10000 1Ix threshold 1000 – 2.5 x 1012 1000t threshold 5 – 500ms 1ms

8.3.2 Lock-out alarm settings

Name Range Step sizeOperation threshold 1– 10000 1Ix threshold 1000 – 2.5 x 1012 1000t threshold 5 – 500ms 1ms

8.4 Reconnection time delay

Setting Range StepReconnection timer 0 – 300s 0.01sReset timer 0.01s – 30s 0.01s


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Section 9. INPUT AND OUTPUT SETTING RANGES

9.1 CT and VT ratio settings

Primary range Secondary range

Current transformer 1 – 30000 Amps 1 or 5 Ampsstep size 1A

Voltage transformer 100V – 10000kV 100 – 440Vstep size 1V



Chapter 5SCADA Communications


ContentsPage 1 of 1

1. INTRODUCTION 12. COURIER INTERFACE 12.1 Courier protocol 12.2 Front courier port 22.3 Supported command set 22.4 Relay courier database 32.5 Setting changes 32.5.1 Method 1 32.5.3 Relay settings 42.5.4 Setting transfer mode 42.6 Event extraction 42.6.1 Automatic event extraction 52.6.2 Event types 52.6.3 Event format 52.6.4 Manual event record extraction 62.7 Disturbance record extraction 62.8 Programmable logic settings 73. MODBUS INTERFACE 73.1 Communication link 73.2 Modbus functions 73.3 Response codes 83.4 Register mapping 93.5 Event extraction 93.5.1 Manual selection 93.5.2 Automatic extraction 93.5.3 Record data 103.6 Disturbance record extraction 103.6.1 Manual selection 103.6.2 Automatic extraction 103.6.3 Record data 103.7 Setting changes 113.7.1 Password protection 113.7.2 Control and support settings 113.7.3 Protection and disturbance recorder settings 124. IEC 60870-5-103 INTERFACE 124.1 Physical connection and link layer 124.2 Initialisation 134.3 Time synchronisation 134.4 Spontaneous events 134.5 General interrogation 144.6 Cyclic measurements 144.7 Commands 144.8 Test mode 144.9 Disturbance records 144.10 Blocking of monitor direction 14


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Section 1. INTRODUCTION

This chapter describes the remote interfaces of the MiCOM relay in enough detailto allow integration within a substation communication network. As has beenoutlined in earlier chapters the relay supports a choice of one of three protocolsvia the rear communication interface. This is in addition to the front serial interfacewhich supports the Courier protocol.

The rear RS485 interface is isolated and is suitable for permanent connectionwhichever protocol is selected. The advantage of this type of connection is that upto 32 relays can be ‘daisy chained’ together using a simple twisted pair electricalconnection.

For each of the three protocol options the supported functions/commands will belisted together with the database definition. The operation of standard proceduressuch as extraction of event, fault and disturbance records or setting changes willalso be described.

It should be noted that the descriptions contained within this chapter do not aim tofully detail the protocol itself. The relevant documentation for the protocol shouldbe referred to for this information. This chapter serves to describe the specificimplementation of the protocol on the relay.

Section 2. COURIER INTERFACE

2.1 Courier protocol

Courier is an ALSTOM Protection and Control communication protocol.The concept of the protocol is that a standard set of commands are used to accessa database of settings/data within the relay. This allows a generic master to beable to communicate with different slave devices. The application specific aspectsare contained, i.e. the master station does not need to be pre-configured.Within the database itself rather than the commands used to interrogate it.

The same protocol can be used via two physical links K-Bus or RS232; K-Bus isbased on RS485 voltage levels and is synchronous, the RS232 interface usesIEC60870 FT1.2 (IEC60870) frame format. The relay supports an IEC60870connection on the front, for one to one connection, this is not suitable forpermanent connection. This interface uses a fixed baud rate, 11 bit frame and afixed device address. The rear RS485 interface is used to provide a permanentconnection for K-Bus and allows multi-drop connection. It should be noted thatalthough K-Bus is based on RS485 voltage levels it is a synchronous protocol usingFM0 encoding. It is not possible to use a standard RS232 to RS485 converter toconvert IEC60870 to K-Bus.

The following documentation should be referred to for a detailed description of theCourier protocol, command set and link description.

R6509 K-Bus Interface Guide

R6510 IEC60870 Interface Guide

R6511 Courier Protocol

R6512 Courier User Guide


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2.2 Front courier port

The front RS232 port supports the Courier protocol for one to one communication.It is designed for use during installation and commissioning/maintenance and isnot suitable for permanent connection. Since this interface will not be used to linkthe relay to a substation communication system some of the features of Courier arenot implemented. These are as follows:

Automatic extraction of Event Records:Courier Status byte does not support the Event flagSent Event/Accept Event commands are not implemented

Automatic extraction of Disturbance records:Courier Status byte does not support the Disturbance flag

Busy Response Layer:Courier Status byte does not support the Busy flag, the only response to arequest will be the final data

Fixed Address:The address of the front Courier port is always 1, the Change Device addresscommand is not supported.

It should be noted that although automatic extraction of event and disturbancerecords is not supported it is possible to manually access this data via the frontport.

2.3 Supported command set

The following Courier commands are supported by the relay:

Protocol Layer

Reset Remote Link

Poll Status

Poll Buffer*

Low Level Commands

Send Event*

Accept Event*

Send Block

Store Block Identifier

Store Block Footer

Menu Browsing

Get Column Headings

Get Column Text

Get Column Values

Get Strings

Get Text

Get Value

Get Column Setting Limits


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Setting Changes

Enter Setting Mode

Preload Setting

Abort Setting

Execute Setting

Reset Menu Cell

Set Value

Control Commands

Select Setting Group

Change Device Address*

Set Real Time

Note: Commands indicated with a * are not supported via the front Courier port.

2.4 Relay courier database

The Courier database is two dimensional structure with each cell in the databasebeing referenced by a row and column address. Both the column and the row cantake a range from 0 to 255. Addresses in the database are specified ashexadecimal values, eg 0A02 is column 0A (10 decimal) row 02. Associatedsettings/data will be part of the same column, row zero of the column contains atext string to identify the contents of the column.

Appendix A contains the complete database definition for the relay for each celllocation the following information is stated:

• Cell Text

• Cell Datatype

• Cell value

• Whether if the cell is settable, if so

• Minimum value

• Maximum value

• Step size

• Password Level required to allow setting changes

• String information (for Indexed String or Binary flag cells)

2.5 Setting changes

(See Courier User Guide Chapter 9)

Courier provides two mechanisms for making setting changes, both of these aresupported by the relay. Either method can be used for editing any of the settingswithin the relay database.

2.5.1 Method 1

This uses a combination of three commands to perform a settings change:

Enter Setting Mode - checks that the cell is settable and returns the limits


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Preload Setting - Places a new value to the cell, this value is echoed to ensure thatsetting corruption has not taken place, the validity of the setting is not checked bythis action.

Execute Setting - Confirms the setting change, if the change is valid then a positiveresponse will be returned, if the setting change fails then an error response will bereturned.

Abort Setting - This command can be used to abandon the setting change.

This is the most secure method and is ideally suited to on-line editors as the settinglimits are taken from the relay before the setting change is made. However thismethod can be slow if many settings are being changed as three commands arerequired for each change.

2.5.2 Method 2

The Set Value command can be used to directly change a setting, the response tothis command will be either a positive confirm or an error code to indicate thenature of a failure. This command can be used to implement a setting more rapidlythen the previous method, however the limits are not extracted from the relay.This method is most suitable for off-line setting editors such as MiCOM S1.

2.5.3 Relay settings

There are three categories of settings within the relay database

• Control and Support

• Disturbance Recorder

• Protection Settings GroupSetting changes made to the control and support settings are implementedimmediately and stored in non-volatile memory. Settings made to either theDisturbance recorder settings or the Protection Settings Groups are stored inscratchpad memory only and are not immediately implemented by the relay.To action setting changes made to these areas of the relay database the SaveChanges cell in the Configuration column must be written to. This allows thechanges to either be confirmed and stored within non-volatile memory or thesetting changes to be aborted.

2.5.4 Setting transfer mode

If it is necessary to transfer all of the relay settings to or from the relay a cell withinthe Communication System Data column can be used. This cell (location BF03)when set to 1 makes all of the relay settings visible. Any setting changes made withthe relay set in this mode are stored in scratchpad memory (including control andsupport settings). When the value of BF03 is set back to 0 any setting changes areconfirmed and stored in non-volatile memory.

2.6 Event extraction

Events can be extracted either automatically (rear port only) or manually (eitherCourier port). For automatic extraction all events are extracted in sequential orderusing the standard Courier mechanism, this includes fault/maintenance data ifappropriate. The manual approach allows the user to select events,faults ormaintenance data at random from the stored records.


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2.6.1 Automatic event extraction

(See Chapter X Courier User Guide)

This method is intended for continuous extraction of event and fault information asit is produced, it is only supported via the rear Courier port.

When new event information is created the Event bit is set within the Status byte,this indicates to the Master device that event information is available. The oldest,unextracted event can be extracted from the relay using the Send Event command.The relay will respond with the event data, which will be either a Courier Type 0or Type 3 event. The Type 3 event is used for fault records and maintenancerecords.

Once an event has been extracted from the relay the Accept Event can be used toconfirm that the event has been successfully extracted. If all events have beenextracted then the event bit will reset, if there are more events still to be extractedthe next event can be accessed using the Send Event command as before.

2.6.2 Event types

Events will be created by the relay under the following circumstances:

• Change of state of output contact

• Change of state of opto input

• Protection element operation

• Alarm condition

• Setting Change

• Password entered/timed-out

• Fault Record (Type 3 Courier Event)

• Maintenance record (Type 3 Courier Event)

2.6.3 Event format

The Send Event command results in the following fields being returned by therelay:

• Cell Reference

• Timestamp

• Cell Text

• Cell Value

Appendix B contains a table of the events created by the relay and indicates howthe contents of the above fields are interpreted. Fault records and Maintenancerecords will return a Courier Type 3 event which contains the above fields togetherwith two additional fields:

• Event extraction column

• Event number

These events contain additional information which is extracted from the relay usingthe referenced extraction column. Row 01 of the extraction column contains asetting which allows the fault/maintenance record to be selected. This settingshould be set to the event number value returned within the record, the extendeddata can be extracted from the relay by uploading the text and data from thecolumn.


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2.6.4 Manual event record extraction

Column 01 of the database can be used for manual viewing of event, fault andmaintenance records. The contents of this column will depend of the nature of therecord selected. It is possible to select by event number, or to directly select a faultrecord or maintenance record.

Event Record selection (Row 01) - This cell can be set to a value between 0 to 249to select which of the 250 stored events is selected, 0 will select the most recentrecord; 249 the oldest stored record. For simple event records (Type 0) cells 0102to 0105 contain the event details. A single cell is used to represent each of theevent fields. If the event selected is a fault or maintenance record (Type 3) then theremainder of the column will contain the additional information.

Fault Record Selection (Row 05) - This cell can be used to directly select a faultrecord using a value between 0 and 4 to select one of up to five stored faultrecords (0 will be the most recent fault and 4 will be the oldest). The column willthen contain the details of the fault record selected.

Maintenance Record Selection (Row F0) - This cell can be used to select amaintenance record using a value between 0 and 4 and operates in a similar wayto the fault record selection.

It should be noted that if this column is used to extract event information from therelay the number associated with a particular record will change when a newevent or fault occurs.

2.7 Disturbance record extraction

The stored disturbance records within the relay are accessible in a compressedformat via the Courier interface. The records are extracted using column B4, itshould be noted that cells required for extraction of uncompressed disturbancerecords are not supported.

Select Record Number (Row 01) - This cell can be used to select the record to beextracted. Record 0 will be the oldest un-extracted record, older records will beassigned positive values, and negative values will be used for more recent records.To facilitate automatic extraction via the rear port the Disturbance bit of the Statusbyte is set by the relay whenever there are unextracted disturbance records.

Once a record has been selected, using the above cell, the time and date of therecord can be read from cell 02. The disturbance record itself can be extractedusing the block transfer mechanism from cell B00B. It should be noted that the fileextracted from the relay is in a compressed format, it will be necessary to useMiCOM S1 to de-compress this file and save the disturbance record in theCOMTRADE format.

As has been stated the rear Courier port can be used to automatically extractdisturbance records as they occur. This operates using the standard Couriermechanism defined in Chapter 8 of the Courier User Guide. The front Courier portdoes not support automatic extraction although disturbance record data can beextracted manually from this port.


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2.8 Programmable logic settings

The programmable logic settings can be uploaded from and downloaded to therelay using the block transfer mechanism defined in Chapter 12 of the Courier UserGuide.The following cells are used to perform the extraction

• B204 Domain: Used to select either PSL settings (Upload or download) or PSLconfiguration data (Upload only)

• B208 Sub-Domain: Used to select the Protection Setting Group to be uploaded/downloaded.

• B20C Version: Used on a download to check the compatibility of the file to bedownloaded with the relay.

• B21C Transfer Mode: Used to set-up the transfer process

• B120 Data Transfer Cell: Used to perform upload/download.

The Programmable scheme logic settings can be uploaded and downloaded to andfrom the relay using this mechanism. If it is necessary to edit the settings MiCOMS1 must be used as the data format is compressed. MiCOM S1 also performschecks on the validity of the settings before they are downloaded to the relay.

Section 3. MODBUS INTERFACE

The Modbus interface is a master/slave protocol, it is defined by MODICON Incby the following document:

Modicon Modbus Protocol Reference GuidePI-MBUS-300 Rev. E

3.1 Communication link

This interface also uses the rear RS485 port for communication using RTU modecommunication rather than ASCII mode as this provides more efficient use of thecommunication bandwidth. This mode of communication is defined in page 7 ofthe Modbus Guide.

The following parameters can be configured for this port using either the frontpanel interface or the front Courier port:

Baud Rate

Device Address

Parity

Inactivity Time

3.2 Modbus functions

The following Modbus function codes are supported by the relay:

01 Read Coil Status

02 Read Input Status

03 Read Holding Registers

04 Read Input Registers

06 Preset Single Register


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08 Diagnostics

11 Fetch Communication Event Counter

12 Fetch Communication Event Log

16 Preset Multiple Registers 127 max

These are interpreted by the MiCOM relay in the following way:

01 Read status of output contacts (1xxxx addresses)

02 Read status of opto inputs (2xxxx addresses)

03 Read Setting values (4xxxx addresses)

04 Read Measured values (3xxxx addresses

06 Write single setting value (4xxxx addresses)

16 Write multiple setting values (4xxxx addresses)

3.3 Response codes

Code Modbus description MiCOM interpretation01 Illegal Function Code The function code transmitted is not

supported by the slave02 Illegal Data Address The start data address in the request is not

an allowable value. If any of the cells inthe range to be written to cannot beaccessed due to password protection thenall changes within the request arediscarded and this error response will bereturned. Note: If the start address iscorrect but the range includes non -implemented addresses this response isnot produced

03 Illegal Value A value referenced in the data fieldtransmitted by the master is not withinrange. Other values transmitted within thesame packet will be executed if insiderange.

06 Slave Device Busy The write command cannot beimplemented due to the database beinglocked by another interface. This responseis also produced if the relay software isbusy executing a previous request.


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3.4 Register mapping

The relay supports the following memory page references:-

Memory Page Interpretation

0xxxx Read and write access of the Output Relays.

1xxxx Read only access of the Opto Inputs.

3xxxx Read only access of Data.

4xxxx Read and write access of Settings.

where xxxx represents the addresses available in the page (0 to 9999).

Note that the “extended memory file” (6xxxx) is not supported.

A complete map of the Modbus addresses supported by the relay is contained inAppendix 1 of this service manual.

3.5 Event extraction

The relay supports two methods of event extraction providing either automatic ormanual extraction of the stored event, fault and maintenance records.

3.5.1 Manual selection

There are three registers available to manually select stored records, there are alsothree read only registers allowing the number of stored records to be determined.

40100 - Select Event, 0 to 249

40101 - Select Fault, 0 to 4

40102 - Select Maintenance Record, 0 to 4

For each of the above registers a value of 0 represents the most recent storedrecord.The following registers can be read to indicate the numbers of the various types ofrecord stored.

30100 - Number of stored records

30101 - Number of stored fault records

30102 - Number of stored maintenance records

Each fault or maintenance record logged causes an event record to be created bythe relay. If this event record is selected the additional registers allowing the faultor maintenance record details will also become populated.

3.5.2 Automatic extraction

The automatic extraction facilities allow all types of record to be extracted as theyoccur. Event records are extracted in sequential order including any fault ormaintenance data that may be associated with the event.

The Modbus master can determine whether the relay has any events stored thathave not yet been extracted. This is performed by reading the relay status register30001. If the event bit of this register is set then the relay has unextracted eventsavailable. To select the next event for sequential extraction the master station writesa value of 1 to the record selection register 40400. The event data together withany fault/maintenance data can be read from the registers specified below. Oncethe data has been read the event record can be marked as having been read bywriting a value of 2 to register 40400.


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3.5.3 Record data

The location and format of the registers used to access the record data is the samewhether they have been selected using either of the two mechanisms detailedabove.

Event Record Data: 30103 to 30109

The presence of additional data for the event record is indicated by cell 30110, avalue of 0 means that there is no additional data.

30110 = 1, fault record data can be read from 30111 to 30197

30110 = 2, maintenance record data can be read from 30198 to 30199

If a fault record or maintenance record is directly selected using the manualmechanism then the data can be read from the register ranges specified above, theevent record data in cells 30103 to 30109 will not be available.

It is possible using register 40401 to clear independently the stored relay event/fault and maintenance records. This register also provides an option to reset therelay indications, this has the same effect on the relay as pressing the clear keywithin the alarm viewer using the front panel menu.

3.6 Disturbance record extraction

The relay provides facilities for both manual and automatic extraction ofdisturbance records. The two methods differ only in the mechanism for selecting adisturbance record, the method for extracting the data and the format of the dataare identical.

3.6.1 Manual selection

Each disturbance record has a unique identifier which increments for each storedrecord and resets at a value of 65535. The following registers can be used todetermine the identifiers for the stored records

30800 - The number of stored disturbance records

30801 - The identifier for the oldest stored record

A record can be selected by writing the required record identifier to register40250. It is possible to read the timestamp of the selected record and in this wayproduce a list of all the stored records.

3.6.2 Automatic extraction

The Modbus master station can determine the presence of unread disturbancerecords by polling register 30001. When the disturbance bit of this register is setdisturbance records are available for extraction. To select the next disturbancerecord write a value of 3 to cell 40400. Once the disturbance record data hasbeen read by the master station this record can be marked as having been read bywriting a value of 4 to register 40400.

3.6.3 Record data

The timestamp for a record selected using either of the above means can be readfrom registers 30390 to 30393. The disturbance record data itself is stored in acompressed format, due to the size of the disturbance record it must be read usinga paging system.The number of pages required to extract a record will depend on the configuredsize of the record.


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When a record is first selected the first page of data will be available in registers30803 to 30929 (the number of registers required for the current page can beread from register 30802, this will be 127 for all but the last page in the record).Once the first page has been read the next page can be selected by writing avalue of 5 to register 40400. If this action is performed on the last page for thedisturbance record an illegal value error response will be returned. This errorresponse can be used by the Modbus master to indicate that the last page of thedisturbance record has been read.

3.7 Setting changes

The relay settings can be split into two categories:

• control and support settings

• disturbance record settings and protection setting groups

Changes to settings within the control and support area are executed immediately.Changes to either the protection setting groups or the disturbance recorder arestored in a temporary area and must be confirmed before they are implemented.All the relay settings are edited via Modbus using 4xxxx addresses. The followingpoints should be noted when settings are being edited:

• Settings implemented using multiple registers must be written to using a multi-register write operation.

• The first address for a multi-register write must be a valid address, if there areunmapped addresses within the range being written to then the data associatedwith these addresses will be discarded.

• If a write operation is performed with values that are out of range then theillegal data response will be produced. Valid setting values within the samewrite operation will be executed.

• If a write operation is performed attempting to change registers that require ahigher level of password access than is currently enabled then all settingchanges in the write operation will be discarded.

3.7.1 Password protection

As described in the introduction to this service manual the relay settings can besubject to Password protection. The level of password protection required to edit asetting is indicated in relay setting database (Appendix A). Level 2 is the highestlevel of password access, level 0 indicates that no password is required forediting.

The following registers are available to control Password protection:

40001&40002 Password Entry

40022 Default Password Level

40023&40024 Setting to Change password level 1

40025&40026 Setting to Change password level 2

30010 Can be read to indicate current access level

3.7.2 Control and support settings

Control and support settings are executed immediately on the write operation.


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3.7.3 Protection and disturbance recorder settings

Setting changes to either of these areas are stored in a scratchpad area and willnot be used by the relay unless a confirm or to abort operation is performed.Register 40405 can be used to either to confirm or abort the setting changeswithin the scratchpad area. It should be noted that the relay supports four groupsof protection settings. The Modbus addresses for each of the four groups arerepeated within the following address ranges:

Group 1 41000-42999

Group 2 43000-44999

Group 3 45000-46999

Group 4 47000-48999

In addition to the basic editing of the protection setting groups the followingfunctions are provided.

• Default values can be restored to a setting group or to all of the relay settings bywriting to register 40402.

• It is possible to copy the contents of one setting group to another by writing thesource group to register 40406 and the target group to 40407.

It should be noted that the setting changes performed by either of the twooperations defined above are made to the scratchpad area. These changes mustbe confirmed by writing to register 40405.

The active protection setting groups can be selected by writing to register 40404.An illegal data response will be returned if an attempt is made to set the activegroup to one that has been disabled.

Section 4. IEC60870-5-103 INTERFACE

The IEC60870-5-103 interface is a master/slave interface with the relay as theslave device. This protocol is based on the VDEW communication protocol.The relay conforms to compatibility level 2, compatibility level 3 is not supported.

The following IEC60870-5-103 facilities are supported by this interface:

• Initialisation (Reset)

• Time Synchronisation

• Event Record Extraction

• General Interrogation

• Cyclic Measurements

• General Commands

4.1 Physical connection and link layer

Two connection options are available for IEC60870-5-103, either the rear RS485port or an optional rear fibre optic port. Should the fibre optic port be fitted theselection of the active port can be made via the front panel menu or the frontCourier port, however the selection will only be effective following the next relaypower up.


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For either of the two modes of connection it is possible to select both the relayaddress and baud rate using the front panel menu/front Courier. Following achange to either of these two settings a reset command is required to re-establishcommunications.

4.2 Initialisation

Whenever the relay has been powered up, or if the communication parametershave been changed a reset command is required to initialize the communications.The relay will respond to either of the two reset commands (Reset CU or ResetFCB), the difference being that the Reset CU will clear any unsent messages in therelay’s transmit buffer.

The relay will respond to the reset command with an identification messageASDU 5, the Cause Of Transmission COT of this response will be either Reset CUor Reset FCB depending on the nature of the reset command. The followinginformation will be contained in the data section of this ASDU:

Manufacturer Name: ALSTOM

The Software Identification Section will contain the first four characters of the relaymodel number to identify the type of relay, eg P141.

In addition to the above identification message, if the relay has been powered upit will also produce a power up event.

4.3 Time synchronisation

The relay time and date can be set using the time synchronisation feature of theIEC60870-5-103 protocol. The relay will correct for the transmission delay asspecified in IEC60870-5-103. If the time synchronisation message is sent as asend/confirm message then the relay will respond with a confirm. Whether thetime synchronisation message is sent as a send confirm or a broadcast (send/noreply) message, a time synchronisation message will be returned as Class 1 data.

If the relay clock is being synchronized using the IRIG-B input then it will not bepossible to set the relay time using the IEC60870-5-103 interface. An attempt toset the time via the interface will cause the relay to create an event with the currentdate and time taken from the IRIG-B synchronized internal clock.

4.4 Spontaneous events

The events created by the relay will be passed using the standard function type/information numbers to the IEC60870-5-103 master station. Private codes are notused, thus any events that cannot be passed using the standardized messages willnot be sent.

Events are categorized using the following information:

Common Address

Function Type

Information number

Appendix 1 contains a complete listing of all events produced by the relay.The common address is used to differentiate in circumstances where the relayproduces more events of a certain type than can be passed using the standardizedmessages. For example if the relay produces starts and trips for four stages ofovercurrent only two stages can be passed using the standardized messages.


Page 14 of 14

Using the different common address for two of the overcurrent stages allows eachstage to be indicated. The table in Appendix 1 shows the common address as anoffset value. The common address offset will be added to the station address inorder to pass these events.

4.5 General interrogation

The GI request can be used to read the status of the relay, the function numbers,information numbers and common address offsets that will be returned during theGI cycle are indicated in Appendix 1.

4.6 Cyclic measurements

The relay will produce measured values using ASDU 9 on a cyclical basis, this canbe read from the relay using a Class 2 poll (note ADSU 3 is not used). The rate atwhich the relay produces new measured values can be controlled using theMeasurement Period setting. This setting can be edited from the front panel menu/front Courier port and is active immediately following a change.

It should be noted that the measurands transmitted by the relay are sent as aproportion of either 1.2 or 2.4 times the rated value of the analog value.The selection of either 1.2 or 2.4 for a particular value is indicated in Appendix 1.

4.7 Commands

A list of the supported commands is contained in Appendix 1. The relay willrespond to other commands with an ASDU 1, with a cause of transmission (COT)of negative acknowledgement of a command.

4.8 Test mode

It is possible using either the front panel menu or the front Courier port to disablethe relay output contacts to allow secondary injection testing to be performed.This is interpreted as test mode by the IEC60870-5-103 standard. An event will beproduced to indicate both entry to and exit from test mode. Spontaneous eventsand cyclic measured data transmitted whilst the relay is in test mode will have aCOT of test mode.

4.9 Disturbance records

The disturbance records stored by the relay cannot be extracted using themechanism defined in the IEC60870-5-103 standard. The relay maintainscompatibility with the VDEW control system by transmitting an ASDU 23 with nodisturbance records at the start of every GI cycle.

Any attempt to extract disturbance record data from the relay (using ASDU 24) willresult in the relay responding with ASDU 31 end of transmission of disturbancerecord with a Type of Order of abortion by the protection equipment.

4.10 Blocking of monitor direction

The relay does not support a facility to block messages in the Monitor direction.



Appendix ACourier Database

TECHNICAL GUIDE TG8617AMiCOM P341 Volume 2INTERCONNECTION PROTECTION RELAY Appendix A

Page 1 of 87

APPENDIX A

This Appendix is split into several sections, these are as follows:

• Menu Database for Courier, User Interface and Modbus

• Menu Datatype Definition

• Event Data for Courier, User Interface and Modbus

• IEC 60870-5-103 Interoperability Guide

• Internal Digital Signals

• Default Programmable Logic

Menu database

This database defines the structure of the relay menu for the Courier interface, thefront panel user interface and the Modbus interface. This includes all the relaysettings and measurements. Datatypes for Modbus and indexed strings for Courierand the user interface are cross referenced to the Menu Datatype Definition section(using a G Number). For all settable cells the setting limits and default value arealso defined within this database.

Note: The following labels are used within the database

Label Description Value

V1 Main VT Rating 1 (100/110V) or 4 (380/440V)

V2 Checksync VT Rating 1 (100/110V) or 4 (380/440V)

V3 NVD VT Rating 1 (100/110V) or 4 (380/440V)

I1 Phase CT Rating 1 or 5 (Setting 0A08)

I2 Earth Fault CT Raing 1 or 5 (Setting 0A0A)

I3 Sensitive CT Rating 1 or 5 (Setting 0A0C)

I4 Mutual CT Rating 1 or 5 (Setting 0A0E)

Menu datatype definition

This table defines the datatypes used for Modbus (the datatypes for the Courierand user interface are defined within the Menu Database itself using the standardCourier Datatypes). This section also defines the indexed string setting options forall interfaces. The datatypes defined within this section are cross reference to fromthe Menu Database using a G number.

Event data

This section of the Appendix specifies all the event information that can beproduced by the relay. It details exactly how each event will be presented via theCourier, User and Modbus interfaces.

IEC 60870-5-103 Interoperability guide

This table fully defines the operation of the IEC 60870-5-103 (VDEW) interface forthe relay it should be read in conjunction with the relevant section of theCommunications Chapter of this Manual (Volume 1 Chapter 5).


Page 2 of 87

Internal digital signals

This table defines all of the relay internal digital signals (opto inputs, outputcontacts and protection inputs and outputs). A relay may have up to 512 internalsignals each reference by a numeric index as shown in this table. This numericindex is used to select a signal for the commissioning monitor port. It is also usedto explicitly define protection events produced by the relay (see the Event Datasection of this Appendix).

Default programmable logic

This section documents the default programmable logic for the various models ofthe relay. This default logic for each model of the relay is supplied with theMiCOM S1 Scheme Logic Editor PC support software.

References

Chapter 1 Introduction : User Interface operation and connections to relay

Chapter 5 Communications: Overview of communication interfaces

Courier User Guide R6512

Modicon Modbus Protocol Reference GuidePI-MBUS-300 Rev. E

IEC 60870-5-103 Telecontrol Equipment and Systems - Transmission Protocols -Companion Standard for the informative interface of Protection Equipment


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le if

Ala

rmVT

S/CT

S

Fault

ed P

hase

N/A

0107

Bina

ry F

lag

(8 B

its)

G16

3011

1G

16Da

ta*

**

Star

ted

phas

es +

trip

ped

phas

es

Star

t Ele

men

ts1N

/A01

08Bi

nary

Fla

g (3

2 Bi

ts)G

8430

112

3011

3G

84Da

ta*

**

Star

ted

Elem

ents

Inde

xed

Strin

g

Star

t Ele

men

ts2N

/A01

09Bi

nary

Fla

g (3

2 Bi

ts)G

107

3011

430

115

G10

7Da

ta*

**

Star

ted

Elem

ents

Inde

xed

Strin

g

Trip

Ele

men

ts1N

/A01

0ABi

nary

Fla

g (3

2 Bi

ts)G

8530

116

3011

7G

85Da

ta*

**

Trip

ped

mai

n el

emen

tsIn

dexe

d St

ring

Trip

Ele

men

ts2N

/A01

0BBi

nary

Fla

g (3

2 Bi

ts)G

8630

118

3011

9G

86Da

ta*

**

Trip

ped

seco

ndar

y el

emen

tsIn

dexe

d St

ring


Page 8 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Fault

Ala

rms

N/A

010C

Bina

ry F

lag

(32

Bits)

G87

3012

030

121

G87

Data

**

*Fa

ullt A

larm

s/W

arni

ngs

Inde

xed

Strin

g

Fault

Tim

e01

0DIE

C870

Tim

e &

Date

3012

230

125

G12

(Fro

m R

ecor

d)Da

ta*

**

Activ

e G

roup

010E

Unsig

ned

Inte

ger

3012

6G

1Da

ta*

**

Syste

m F

requ

ency

010F

Cour

ier N

umbe

r (fre

quen

cy)

3012

7G

30Da

ta*

**

Fault

Dur

atio

n01

10Co

urie

r Num

ber (

time)

3012

830

129

G24

Data

**

*

CB O

pera

te Ti

me

0111

Cour

ier N

umbe

r (tim

e)30

130

G25

Data

**

*

Rela

y Tr

ip T

ime

0112

Cour

ier N

umbe

r (tim

e)30

131

3013

2G

24Da

ta*

**

IA01

13Co

urie

r Num

ber (

curre

nt)

3013

330

134

G24

Data

**

IA-1

*

IB01

14Co

urie

r Num

ber (

curre

nt)

3013

530

136

G24

Data

**

IB-1

*

IC01

15Co

urie

r Num

ber (

curre

nt)

3013

730

138

G24

Data

**

IC-1

*

VAB

0116

Cour

ier N

umbe

r (vo

ltage

)30

139

3014

0G

24Da

ta*

**

VBC

0117

Cour

ier N

umbe

r (vo

ltage

)30

141

3014

2G

24Da

ta*

**

VCA

0118

Cour

ier N

umbe

r (vo

ltage

)30

143

3014

4G

24Da

ta*

**

VAN

0119

Cour

ier N

umbe

r (vo

ltage

)30

145

3014

6G

24Da

ta*

**

VBN

011A

Cour

ier N

umbe

r (vo

ltage

)30

147

3014

8G

24Da

ta*

**

VCN

011B

Cour

ier N

umbe

r (vo

ltage

)30

149

3015

0G

24Da

ta*

**

IA-2

011C

Cour

ier N

umbe

r (cu

rrent

)30

151

3015

2G

24Da

ta*

IB-2

011D

Cour

ier N

umbe

r (cu

rrent

)30

153

3015

4G

24Da

ta*

IC-2

011E

Cour

ier N

umbe

r (cu

rrent

)30

155

3015

6G

24Da

ta*

IA D

iffer

entia

l01

1FCo

urie

r Num

ber (

curre

nt)

3015

730

158

G24

Data

*

IB D

iffer

entia

l01

20Co

urie

r Num

ber (

curre

nt)

3015

930

160

G24

Data

*

IC D

iffer

entia

l01

21Co

urie

r Num

ber (

curre

nt)

3016

130

162

G24

Data

*

VN M

easu

red

0122

Cour

ier N

umbe

r (vo

ltage

)30

163

3016

4G

24Da

ta*

**

VN D

erive

d01

23Co

urie

r Num

ber (

volta

ge)

3016

530

166

G24

Data

**

*


Page 9 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

IN D

erive

d01

24Co

urie

r Num

ber (

curre

nt)

3016

730

168

G24

Data

*IN

Mea

sure

d*

*

IN S

ensit

ive01

25Co

urie

r Num

ber (

curre

nt)

3016

930

170

G24

Data

**

*

IREF

Diff

0126

Cour

ier N

umbe

r (cu

rrent

)30

171

3017

2G

24Da

ta*

*

IREF

Bia

s01

27Co

urie

r Num

ber (

curre

nt)

3017

330

174

G24

Data

**

I201

28Co

urie

r Num

ber (

curre

nt)

3017

530

176

G24

Data

**

3 Ph

ase

Wat

ts01

29Co

urie

r Num

ber (

Pow

er)

3017

730

179

G29

Data

**

*

3 Ph

ase

VArs

012A

Cour

ier N

umbe

r (VA

r)30

180

3018

2G

29Da

ta*

**

3Ph

Pow

er F

acto

r01

2BCo

urie

r Num

ber (

Decim

al)

3018

3G

30Da

ta*

**

RTD

1 La

bel

012C

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3018

4G

10Da

ta*

*

RTD

2 La

bel

012D

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3018

5G

10Da

ta*

*

RTD

3 La

bel

012E

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3018

6G

10Da

ta*

*

RTD

4 La

bel

012F

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3018

7G

10Da

ta*

*

RTD

5 La

bel

0130

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3018

8G

10Da

ta*

*

RTD

6 La

bel

0131

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3018

9G

10Da

ta*

*

RTD

7 La

bel

0132

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3019

0G

10Da

ta*

*

RTD

8 La

bel

0133

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3019

1G

10Da

ta*

*

RTD

9 La

bel

0134

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3019

2G

10Da

ta*

*

RTD

10 La

bel

0135

Cour

ier N

umbe

r (Te

mpe

ratu

re)

3019

3G

10Da

ta*

*

df/d

t01

36Co

urie

r Num

ber (

Hz/s

)30

194

G25

Data

*Vi

sible

if d

f/ft

trip

V Ve

ctor S

hift

0137

Cour

ier N

umbe

r (An

gle)

3019

5G

30Da

ta*

Visib

le if

V V

ecto

r shi

ft tri

p

Sele

ct M

aint

01F0

Unsig

ned

Inte

ger (

16 b

its)

4010

2G

1Se

tting

04

10

**

*Al

low

s Sel

f Tes

t Rep

ort t

o be

sele

cted

Mai

nt Te

xt01

F1As

cii Te

xt (3

2 ch

ars)

Data

**

*

Mai

nt Ty

pe01

F2Un

signe

d in

tege

r (32

bits

)30

196

3019

7G

27Da

ta*

**

Mai

nt D

ata

01F3

Unsig

ned

inte

ger (

32 b

its)

3019

830

199

G27

Data

**

*

Rese

t Ind

icatio

n01

FFIn

dexe

d St

ring

G11

No

Com

man

d0

11

1*

**


Page 10 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

MEA

SURE

MEN

TS 1

0200

**

*

IA M

agni

tude

0201

Cour

ier N

umbe

r (cu

rrent

)30

200

3020

1G

24Da

ta*

*IA

-1 M

agni

tude

*

IA P

hase

Ang

le02

02Co

urie

r Num

ber (

angl

e)30

202

G30

Data

**

IA-1

Pha

se A

ngle

*

IB M

agni

tude

0203

Cour

ier N

umbe

r (cu

rrent

)30

203

3020

4G

24Da

ta*

*IB

-1 M

agni

tude

*

IB P

hase

Ang

le02

04Co

urie

r Num

ber (

angl

e)30

205

G30

Data

**

IB-1

Pha

se A

ngle

*

IC M

agni

tude

0205

Cour

ier N

umbe

r (cu

rrent

)30

206

3020

7G

24Da

ta*

*IC

-1 M

agni

tude

*

IC P

hase

Ang

le02

06Co

urie

r Num

ber (

angl

e)30

208

G30

Data

**

IC-1

Pha

se A

ngle

*

IN M

easu

red

Mag

0207

Cour

ier N

umbe

r (cu

rrent

)30

209

3021

0G

24Da

ta*

*

IN M

easu

red

Ang

0208

Cour

ier N

umbe

r (an

gle)

3021

1G

30Da

ta*

*

IN D

erive

d M

ag02

09Co

urie

r Num

ber (

curre

nt)

3021

230

213

G24

Data

*

IN D

erive

d An

gle

020A

Cour

ier N

umbe

r (an

gle)

3021

4G

30Da

ta*

ISEF

Mag

nitu

de02

0BCo

urie

r Num

ber (

curre

nt)

3021

530

216

G24

Data

**

*

ISEF

Ang

le02

0CCo

urie

r Num

ber (

degr

ees)

3021

7G

30Da

ta*

**

I1 M

agni

tude

020D

Cour

ier N

umbe

r (cu

rrent

)30

218

3021

9G

24Da

ta*

**

I2 M

agni

tude

020E

Cour

ier N

umbe

r (cu

rrent

)30

220

3022

1G

24Da

ta*

**

I0 M

agni

tude

020F

Cour

ier N

umbe

r (cu

rrent

)30

222

3022

3G

24Da

ta*

**

IA R

MS

0210

Cour

ier N

umbe

r (cu

rrent

)30

224

3022

5G

24Da

ta*

**

IB R

MS

0211

Cour

ier N

umbe

r (cu

rrent

)30

226

3022

7G

24Da

ta*

**

IC R

MS

0212

Cour

ier N

umbe

r (cu

rrent

)30

228

3022

9G

24Da

ta*

**

VAB

Mag

nitu

de02

14Co

urie

r Num

ber (

volta

ge)

3023

030

231

G24

Data

**

*

VAB

Phas

e An

gle

0215

Cour

ier N

umbe

r (an

gle)

3023

2G

30Da

ta*

**

VBC

Mag

nitu

de02

16Co

urie

r Num

ber (

volta

ge)

3023

330

234

G24

Data

**

*

VBC

Phas

e An

gle

0217

Cour

ier N

umbe

r (an

gle)

3023

5G

30Da

ta*

**


Page 11 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

VCA

Mag

nitu

de02

18Co

urie

r Num

ber (

volta

ge)

3023

630

237

G24

Data

**

*

VCA

Phas

e An

gle

0219

Cour

ier N

umbe

r (an

gle)

3023

8G

30Da

ta*

**

VAN

Mag

nitu

de02

1ACo

urie

r Num

ber (

volta

ge)

3023

930

240

G24

Data

**

*

VAN

Pha

se A

ngle

021B

Cour

ier N

umbe

r (an

gle)

3024

1G

30Da

ta*

**

VBN

Mag

nitu

de02

1CCo

urie

r Num

ber (

volta

ge)

3024

230

243

G24

Data

**

*

VBN

Pha

se A

ngle

021D

Cour

ier N

umbe

r (an

gle)

3024

4G

30Da

ta*

**

VCN

Mag

nitu

de02

1ECo

urie

r Num

ber (

volta

ge)

3024

530

246

G24

Data

**

*

VCN

Pha

se A

ngle

021F

Cour

ier N

umbe

r (an

gle)

3024

7G

30Da

ta*

**

VN M

easu

red

Mag

0220

Cour

ier N

umbe

r (vo

ltage

)30

248

3024

9G

24Da

ta*

**

VN M

easu

red

Ang

0221

Cour

ier N

umbe

r (an

gle)

3025

0G

30Da

ta*

**

VN D

erive

d M

ag02

22Co

urie

r Num

ber (

volta

ge)

3025

130

252

G24

Data

**

*

VN D

erive

d An

g02

23Co

urie

r Num

ber (

angl

e)30

252

G30

Data

**

*

V1 M

agni

tude

0224

Cour

ier N

umbe

r (vo

ltage

)30

253

3025

4G

24Da

ta*

**

V2 M

agni

tude

0225

Cour

ier N

umbe

r (vo

ltage

)30

255

3025

6G

24Da

ta*

**

V0 M

agni

tude

0226

Cour

ier N

umbe

r (vo

ltage

)30

257

3025

8G

24Da

ta*

**

VAN

RM

S02

27Co

urie

r Num

ber (

volta

ge)

3025

930

260

G24

Data

**

*

VBN

RM

S02

28Co

urie

r Num

ber (

volta

ge)

3026

130

262

G24

Data

**

*

VCN

RM

S02

29Co

urie

r Num

ber (

volta

ge)

3026

330

264

G24

Data

**

*

Freq

uenc

y02

2DCo

urie

r Num

ber (

frequ

ency

)30

265

G30

Data

**

*

MEA

SURE

MEN

TS 2

0300

**

*

A Ph

ase

Wat

ts03

01Co

urie

r Num

ber (

Pow

er)

3030

030

302

G29

Data

**

*

B Ph

ase

Wat

ts03

02Co

urie

r Num

ber (

Pow

er)

3030

330

305

G29

Data

**

*

C Ph

ase

Wat

ts03

03Co

urie

r Num

ber (

Pow

er)

3030

630

308

G29

Data

**

*

A Ph

ase

VArs

0304

Cour

ier N

umbe

r (VA

r)30

309

3031

1G

29Da

ta*

**

B Ph

ase

VArs

0305

Cour

ier N

umbe

r (VA

r)30

312

3031

4G

29Da

ta*

**

C Ph

ase

VArs

0306

Cour

ier N

umbe

r (VA

r)30

315

3031

7G

29Da

ta*

**


Page 12 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

A Ph

ase

VA03

07Co

urie

r Num

ber (

VA)

3031

830

320

G29

Data

**

*

B Ph

ase

VA03

08Co

urie

r Num

ber (

VA)

3032

130

323

G29

Data

**

*

C Ph

ase

VA03

09Co

urie

r Num

ber (

VA)

3032

430

326

G29

Data

**

*

3 Ph

ase

Wat

ts03

0ACo

urie

r Num

ber (

Pow

er)

3032

730

329

G29

Data

**

*

3 Ph

ase

VArs

030B

Cour

ier N

umbe

r (VA

r)30

330

3033

2G

29Da

ta*

**

3 Ph

ase

VA03

0CCo

urie

r Num

ber (

VA)

3033

330

335

G29

Data

**

*

3Ph

Pow

er F

acto

r03

0ECo

urie

r Num

ber (

decim

al)

3033

9G

30Da

ta*

**

APh

Pow

er F

acto

r03

0FCo

urie

r Num

ber (

decim

al)

3034

0G

30Da

ta*

**

BPh

Pow

er F

acto

r03

10Co

urie

r Num

ber (

decim

al)

3034

1G

30Da

ta*

**

CPh

Pow

er F

acto

r03

11Co

urie

r Num

ber (

decim

al)

3034

2G

30Da

ta*

**

3Ph

WHo

urs F

wd

0312

Cour

ier N

umbe

r (W

h)30

343

3034

5G

29Da

ta*

**

3 Ph

ase

Wat

t - H

ours

(For

war

d)

3Ph

WHo

urs R

ev03

13Co

urie

r Num

ber (

Wh)

3034

630

348

G29

Data

**

*3

Phas

e W

atts

- Hou

rs (R

ever

se)

3Ph

VArH

ours

Fwd

0314

Cour

ier N

umbe

r (VA

rh)

3034

930

351

G29

Data

**

*3

Phas

e VA

r - H

ours

(For

war

d)

3Ph

VArH

ours

Rev

0315

Cour

ier N

umbe

r (VA

rh)

3035

230

354

G29

Data

**

*3

Phas

e VA

r - H

ours

(Rev

erse

)

3Ph

W F

ix D

eman

d03

16Co

urie

r Num

ber (

Pow

er)

3035

530

357

G29

Data

**

*3

Phas

e W

atts

- Fix

ed D

eman

d

3Ph

VArs

Fix

Dem

0317

Cour

ier N

umbe

r (Va

rs)30

358

3036

0G

29Da

ta*

**

3 Ph

ase

VArs

- Fix

ed D

eman

d

IA F

ixed

Dem

and

0318

Cour

ier N

umbe

r (Cu

rrent

)30

361

3036

2G

24Da

ta*

**

IB F

ixed

Dem

and

0319

Cour

ier N

umbe

r (Cu

rrent

)30

363

3036

4G

24Da

ta*

**

IC F

ixed

Dem

and

031A

Cour

ier N

umbe

r (Cu

rrent

)30

365

3036

6G

24Da

ta*

**

3 Ph

W R

oll D

em03

1BCo

urie

r Num

ber (

Pow

er)

3036

730

369

G29

Data

**

*3

Phas

e W

atts

- Rol

ling

Dem

and

3Ph

VArs

RollD

em03

1CCo

urie

r Num

ber (

VAr)

3037

030

372

G29

Data

**

*3

Phas

e VA

rs - R

ollin

g De

man

d

IA R

oll D

eman

d03

1DCo

urie

r Num

ber (

Curre

nt)

3037

330

374

G24

Data

**

*

IB R

oll D

eman

d03

1ECo

urie

r Num

ber (

Curre

nt)

3037

530

376

G24

Data

**

*

IC R

oll D

eman

d03

1FCo

urie

r Num

ber (

Curre

nt)

3037

730

378

G24

Data

**

*

3Ph

W P

eak

Dem

0320

Cour

ier N

umbe

r (Po

wer

)30

379

3038

1G

29Da

ta*

**

3 Ph

ase

Wat

ts - P

eak

Dem

and

3Ph

VAr P

eak

Dem

0321

Cour

ier N

umbe

r (VA

r)30

382

3038

4G

29Da

ta*

**

3 Ph

ase

VArs

- Pea

k De

man

d


Page 13 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

IA P

eak

Dem

and

0322

Cour

ier N

umbe

r (Cu

rrent

)30

385

3038

6G

24Da

ta*

**

IB P

eak

Dem

and

0323

Cour

ier N

umbe

r (Cu

rrent

)30

387

3038

8G

24Da

ta*

**

IC P

eak

Dem

and

0324

Cour

ier N

umbe

r (Cu

rrent

)30

389

3039

0G

24Da

ta*

**

Rese

t Dem

and

0325

Inde

xed

Strin

gG

1140

103

G11

No

Com

man

d0

11

1*

**

MEA

SURE

MEN

TS 3

0400

**

IA-2

Mag

nitu

de04

01Co

urie

r Num

ber (

Curre

nt)

3040

030

401

G24

Data

*

IA-2

Pha

se A

ngle

0402

Cour

ier N

umbe

r (An

gle)

3040

2G

30Da

ta*

IB-2

Mag

nitu

de04

03Co

urie

r Num

ber (

Curre

nt)

3040

330

404

G24

Data

*

IB-2

Pha

se A

ngle

0404

Cour

ier N

umbe

r (An

gle)

3040

5G

30Da

ta*

IC-2

Mag

nitu

de04

05Co

urie

r Num

ber (

Curre

nt)

3040

630

407

G24

Data

*

IC-2

Pha

se A

ngle

0406

Cour

ier N

umbe

r (An

gle)

3040

8G

30Da

ta*

IA D

iffer

entia

l04

07Co

urie

r Num

ber (

Curre

nt)

3040

930

410

G24

Data

*(0

90B=

1) &

& (X

001

= 1)

IB D

iffer

entia

l04

08Co

urie

r Num

ber (

Curre

nt)

3041

130

412

G24

Data

*(0

90B=

1) &

& (X

001

= 1)

IC D

iffer

entia

l04

09Co

urie

r Num

ber (

Curre

nt)

3041

330

414

G24

Data

*(0

90B=

1) &

& (X

001

= 1)

IA B

ias

040A

Cour

ier N

umbe

r (Cu

rrent

)30

415

3041

6G

24Da

ta*

IB B

ias

040B

Cour

ier N

umbe

r (Cu

rrent

)30

417

3041

8G

24Da

ta*

IC B

ias

040C

Cour

ier N

umbe

r (Cu

rrent

)30

419

3042

0G

24Da

ta*

IREF

Diff

040D

Cour

ier N

umbe

r (Cu

rrent

)30

421

3042

2G

24Da

ta*

*(0

915=

1) &

& (X

A01

>= 3

)

IREF

Bia

s04

0ECo

urie

r Num

ber (

Curre

nt)

3042

330

424

G24

Data

**

(091

5=1)

&&

(XA0

1 >=

3)

VN 3

rd H

arm

onic

040F

Cour

ier N

umbe

r (Vo

ltage

)30

425

3042

6G

24Da

ta*

Roto

r The

rmal

0410

Cour

ier N

umbe

r (Pe

rcen

tage

)30

427

G1

Data

**

(090

E=1)

&&

(X30

4 =

1)

Rese

t The

rmal

0411

Inde

xed

Strin

gG

1140

104

G11

No

Com

man

d0

11

1*

*(0

90E=

1) &

& (X

304

= 1)

RTD

104

12Co

urie

r Num

ber (

Tem

pera

ture

)30

428

G10

Data

**

RTD

204

13Co

urie

r Num

ber (

Tem

pera

ture

)30

429

G10

Data

**

RTD

304

14Co

urie

r Num

ber (

Tem

pera

ture

)30

430

G10

Data

**

RTD

404

15Co

urie

r Num

ber (

Tem

pera

ture

)30

431

G10

Data

**


Page 14 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

RTD

504

16Co

urie

r Num

ber (

Tem

pera

ture

)30

432

G10

Data

**

RTD

604

17Co

urie

r Num

ber (

Tem

pera

ture

)30

433

G10

Data

**

RTD

704

18Co

urie

r Num

ber (

Tem

pera

ture

)30

434

G10

Data

**

RTD

804

19Co

urie

r Num

ber (

Tem

pera

ture

)30

435

G10

Data

**

RTD

904

1ACo

urie

r Num

ber (

Tem

pera

ture

)30

436

G10

Data

**

RTD

1004

1BCo

urie

r Num

ber (

Tem

pera

ture

)30

437

G10

Data

**

RTD

Ope

n Cc

t04

1CBi

nary

Fla

g (1

0 bi

ts)G

108

3043

8G

108

Data

**

RTD

Shor

t Cct

041D

Bina

ry F

lag

(10

bits)

G10

930

439

G10

9Da

ta*

*

RTD

data

erro

r04

1EBi

nary

Fla

g (1

0 bi

ts)G

110

3044

0G

110

Data

**

Rese

t RTD

flag

s04

1FIn

dexe

d str

ing

G11

4010

5G

11‘

No

Com

man

d0

11

1*

*

CB C

ON

DITIO

N06

00*

**

CB C

ON

DITIO

N M

ON

ITORI

NG

CB O

pera

tions

0601

Unsig

ned

Inte

ger

3060

0G

1Da

ta*

**

Num

ber o

f Circ

uit B

reak

er O

pera

tions

Tota

l IA

Brok

en06

02Co

urie

r Num

ber (

curre

nt)

3060

130

602

G24

Data

**

*Br

oken

Cur

rent

A P

hase

Tota

l IB

Brok

en06

03Co

urie

r Num

ber (

curre

nt)

3060

330

604

G24

Data

**

*Br

oken

Cur

rent

B P

hase

Tota

l IC

Brok

en06

04Co

urie

r Num

ber (

curre

nt)

3060

530

606

G24

Data

**

*Br

oken

Cur

rent

C P

hase

CB O

pera

te T

ime

0605

Cour

ier N

umbe

r (tim

e)30

607

G25

Data

**

*Ci

rcui

t Bre

aker

ope

ratin

g tim

e

Rese

t CB

Data

0606

Inde

xed

Strin

gG

1140

150

G11

No

Com

man

d0

11

1*

**

Rese

t All

Value

s

CB C

ON

TRO

L07

00*

**

CB C

ontro

l by

0701

Inde

xed

Strin

gG

9940

200

G99

Disa

bled

Setti

ng0

71

2*

Clos

e Pu

lse T

ime

0702

Cour

ier N

umbe

r (Tim

e)40

201

G2

0.5

Setti

ng0.

110

0.01

2*

Trip

Puls

e Tim

e07

03Co

urie

r Num

ber (

Time)

4020

2G

20.

5Se

tting

0.1

50.

012

*

Man

Clo

se D

elay

0705

Cour

ier N

umbe

r (Tim

e)40

203

G2

10Se

tting

0.01

600

0.01

2*

Man

ual C

lose

Del

ay

CB H

ealth

y Tim

e07

06Co

urie

r Num

ber (

Time)

4020

440

205

G35

5Se

tting

0.01

9999

0.01

2*

Lock

out R

eset

0708

Inde

xed

Strin

gG

1140

206

G11

No

Com

man

d0

11

2*

**

Rese

t Loc

kout

by

0709

Inde

xed

Strin

gG

8140

207

G81

CB C

lose

Setti

ng0

11

2*

**

Man

Clo

se R

stDly

070A

Cour

ier N

umbe

r (Tim

e)40

208

G2

5Se

tting

0.01

600

0.01

2*

**

Man

ual C

lose

Res

et D

elay


Page 15 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

CB S

tatu

s Inp

ut07

11In

dexe

d St

ring

4020

9G

118

Non

eSe

tting

03

12

**

*

DATE

AN

D TIM

E08

00*

**

Date

/Tim

eN

/A08

01IE

C870

Tim

e &

Date

4030

040

303

G12

Setti

ng0

**

*

Date

N/A

**

*Fr

ont P

anel

Men

u on

ly12

-Jan-9

8

Time

N/A

**

*Fr

ont P

anel

Men

u on

ly12

:00

IRIG

-B S

ync

0804

Inde

xed

Strin

gG

3740

304

G37

Disa

bled

Setti

ng0

11

2*

**

IRIG

-B S

tatu

s08

05In

dexe

d St

ring

G17

3009

0G

17Da

ta*

**

Batte

ry S

tatu

s08

06In

dexe

d St

ring

G59

3009

1G

59Da

ta*

**

Batte

ry A

larm

0807

Inde

xed

Strin

gG

3740

305

G37

Enab

led

Setti

ng0

11

2*

**

CON

FIGUR

ATIO

N09

00*

**

Resto

re D

efau

lts09

01In

dexe

d St

ring

G53

4040

2G

53N

o O

pera

tion

Com

man

d0

51

2*

**

Setti

ng G

roup

0902

Inde

xed

Strin

gG

6140

403

G61

Men

uSe

tting

01

12

**

*

Activ

e Se

tting

s09

03In

dexe

d St

ring

G90

4040

4G

901

Setti

ng0

31

1*

**

Save

Cha

nges

0904

Inde

xed

Strin

gG

6240

405

G62

No

Ope

ratio

nCo

mm

and

02

12

**

*

Copy

Fro

m09

05In

dexe

d St

ring

G90

4040

6G

90G

roup

1Se

tting

03

12

**

*

Copy

To09

06In

dexe

d St

ring

G98

4040

7G

98N

o O

pera

tion

Com

man

d0

31

2*

**

Setti

ng G

roup

109

07In

dexe

d St

ring

G37

4040

8G

37En

able

dSe

tting

01

12

**

*

Setti

ng G

roup

209

08In

dexe

d St

ring

G37

4040

9G

37Di

sabl

edSe

tting

01

12

**

*

Setti

ng G

roup

309

09In

dexe

d St

ring

G37

4041

0G

37Di

sbal

edSe

tting

01

12

**

*

Setti

ng G

roup

409

0AIn

dexe

d St

ring

G37

4041

1G

37Di

sabl

edSe

tting

01

12

**

*

Gen

Diff

eren

tial

090B

Inde

xed

Strin

gG

3740

412

Enab

led

Setti

ng0

11

2*

Pow

er09

0CIn

dexe

d St

ring

G37

4041

3En

able

dSe

tting

01

12

**

*

Fiel

d Fa

ilure

090D

Inde

xed

Strin

gG

3740

414

Enab

led

Setti

ng0

11

2*

*

NPS

The

rmal

090E

Inde

xed

Strin

gG

3740

415

Enab

led

Setti

ng0

11

2*

*

Syste

m B

acku

p09

0FIn

dexe

d St

ring

G37

4041

6En

able

dSe

tting

01

12

**


Page 16 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Ove

rcur

rent

0910

Inde

xed

Strin

gG

3740

417

Enab

led

Setti

ng0

11

2*

**

Earth

Fau

lt09

13In

dexe

d St

ring

G37

4041

8En

able

dSe

tting

01

12

**

*

SEF/

REF

Prot

’n09

15In

dexe

d St

ring

G37

4041

9Di

sabl

edSe

tting

01

12

*En

able

d*

*

Resid

ual O

/V N

VD09

16In

dexe

d St

ring

G37

4042

0En

able

dSe

tting

01

12

**

*Re

sidua

l Ove

rvol

tage

100%

Sta

tor E

F09

17In

dexe

d St

ring

G37

4042

1Di

sabl

edSe

tting

01

12

*

V/Hz

0918

Inde

xed

Strin

gG

3740

422

Disa

bled

Setti

ng0

11

2*

*

df/d

t09

19In

dexe

d St

ring

G37

4042

3En

able

dSe

tting

01

12

*

V Ve

ctor S

hift

091A

Inde

xed

Strin

gG

3740

424

Disa

bled

Setti

ng0

11

2*

Dead

Mac

hine

091B

Inde

xed

Strin

gG

3740

425

Disa

bled

Setti

ng0

11

2*

Reco

nnec

t Del

ay09

1CIn

dexe

d St

ring

G37

4042

6Di

sabl

edSe

tting

01

12

*

Volt

Prot

ectio

n09

1DIn

dexe

d St

ring

G37

4042

7En

able

dSe

tting

01

12

**

*

Freq

Pro

tecti

on09

1EIn

dexe

d St

ring

G37

4042

8En

able

dSe

tting

01

12

**

*

RTD

Inpu

ts09

1FIn

dexe

d St

ring

G37

4042

9En

able

dSe

tting

01

12

**

CB F

ail

0920

Inde

xed

Strin

gG

3740

430

Disa

bled

Setti

ng0

11

2*

**

Supe

rvisi

on09

21In

dexe

d St

ring

G37

4043

1Di

sabl

edSe

tting

01

12

**

*

Inpu

t Lab

els

0925

Inde

xed

Strin

gG

80Vi

sible

Setti

ng0

11

1*

**

Out

put L

abel

s09

26In

dexe

d St

ring

G80

Visib

leSe

tting

01

11

**

*

RTD

Labe

ls09

27In

dexe

d St

ring

G80

Visib

leSe

tting

01

11

**

CT &

VT

Ratio

s09

28In

dexe

d St

ring

G80

Visib

leSe

tting

01

11

**

*

Reco

rder

Con

trol

0929

Inde

xed

Strin

gG

80In

visib

leSe

tting

01

11

**

*

Distu

rb R

ecor

der

092A

Inde

xed

Strin

gG

80In

visib

leSe

tting

01

11

**

*Di

sturb

ance

reco

rder

Mea

sure

’t Se

tup

092B

Inde

xed

Strin

gG

80In

visib

leSe

tting

01

11

**

*

Com

ms S

ettin

gs09

2CIn

dexe

d St

ring

G80

Visib

leSe

tting

01

11

**

*

Com

miss

ion

Tests

092D

Inde

xed

Strin

gG

80Vi

sible

Setti

ng0

11

1*

**

Setti

ng V

alue

s09

2EIn

dexe

d St

ring

G54

Prim

ary

Setti

ng0

11

1*

**

4040

0G

18*

**

Reco

rd se

lecti

on c

omm

and

regi

ster

4040

1G

6*

**

Reco

rd c

ontro

l com

man

d re

giste

r


Page 17 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

CT A

ND

VT R

ATIO

S0A

00*

**

value

s for

mult

iplie

r see

mult

colum

n

Mai

n VT

Prim

ary

0A01

Cour

ier N

umbe

r (Vo

ltage

)40

500

4050

1G

3511

0Se

tting

100

1000

000

12

**

*La

bel V

1=M

ain

VT R

atin

g/11

0

Mai

n VT

Sec

’y0A

02Co

urie

r Num

ber (

Volta

ge)

4050

2G

211

0Se

tting

80*V

114

0*V1

1*V1

2*

**

Labe

l M1=

0A01

/0A0

2

NVD

VT

Prim

ary

0A05

Cour

ier N

umbe

r (Vo

ltage

)40

506

4050

7G

3511

0Se

tting

100

1000

000

12

**

*N

eutra

l Disp

lace

men

t VT

Prim

ary

Labe

l V3=

Neu

tral D

isp V

T Ra

ting/

110

NVD

VT

Seco

ndar

y0A

06Co

urie

r Num

ber (

Volta

ge)

4050

8G

211

0Se

tting

80*V

314

0*V3

1*V3

2*

**

Neu

tral D

ispla

cem

ent V

T Se

cond

ary

Labe

l M3=

0A05

/0A0

6

Phas

e CT

Prim

ary

0A07

Cour

ier N

umbe

r (Cu

rrent

)40

509

G2

1Se

tting

130

000

12

**

*I1

=Pha

se C

T se

cond

ary

ratin

g

Phas

e CT

Sec

’y0A

08Co

urie

r Num

ber (

Curre

nt)

4051

0G

21

Setti

ng1

54

2*

**

Labe

l M4=

0A07

/0A0

8

E/F

CT P

rimar

y0A

09Co

urie

r Num

ber (

Curre

nt)

4051

1G

21

Setti

ng1

3000

01

2*

*La

bel I

2=E/

F CT

seco

ndar

y ra

ting

E/F

CT S

econ

dary

0A0A

Cour

ier N

umbe

r (Cu

rrent

)40

512

G2

1Se

tting

15

42

**

Labe

l M5=

0A09

/0A0

A

SEF

CT P

rimar

y0A

0BCo

urie

r Num

ber (

Curre

nt)

4051

3G

21

Setti

ng1

3000

01

2*

**

Labe

l I3=

SEF

CT se

cond

ary

ratin

g

SEF

CT S

econ

dary

0A0C

Cour

ier N

umbe

r (Cu

rrent

)40

514

G2

1Se

tting

15

42

**

*La

bel M

6=0A

0B/0

A0C

RECO

RD C

ON

TRO

L0B

00*

**

Clea

r Eve

nts

0B01

Inde

xed

Strin

gG

11N

oCo

mm

and

01

11

**

*

Clea

r Fau

lts0B

02In

dexe

d St

ring

G11

No

Com

man

d0

11

1*

**

Clea

r Mai

nt0B

03In

dexe

d St

ring

G11

No

Com

man

d0

11

1*

**

DIST

URB

RECO

RDER

0C00

**

*DI

STUR

BAN

CE R

ECO

RDER

Dura

tion

0C01

Cour

ier N

umbe

r (Tim

e)40

600

G2

1.5

Setti

ng0.

110

.50.

012

**

*

Trig

ger P

ositi

on0C

02Co

urie

r Num

ber (

%)

4060

1G

233

.3Se

tting

010

00.

12

**

*

Trig

ger M

ode

0C03

Inde

xed

Strin

gG

3440

602

G34

Sing

le0

11

2*

**

Anal

og C

hann

el 1

0C04

Inde

xed

Strin

gG

3140

603

G31

VAN

Setti

ng0

**1

2*

**

“**

Max

= 7

for M

odel

1,

8

for M

odel

2,

1

1 fo

r Mod

el 3


Page 18 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Anal

og C

hann

el 2

0C05

Inde

xed

Strin

gG

3140

604

G31

VBN

Setti

ng0

**1

2*

**

“**

Max

= 7

for M

odel

1,

8

for M

odel

2,

1

1 fo

r Mod

el 3

Anal

og C

hann

el 3

0C06

Inde

xed

Strin

gG

3140

605

G31

VCN

Setti

ng0

**1

2*

**

“**

Max

= 7

for M

odel

1,

8 fo

r Mod

el2,

11

for M

odel

3

Anal

og C

hann

el 4

0C07

Inde

xed

Strin

gG

3140

606

G31

VNSe

tting

0**

12

**

*“*

* M

ax =

7 fo

r Mod

el1,

8

for M

odel

2,

11

for M

odel

3

Anal

og C

hann

el 5

0C08

Inde

xed

Strin

gG

3140

607

G31

IASe

tting

0**

12

**

*“*

* M

ax =

7 fo

r Mod

el1,

8

for M

odel

2,

11

for M

odel

3

Anal

og C

hann

el 6

0C09

Inde

xed

Strin

gG

3140

608

G31

IBSe

tting

0**

12

**

*“*

* M

ax =

7 fo

r Mod

el1,

8

for M

odel

2,

11

for M

odel

3

Anal

og C

hann

el 7

0C0A

Inde

xed

Strin

gG

3140

609

G31

ICSe

tting

0**

12

**

*“*

* M

ax =

7 fo

r Mod

el1,

8

for M

odel

2,

11 fo

r Mod

el3

Anal

og C

hann

el 8

0C0B

Inde

xed

Strin

gG

3140

610

G31

IN S

EFSe

tting

0**

12

**

*“*

* M

ax =

7 fo

r Mod

el1,

8

for M

odel

2.

11

for M

odel

3

Digi

tal I

nput

10C

0CIn

dexe

d St

ring

G32

4061

1G

32Re

lay

1Se

tting

0Se

e N

ote

12

**

*N

ote:

Num

ber o

f sig

nals

is m

odel

depe

nden

t

Inpu

t 1 T

rigge

r0C

0DIn

dexe

d St

ring

G66

4061

2G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

20C

0EIn

dexe

d St

ring

G32

4061

3G

32Re

lay

2Se

tting

0Se

e N

ote

12

**

*

Inpu

t 2 T

rigge

r0C

0FIn

dexe

d St

ring

G66

4061

4G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

30C

10In

dexe

d St

ring

G32

4061

5G

32Re

lay

3Se

tting

0Se

e N

ote

12

**

*

Inpu

t 3 T

rigge

r0C

11In

dexe

d St

ring

G66

4061

6G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

40C

12In

dexe

d St

ring

G32

4061

7G

32Re

lay

4Se

tting

0Se

e N

ote

12

**

*

Inpu

t 4 T

rigge

r0C

13In

dexe

d St

ring

G66

4061

8G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

50C

14In

dexe

d St

ring

G32

4061

9G

32Re

lay

5Se

tting

0Se

e N

ote

12

**

*

Inpu

t 5 T

rigge

r0C

15In

dexe

d St

ring

G66

4062

0G

66N

o Tr

igge

rSe

tting

02

12

**

*


Page 19 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Digi

tal I

nput

60C

16In

dexe

d St

ring

G32

4062

1G

32Re

lay

6Se

tting

0Se

e N

ote

12

**

*

Inpu

t 6 T

rigge

r0C

17In

dexe

d St

ring

G66

4062

2G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

70C

18In

dexe

d St

ring

G32

4062

3G

32Re

lay

7Se

tting

0Se

e N

ote

12

**

*

Inpu

t 7 T

rigge

r0C

19In

dexe

d St

ring

G66

4062

4G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

80C

1AIn

dexe

d St

ring

G32

4062

5G

32O

pto

Inpu

t 1Se

tting

0Se

e N

ote

12

**

Rela

y 8

*

Inpu

t 8 T

rigge

r0C

1BIn

dexe

d St

ring

G66

4062

6G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

90C

1CIn

dexe

d St

ring

G32

4062

7G

32O

pto

Inpu

t 2Se

tting

0Se

e N

ote

12

**

Rela

y 9

*

Inpu

t 9 T

rigge

r0C

1DIn

dexe

d St

ring

G66

4062

8G

66N

o Tr

igge

rSe

tting

02

12

**

*

Digi

tal I

nput

10

0C1E

Inde

xed

Strin

gG

3240

629

G32

Opt

o In

put 3

Setti

ng0

See

Not

e1

2*

*Re

lay

10*

Inpu

t 10

Trig

ger

0C1F

Inde

xed

Strin

gG

6640

630

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

11

0C20

Inde

xed

Strin

gG

3240

631

G32

Opt

o In

put 4

Setti

ng0

See

Not

e1

2*

*Re

lay

11*

Inpu

t 11

Trig

ger

0C21

Inde

xed

Strin

gG

6640

632

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

12

0C22

Inde

xed

Strin

gG

3240

633

G32

Opt

o In

put 5

Setti

ng0

See

Not

e1

2*

*Re

lay

12*

Inpu

t 12

Trig

ger

0C23

Inde

xed

Strin

gG

6640

634

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

13

0C24

Inde

xed

Strin

gG

3240

635

G32

Opt

o In

put 6

Setti

ng0

See

Not

e1

2*

*Re

lay

13*

Inpu

t 13

Trig

ger

0C25

Inde

xed

Strin

gG

6640

636

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

14

0C26

Inde

xed

Strin

gG

3240

637

G32

Opt

o In

put 7

Setti

ng0

See

Not

e1

2*

*Re

lay

14*

Inpu

t 14

Trig

ger

0C27

Inde

xed

Strin

gG

6640

638

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

15

0C28

Inde

xed

Strin

gG

3240

639

G32

Opt

o In

put 8

Setti

ng0

See

Not

e1

2*

*O

pto

Inpu

t 1*

Inpu

t 15

Trig

ger

0C29

Inde

xed

Strin

gG

6640

640

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

16

0C2A

Inde

xed

Strin

gG

3240

641

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 2

*


Page 20 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Inpu

t 16

Trig

ger

0C2B

Inde

xed

Strin

gG

6640

642

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

17

0C2C

Inde

xed

Strin

gG

3240

643

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 3

*

Inpu

t 17

Trig

ger

0C2D

Inde

xed

Strin

gG

6640

644

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

18

0C2E

Inde

xed

Strin

gG

3240

645

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 4

*

Inpu

t 18

Trig

ger

0C2F

Inde

xed

Strin

gG

6640

646

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

19

0C30

Inde

xed

Strin

gG

3240

647

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 5

*

Inpu

t 19

Trig

ger

0C31

Inde

xed

Strin

gG

6640

648

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

20

0C32

Inde

xed

Strin

gG

3240

649

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 6

*

Inpu

t 20

Trig

ger

0C33

Inde

xed

Strin

gG

6640

650

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

21

0C34

Inde

xed

Strin

gG

3240

651

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 7

*

Inpu

t 21

Trig

ger

0C35

Inde

xed

Strin

gG

6640

652

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

22

0C36

Inde

xed

Strin

gG

3240

653

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 8

*

Inpu

t 22

Trig

ger

0C37

Inde

xed

Strin

gG

6640

654

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

23

0C38

Inde

xed

Strin

gG

3240

655

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 9

*

Inpu

t 23

Trig

ger

0C39

Inde

xed

Strin

gG

6640

656

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

24

0C3A

Inde

xed

Strin

gG

3240

657

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 1

0*

Inpu

t 24

Trig

ger

0C3B

Inde

xed

Strin

gG

6640

658

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

25

0C3C

Inde

xed

Strin

gG

3240

659

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 1

1*

Inpu

t 25

Trig

ger

0C3D

Inde

xed

Strin

gG

6640

660

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

26

0C3E

Inde

xed

Strin

gG

3240

661

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 1

2*


Page 21 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Inpu

t 26

Trig

ger

0C3F

Inde

xed

Strin

gG

6640

662

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

27

0C40

Inde

xed

Strin

gG

3240

663

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 1

3*

Inpu

t 27

Trig

ger

0C41

Inde

xed

Strin

gG

6640

664

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

28

0C42

Inde

xed

Strin

gG

3240

665

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 1

4*

Inpu

t 28

Trig

ger

0C43

Inde

xed

Strin

gG

6640

666

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

29

0C44

Inde

xed

Strin

gG

3240

667

G32

Not

Use

dSe

tting

0Se

e N

ote

12

**

Opt

o In

put 1

5*

Inpu

t 29

Trig

ger

0C45

Inde

xed

Strin

gG

6640

668

G66

No

Trig

ger

Setti

ng0

21

2*

**

Digi

tal I

nput

30

0C46

Inde

xed

Strin

gG

3240

669

G32

Not

Use

dSe

tting

0Se

e N

ote

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Opt

o In

put 1

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t 30

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Digi

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32

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Use

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e N

ote

12

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*

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MEA

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EASU

REM

ENT

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ING

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12

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utes

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Page 22 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

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odel

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men

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lRo

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ta ty

peSt

rings

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dDa

tagr

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d St

ring

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ier

Data

**

*

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ote

Addr

ess

0E02

255

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255

11

**

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ild =

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r IEC

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103

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ned

inte

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its)

247

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247

12

**

*Bu

ild =

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bus

Inac

tivity

Tim

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03Co

urie

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ber (

Time-m

inut

es)

15Se

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130

12

**

*

Baud

Rat

e0E

04In

dexe

d St

ring

G38

9600

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01

12

**

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ild =

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03

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253

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*

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o I/

P St

atus

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11

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fault

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ger

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11

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11

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4085

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fault

LED

8


Page 23 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

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42P3

43

Test

Mod

e0F

0DIn

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d St

ring

G37

4085

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37Di

sabl

edSe

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01

12

**

*

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Patte

rn0F

0EBi

nary

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g (2

1bits

)G

940

859

4086

0G

90

Setti

ng0

201

2*

**

Inde

xed

Strin

g

Cont

act T

est

0F0F

Inde

xed

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gG

9340

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G93

No

Ope

ratio

nCo

mm

and

02

12

**

*

Test

LEDs

0F10

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(8bi

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9440

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No

Ope

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mm

and

01

12

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DDB

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**

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**

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736

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**

*

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224

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lag(

32)

3073

730

738

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**

*

DDB

256

- 287

N/A

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Bina

ry F

lag(

32)

3073

930

740

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**

*

DDB

288

- 319

N/A

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Bina

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lag(

32)

3074

130

742

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**

*

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320

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744

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**

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32)

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**

*

DDB

384

- 415

N/A

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lag(

32)

3074

730

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**

*

DDB

416

- 447

N/A

0F2D

Bina

ry F

lag(

32)

3074

930

750

G27

Data

**

*

DDB

448

- 479

N/A

0F2E

Bina

ry F

lag(

32)

3075

130

752

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Data

**

*

DDB

480

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0F2F

Bina

ry F

lag(

32)

3075

330

754

G27

Data

**

*N

/ABi

nary

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g(16

)30

701

G1

Data

**

*Re

lay

Stat

us (r

epea

t of C

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N/A

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ier N

umbe

r (cu

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IA M

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IC M

agni

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)30

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VAB

Mag

nitu

deN

/ACo

urie

r Num

ber (

volta

ge)

3071

030

711

G24

Data

**

*VB

C M

agni

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N/A

Cour

ier N

umbe

r (vo

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Mag

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3 Ph

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N/A

Cour

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)30

720

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**

*3

Phas

e Po

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N/A

Cour

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umbe

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Freq

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Rela

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st Po

rt St

atus


Page 24 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

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41P3

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43

CB M

ON

ITOR

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aint

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4015

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arm

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bled

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11

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Brok

en C

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nt m

aint

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ce a

larm

I^ M

aint

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03Co

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ber (

Curre

nt)

4015

340

154

G35

1000

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M1

2500

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640

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NM

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No.

CB

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07Un

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d In

tege

r40

159

G1

10Se

tting

110

000

12

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ance

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No.

CB

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Strin

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160

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4016

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01

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CB T

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ting

Time

mai

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CB T

ime

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umbe

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e


Page 25 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

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Type

Min

Max

Step

Pass

wor

dM

odel

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men

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lRo

wDa

ta ty

peSt

rings

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tagr

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43

GRO

UP 1

3000

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DIFF

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101

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Page 26 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

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men

tCo

lRo

wDa

ta ty

peSt

rings

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tagr

oup

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led

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FIELD

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Page 27 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

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men

tCo

lRo

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peSt

rings

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oup

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Page 28 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

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Type

Min

Max

Step

Pass

wor

dM

odel

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men

tCo

lRo

wDa

ta ty

peSt

rings

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tagr

oup

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)41

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Page 29 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

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ting

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Type

Min

Max

Step

Pass

wor

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odel

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men

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wDa

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rings

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rent

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Cour

ier N

umbe

r (Cu

rrent

)41

422

G2

0.5

Setti

ng0.

08* I

132

*I1

0.01

* I1

2*

IN>4

Tim

e De

lay

3819

Cour

ier N

umbe

r (Tim

e)41

423

G2

0Se

tting

020

00.

012

*

IN>

Func

Link

381A

Bina

ry F

lags

G63

4142

4G

6315

Setti

ng15

41

2*


Page 30 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

IN>

DIRE

CTIO

NAL

381B

(Sub

Hea

ding

)2

*

IN>

Char

Ang

le38

1CCo

urie

r Num

ber(A

ngle

)41

425

G2

-60

Setti

ng-9

595

12

*

IN>

Pol

381D

Inde

xed

Strin

gG

4641

426

G46

Zero

Seq

uenc

eSe

tting

01

12

*

IN>

VNpo

l Inp

ut38

1EIn

dexe

d St

ring

G49

4142

7G

49M

easu

red

Setti

ng0

11

2*

IN>

VNpo

l Set

381F

Cour

ier N

umbe

r (Vo

ltage

)41

428

G2

5Se

tting

0.5*

V122

*V1

0.5*

V12

*V1

app

lied

for V

N se

t to

derv

ied.

IN>

V2po

l Set

3820

Cour

ier N

umbe

r (Vo

ltage

)41

429

G2

5Se

tting

0.5*

V125

*V1

0.5*

V12

*

IN>

I2po

l Set

3821

Cour

ier N

umbe

r (Cu

rrent

)41

430

G2

0.08

Setti

ng0.

08* I

11*

I10.

01*I

12

*

GRO

UP 1

3A00

**

*

SEF/

REF

PRO

T’N

SEF/

REF

Opt

ions

3A01

Inde

xed

Strin

gG

5841

500

G58

SEF

Setti

ng0

21

2*

05

12

**

ISEF

>1 F

uncti

on3A

02In

dexe

d St

ring

G43

4150

1G

43DT

Setti

ng0

101

2*

G10

5G

105

01

1*

*

ISEF

>1 D

irecti

on3A

03In

dexe

d St

ring

G44

4150

2G

44N

on-D

irecti

onal

Setti

ng0

21

2*

**

ISEF>

1 Cu

rrent

3A04

Cour

ier N

umbe

r (Cu

rrent)

4150

3G

20.

05Se

tting

0.00

5*I3

0.1*

I30.

0002

5*I3

2*

**

ISEF

>1 D

elay

3A05

Cour

ier N

umbe

r (Tim

e)41

504

G2

1Se

tting

020

00.

012

**

*

ISEF

>1 T

MS

3A06

Cour

ier N

umbe

r (De

cimal

)41

505

G2

1Se

tting

0.02

51.

20.

025

2*

ISEF

>1 T

ime

Dial

3A07

Cour

ier N

umbe

r (De

cimal

)41

506

G2

7Se

tting

0.5

150.

12

*

ISEF

>1 R

eset

Chr

3A08

Inde

xed

Strin

gG

6041

507

G60

DTSe

tting

01

12

*

ISEF

>1 tR

ESET

3A09

Cour

ier N

umbe

r (Tim

e)41

508

G2

0Se

tting

010

00.

012

*

ISEF

>2 F

uncti

on3A

0AIn

dexe

d St

ring

G43

4150

9G

43Di

sabl

edSe

tting

010

12

*

ISEF

>2 D

irecti

on3A

0BIn

dexe

d St

ring

G44

4151

0G

44N

on-D

irecti

onal

Setti

ng0

21

2*

ISEF

>2 C

urre

nt3A

0CCo

urie

r Num

ber (

Curre

nt)

4151

1G

20.

05Se

tting

0.00

5*I3

0.1*

I30.

0002

5*I3

2*

ISEF

>2 D

elay

3A0D

Cour

ier N

umbe

r (Tim

e)41

512

G2

1Se

tting

020

00.

012

*

ISEF

>2 T

MS

3A0E

Cour

ier N

umbe

r (De

cimal

)41

513

G2

1Se

tting

0.02

51.

20.

025

2*

ISEF

>2 T

ime

Dial

3A0F

Cour

ier N

umbe

r (De

cimal

)41

514

G2

7Se

tting

0.5

150.

12

*

ISEF

>2 R

eset

Chr

3A10

Inde

xed

Strin

gG

6041

515

G60

DTSe

tting

01

12

*


Page 31 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

ISEF

>2 tR

ESET

3A11

Cour

ier N

umbe

r (Tim

e)41

516

G2

0Se

tting

010

00.

012

*

ISEF

>3 S

tatu

s3A

12In

dexe

d St

ring

G37

4151

7G

37Di

sabl

edSe

tting

01

12

*

ISEF

>3 D

irecti

on3A

13In

dexe

d St

ring

G44

4151

8G

44N

on-D

irecti

onal

Setti

ng0

21

2*

ISEF

>3 C

urre

nt3A

14Co

urie

r Num

ber (

Curre

nt)

4151

9G

20.

4Se

tting

0.00

5*I3

0.8*

I30.

001*

I32

*

ISEF

>3 D

elay

3A15

Cour

ier N

umbe

r (Tim

e)41

520

G2

0.5

Setti

ng0

200

0.01

2*

ISEF

>4 S

tatu

s3A

16In

dexe

d St

ring

G37

4152

1G

37Di

sabl

edSe

tting

01

12

*

ISEF

>4 D

irecti

on3A

17In

dexe

d St

ring

G44

4152

2G

44N

on-D

irecti

onal

Setti

ng0

21

2*

ISEF

>4 C

urre

nt3A

18Co

urie

r Num

ber (

Curre

nt)

4152

3G

20.

6Se

tting

0.00

5*I3

0.8*

I30.

001*

I32

*

ISEF

>4 D

elay

3A19

Cour

ier N

umbe

r (Tim

e)41

524

G2

0.25

Setti

ng0

200

0.01

2*

ISEF

> Fu

nc Li

nk3A

1ABi

nary

Fla

gsG

6441

525

G64

15Se

tting

154

12

*1

11

2*

*

ISEF

DIR

ECTIO

NAL

3A1B

(Sub

Hea

ding

)2

**

*

ISEF

> Ch

ar A

ngle

3A1C

Cour

ier N

umbe

r(Ang

le)

4152

6G

290

Setti

ng-9

595

12

**

*

ISEF

>VN

pol I

nput

3A1D

Inde

xed

Strin

gG

4941

527

G49

Mea

sure

dSe

tting

01

12

**

*

ISEF

> VN

pol S

et3A

1ECo

urie

r Num

ber (

Volta

ge)

4152

8G

25

Setti

ng0.

5*V1

22*V

10.

5*V1

2*

**

V1 a

pplie

d w

hen

VN se

t to

derv

ied.

0.5*

V322

*V3

0.5*

V3*

**

V3 a

pplie

d w

hen

VN se

t to

mea

sure

d

WAT

TMET

RIC

SEF

3A1F

(Sub

Hea

ding

)*

**

PN>

Setti

ng3A

20Co

urie

r Num

ber (

Pow

er)

4152

9G

29

Setti

ng0.

0*V1

*I3

20*V

1*I3

0.05

*V1*

I32

**

*V1

app

lied

whe

n VN

set t

o de

rvie

d.0.

0*V3

*I3

20*V

3*I3

0.05

*V3*

I3*

**

V3 a

pplie

d w

hen

VN se

t to

mea

sure

d

REST

RICT

ED E

/F3A

21(S

ub H

eadi

ng)

**

*

IREF

> k1

3A22

Cour

ier N

umbe

r (Pe

rcen

tage

)41

530

G2

20Se

tting

020

12

**

IREF

> k2

3A23

Cour

ier N

umbe

r (Pe

rcen

tage

)41

531

G2

150

Setti

ng0

150

12

**

IREF

> Is

13A

24Co

urie

r Num

ber (

Curre

nt)

4153

2G

20.

2Se

tting

0.05

* I1

1.0*

I10.

01* I

12

**

IREF

> Is

23A

25Co

urie

r Num

ber (

Curre

nt)

4153

3G

21

Setti

ng0.

1*I1

1.5*

I10.

01* I

12

**

IREF

> Is

3A26

Cour

ier N

umbe

r (Cu

rrent

)41

534

G2

0.2

Setti

ng0.

05* I

31.

0*I3

0.01

* I3

2*

**


Page 32 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

GRO

UP 1

3B00

**

*

RESI

DUAL

O/V

NVD

VN In

put

3B01

Inde

xed

Strin

gG

4941

550

G49

Mea

sure

dSe

tting

01

12

**

*

VN>1

Fun

ction

3B02

Inde

xed

Strin

gG

2341

551

G23

DTSe

tting

02

12

**

*

VN>1

Vol

tage

Set

3B03

Cour

ier N

umbe

r (Vo

ltage

)41

552

G2

5Se

tting

1*V1

50*V

11*

V12

**

*V1

app

lied

whe

n VN

set t

o de

rvie

d.1*

V350

*V3

1*V3

V3 a

pplie

d w

hen

VN se

t to

mea

sure

d

VN>1

Tim

e De

lay

3B04

Cour

ier N

umbe

r (Tim

e)41

553

G2

5Se

tting

010

00.

012

**

*

VN>1

TM

S3B

05Co

urie

r Num

ber (

Decim

al)

4155

4G

21

Setti

ng0.

510

00.

52

**

*

VN>1

tRes

et3B

06Co

urie

r Num

ber (

Time)

4155

5G

20

Setti

ng0

100

0.01

2*

**

VN>2

Sta

tus

3B07

Inde

xed

Strin

gG

3741

556

G37

Disa

bled

Setti

ng0

11

2*

**

VN>2

Vol

tage

Set

3B08

Cour

ier N

umbe

r (Vo

ltage

)41

557

G2

10Se

tting

1*V1

50*V

11*

V12

**

*V1

app

lied

whe

n VN

set t

o de

rvie

d.1*

V350

*V3

1*V3

V3 a

pplie

d w

hen

VN se

t to

mea

sure

d

VN>2

Tim

e De

lay

3B09

Cour

ier N

umbe

r (Tim

e)41

558

G2

10Se

tting

010

00.

012

**

*

GRO

UP 1

3C00

*

100%

STA

TOR

EF

100%

St E

F St

atus

3C01

Inde

xed

Strin

gG

3741

600

G37

Enab

led

Setti

ng0

11

2*

100%

St E

F VN

3H<

3C02

Cour

ier N

umbe

r (Vo

ltage

)41

601

G2

1Se

tting

0.3*

V320

*V3

0.1*

V32

*

100%

St E

F De

lay

3C03

Cour

ier N

umbe

r (Tim

e)41

602

G2

5Se

tting

010

00.

012

*

100%

St E

F V<

Inh

3C04

Cour

ier N

umbe

r (Vo

ltage

)41

603

G2

80Se

tting

30*V

112

0*V1

1*V1

2*

GRO

UP 1

3D00

**

VOLT

S/HZ

V/Hz

Alm

Sta

tus

3D01

Inde

xed

Strin

gG

3741

650

G37

Enab

led

Setti

ng0

11

2*

*

V/Hz

Ala

rm S

et3D

02Co

urie

r Num

ber (

Volts

/Hz)

4165

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31Se

tting

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rm D

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ier N

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e)41

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ier N

umbe

r (Vo

lts/H

z)41

654

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Setti

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3.5*

V10.

01*V

12

**


Page 33 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

V/Hz

Trip

TM

S3D

06Co

urie

r Num

ber (

Decim

al)

4165

5G

21

Setti

ng1

631

2*

*

V/Hz

Trip

Del

ay3D

07Co

urie

r Num

ber (

Time)

4165

6G

21

Setti

ng0

100

0.01

2*

*

GRO

UP 1

3E00

*

DF/D

T

df/d

t Sta

tus

3E01

Inde

xed

Strin

gG

3741

700

G37

Enab

led

Setti

ng0

11

2*

df/d

t Set

ting

3E02

Cour

ier N

umbe

r (Hz

/s)

4170

1G

20.

2Se

tting

0.1

100.

012

*

df/d

t Tim

e De

lay

3E03

Cour

ier N

umbe

r (Tim

e)41

702

G2

0.5

Setti

ng0

100

0.01

2*

df/d

t f Lo

w3E

04Co

urie

r Num

ber (

Freq

uenc

y)41

703

G2

49.5

Setti

ng45

650.

012

*

df/d

t f H

igh

3E05

Cour

ier N

umbe

r (Fr

eque

ncy)

4170

4G

250

.5Se

tting

4565

0.01

2*

GRO

UP 1

3F00

*

V VE

CTO

R SH

IFT

V Sh

ift S

tatu

s3F

01In

dexe

d St

ring

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4175

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able

dSe

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01

12

*

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ift A

ngle

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umbe

r (An

gle)

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ng2

301

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GRO

UP 1

4000

*

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MAC

HIN

E

Dead

Mac

h St

atus

4001

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xed

Strin

gG

3741

800

G37

Disa

bled

Setti

ng0

11

2*

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Mac

h I>

4002

Cour

ier N

umbe

r (Cu

rrent

)41

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G2

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Setti

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14*

I10.

01* I

12

*

Dead

Mac

h V<

4003

Cour

ier N

umbe

r (Vo

ltage

)41

802

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80Se

tting

10*V

112

0*V1

1*V1

2*

Dead

Mac

h tP

U40

04Co

urie

r Num

ber (

Time)

4180

3G

25

Setti

ng0

100.

12

*

Dead

Mac

h tD

O40

05Co

urie

r Num

ber (

Time)

4180

4G

20.

5Se

tting

010

0.1

2*

GRO

UP 1

4100

*

RECO

NN

ECT

DELA

Y

Reco

nnec

t Sta

tus

4101

Inde

xed

Strin

gG

3741

850

G37

Enab

led

Setti

ng0

11

2*

Reco

nnec

t Del

ay41

02Co

urie

r Num

ber (

Time)

4185

2G

260

Setti

ng0

300

0.01

2*

Reco

nnec

t tPU

LSE

4103

Cour

ier N

umbe

r (Tim

e)41

853

G2

1Se

tting

0.01

300.

012

*


Page 34 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

GRO

UP 1

4200

**

*

VOLT

PRO

TECT

ION

UNDE

R VO

LTAG

E42

01(S

ub H

eadi

ng)

**

*

V< M

easu

r’t M

ode

4202

Inde

xed

Strin

gG

4741

950

G47

Phas

e-Neu

tral

Setti

ng0

11

2*

**

V< O

pera

te M

ode

4203

Inde

xed

Strin

gG

4841

951

G48

Any

Phas

eSe

tting

01

12

**

*

V<1

Func

tion

4204

Inde

xed

Strin

gG

2341

952

G23

DTSe

tting

02

12

**

*

V<1

Volta

ge S

et42

05Co

urie

r Num

ber (

Volta

ge)

4195

3G

250

Setti

ng10

*V1

120*

V11*

V12

**

*Ra

nge

cove

rs Ph

-N &

Ph-P

h

V<1

Time

Dela

y42

06Co

urie

r Num

ber (

Time)

4195

4G

210

Setti

ng0

100

0.01

2*

**

V<1

TMS

4207

Cour

ier N

umbe

r (De

cimal

)41

955

G2

1Se

tting

0.5

100

0.5

2*

**

V<1

Pole

dead

Inh

4208

Inde

xed

Strin

gG

3741

956

G37

Enab

led

Setti

ng0

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Page 35 of 87M

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Page 36 of 87M

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Page 37 of 87M

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Setti

ng32

163

12

*L3

Blo

ck IN

>2*

*

Opt

o In

put 4

4A04

ASCI

I Tex

t (16

cha

rs)42

324

4233

1G

3L4

Blo

ck I>

3&4

Setti

ng32

163

12

*

L4 B

lock

I>2

**

Opt

o In

put 5

4A05

ASCI

I Tex

t (16

cha

rs)42

332

4233

9G

3L5

Res

etSe

tting

3216

31

2*

**


Page 39 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Opt

o In

put 6

4A06

ASCI

I Tex

t (16

cha

rs)42

340

4234

7G

3L6

Ext

Prot

Trip

Setti

ng32

163

12

**

*

Opt

o In

put 7

4A07

ASCI

I Tex

t (16

cha

rs)42

348

4235

5G

3L7

52a

Setti

ng32

163

12

**

*

Opt

o In

put 8

4A08

ASCI

I Tex

t (16

cha

rs)42

356

4236

3G

3L8

52b

Setti

ng32

163

12

**

*

Opt

o In

put 9

4A09

ASCI

I Tex

t (16

cha

rs)42

364

4237

1G

3L9

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

04A

0AAS

CII T

ext (

16 c

hars)

4237

242

379

G3

L10

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

14A

0BAS

CII T

ext (

16 c

hars)

4238

042

387

G3

L11

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

24A

0CAS

CII T

ext (

16 c

hars)

4238

842

395

G3

L12

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

34A

0DAS

CII T

ext (

16 c

hars)

4239

642

403

G3

L13

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

44A

0EAS

CII T

ext (

16 c

hars)

4240

442

411

G3

L14

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

54A

0FAS

CII T

ext (

16 c

hars)

4241

242

419

G3

L15

Not

Use

dSe

tting

3216

31

2*

Opt

o In

put 1

64A

10AS

CII T

ext (

16 c

hars)

4242

042

427

G3

L16

Not

Use

dSe

tting

3216

31

2*

GRO

UP 1

4B00

**

*

OUT

PUT

LABE

LS

Rela

y 1

4B01

ASCI

I Tex

t (16

cha

rs)42

450

4245

7G

3R1

I N>1

Sta

rtSe

tting

3216

31

2*

R1 T

rip C

B*

*

Rela

y 2

4B02

ASCI

I Tex

t (16

cha

rs)42

458

4246

5G

3R2

I>1

Star

tSe

tting

3216

31

2*

R2 T

rip P

rimeM

ov*

*

Rela

y 3

4B03

ASCI

I Tex

t (16

cha

rs)42

466

4247

3G

3R3

Any

Trip

Setti

ng32

163

12

**

*

Rela

y 4

4B04

ASCI

I Tex

t (16

cha

rs)42

474

4248

1G

3R4

Gen

eral

Ala

rmSe

tting

3216

31

2*

**

Rela

y 5

4B05

ASCI

I Tex

t (16

cha

rs)42

482

4248

9G

3R5

CB

Fail

Setti

ng32

163

12

**

*

Rela

y 6

4B06

ASCI

I Tex

t (16

cha

rs)42

490

4249

7G

3R6

Con

trol C

lose

Setti

ng32

163

12

*R6

E/F

Trip

**

Rela

y 7

4B07

ASCI

I Tex

t (16

cha

rs)42

498

4250

5G

3R7

Con

trol T

ripSe

tting

3216

31

2*

R7 V

or F

Trip

*R7

Vol

t Trip

*

Rela

y 8

4B08

ASCI

I Tex

t (16

cha

rs)42

506

4251

3G

3R8

Fre

q Tr

ipSe

tting

3216

31

2*

Rela

y 9

4B09

ASCI

I Tex

t (16

cha

rs)42

514

4252

1G

3R9

Diff

Trip

Setti

ng32

163

12

*

Rela

y 10

4B0A

ASCI

I Tex

t (16

cha

rs)42

522

4252

9G

3R1

0 Sy

sBac

k Tr

ipSe

tting

3216

31

2*


Page 40 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Rela

y 11

4B0B

ASCI

I Tex

t (16

cha

rs)42

530

4253

7G

3R1

1 N

PS T

ripSe

tting

3216

31

2*

Rela

y 12

4B0C

ASCI

I Tex

t (16

cha

rs)42

538

4254

5G

3R1

2 Ff

ail T

ripSe

tting

3216

31

2*

Rela

y 13

4B0D

ASCI

I Tex

t (16

cha

rs)42

546

4255

3G

3R1

3 Po

wer

Trip

Setti

ng32

163

12

*

Rela

y 14

4B0E

ASCI

I Tex

t (16

cha

rs)42

554

4256

1G

3R1

4 V/

Hz T

ripSe

tting

3216

31

2*

GRO

UP 1

4C00

**

0927

=1 A

ND

091F

=1 A

ND

RTD

LABE

LS“0

006=

””P3

4???

?B*”

””

RTD

101

ASCI

I Tex

t (16

cha

rs)42

750

4275

7G

3RT

D 1

Setti

ng32

163

12

**

RTD

202

ASCI

I Tex

t (16

cha

rs)42

758

4276

5G

3RT

D 2

Setti

ng32

163

12

**

RTD

303

ASCI

I Tex

t (16

cha

rs)42

766

4277

3G

3RT

D 3

Setti

ng32

163

12

**

RTD

404

ASCI

I Tex

t (16

cha

rs)42

774

4278

1G

3RT

D 4

Setti

ng32

163

12

**

RTD

505

ASCI

I Tex

t (16

cha

rs)42

782

4278

9G

3RT

D 5

Setti

ng32

163

12

**

RTD

606

ASCI

I Tex

t (16

cha

rs)42

790

4279

7G

3RT

D 6

Setti

ng32

163

12

**

RTD

707

ASCI

I Tex

t (16

cha

rs)42

798

4280

5G

3RT

D 7

Setti

ng32

163

12

**

RTD

808

ASCI

I Tex

t (16

cha

rs)42

806

4281

3G

3RT

D 8

Setti

ng32

163

12

**

RTD

909

ASCI

I Tex

t (16

cha

rs)42

814

4282

1G

3RT

D 9

Setti

ng32

163

12

**

RTD

100A

ASCI

I Tex

t (16

cha

rs)42

822

4282

9G

3RT

D 10

Setti

ng32

163

12

**

GRO

UP 2

PRO

TECT

ION

SET

TING

S*

**

Repe

at o

f Gro

up 1

5000

4300

044

999

**

*

GRO

UP 3

PRO

TECT

ION

SET

TING

S*

**

Repe

at o

f Gro

up 1

7000

4500

046

999

**

*

GRO

UP 4

PRO

TECT

ION

SET

TING

S*

**

Repe

at o

f Gro

up 1

9000

4700

048

999

**

*

(No

Head

er)

N/A

B000

Auto

extr

actio

n Ev

ent R

ecor

d Co

lumn

**

*

Sele

ct Re

cord

B001

Unsig

ned

Inte

ger (

16 b

its)

Setti

ng0

6553

51

**

*Un

ique

cyc

lical

fault

num

ber(f

rom

eve

nt)

Fault

ed P

hase

B002

Bina

ry F

lag

(8 b

its)

In

dexe

d St

ring

G16

G16

Data

**

*Pr

oduc

t Spe

cific

Bit F

lags

Targ

ettin

g

Star

t Ele

men

ts1B0

03Bi

nary

Fla

g (3

2 Bi

ts) In

dexe

d St

ringG

84G

84Da

ta*

**

Prod

uct S

pecif

ic Bi

t Fla

gs Ta

rget

ting


Page 41 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Star

t Ele

men

ts2B0

04Bi

nary

Flag

(32

Bits)

Inde

xed

Strin

gG10

7G

107

Data

**

*

Trip

Ele

men

ts1B0

05Bi

nary

Fla

g (3

2 Bi

ts) In

dexe

d St

ringG

85G

85Da

ta*

**

Prod

uct S

pecif

ic Bi

t Fla

gs Ta

rget

ting

Trip

ped

Elem

ents2

B006

Bina

ry F

lag

(32

Bits)

Ind

exed

Stri

ngG

86G

86Da

ta*

**

Prod

uct S

pecif

ic Bi

t Fla

gs Ta

rget

ting

Fault

Ala

rms

B007

Bina

ry F

lag

(32

Bits)

Inde

xed

Strin

gG87

G87

Data

**

*Pr

oduc

t Spe

cific

Bit F

lags

Targ

ettin

g

Fault

Tim

eB0

08IE

C870

Tim

e &

Date

Data

**

*

Activ

e G

roup

B009

Unsig

ned

Inte

ger

Data

**

*

Syste

m F

requ

ency

B00A

Cour

ier N

umbe

r (fre

quen

cy)

Data

**

*

Fault

Dur

atio

nB0

0BCo

urie

r Num

ber (

time)

Data

**

*

CB O

pera

te T

ime

B00C

Cour

ier N

umbe

r (tim

e)Da

ta*

**

Rela

y Tr

ip T

ime

B00D

Cour

ier N

umbe

r (tim

e)Da

ta*

**

IAB0

0ECo

urie

r Num

ber (

curre

nt)

Data

**

IA-1

*

IBB0

0FCo

urie

r Num

ber (

curre

nt)

Data

**

IB-1

*

ICB0

10Co

urie

r Num

ber (

curre

nt)

Data

**

IC-1

*

VAB

B011

Cour

ier N

umbe

r (vo

ltage

)Da

ta*

**

VBC

B012

Cour

ier N

umbe

r (vo

ltage

)Da

ta*

**

VCA

B013

Cour

ier N

umbe

r (vo

ltage

)Da

ta*

**

VAN

B014

Cour

ier N

umbe

r (vo

ltage

)Da

ta*

**

VBN

B015

Cour

ier N

umbe

r (vo

ltage

)Da

ta*

**

VCN

B016

Cour

ier N

umbe

r (vo

ltage

)Da

ta*

**

IA-2

B017

Cour

ier N

umbe

r (cu

rrent

)Da

ta*

IB-2

B018

Cour

ier N

umbe

r (cu

rrent

)Da

ta*

IC-2

B019

Cour

ier N

umbe

r (cu

rrent

)Da

ta*

IA D

iffer

entia

lB0

1ACo

urie

r Num

ber (

Curre

nt)

Data

*


Page 42 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

B Di

ffere

ntia

lB0

1BCo

urie

r Num

ber (

Curre

nt)

Data

*

IC D

iffer

entia

lB0

1CCo

urie

r Num

ber (

Curre

nt)

Data

*

VN M

easu

red

B01D

Cour

ier N

umbe

r (Vo

ltage

)Da

ta*

**

VN D

erive

dB0

1ECo

urie

r Num

ber (

Volta

ge)

Data

**

*

IN M

easu

red

B01F

Cour

ier N

umbe

r (Vo

ltage

)Da

ta*

*

IN D

erive

dB0

1FCo

urie

r Num

ber (

Curre

nt)

Data

*

IN S

ensit

iveB0

20Co

urie

r Num

ber (

Curre

nt)

Data

**

*

IREF

Diff

B021

Cour

ier N

umbe

r (Cu

rrent

)Da

ta*

*

IREF

Bia

sB0

22Co

urie

r Num

ber (

Curre

nt)

Data

**

I2B0

23Co

urie

r Num

ber (

Curre

nt)

Data

**

3 Ph

ase

Wat

tsB0

24Co

urie

r Num

ber (

Wat

ts)Da

ta*

**

3 Ph

ase

VARs

B025

Cour

ier N

umbe

r (VA

Rs)

Data

**

*

3 Ph

ase

Powe

r Fac

torB0

26Co

urie

r Num

ber (

No

unit)

Data

**

*

RTD

1B0

27Co

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

2B0

28Co

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

3B0

29Co

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

4B0

2ACo

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

5B0

2BCo

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

6B0

2CCo

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

7B0

2DCo

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

8B0

2ECo

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

9B0

2FCo

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

RTD

10B0

30Co

urie

r Num

ber (

Tem

pera

ture

)Da

ta*

*

df/d

tB0

31Co

urie

r Num

ber (

Hz/s

)Da

ta*

V Ve

ctor S

hift

B032

Cour

ier N

umbe

r (An

gle)

Data

*

No

Head

er)

N/A

B100

Auto

extr

actio

n M

aint

enan

ceRe

cord

Col

umn

**

*M

enu

Text

UIM

enu

Text

UI


Page 43 of 87Co

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

dDa

tagr

oup

Leve

lP3

41P3

42P3

43

Sele

ct Re

cord

B101

UIN

T16

Setti

ng0

6553

51

**

*

Time

and

Date

B102

IEC

Date

and

Tim

eDa

ta*

**

Reco

rd Te

xtB1

03AS

CII T

ext (

32 c

hars)

Data

**

*

Reco

rd Ty

peB1

04Un

signe

d In

tege

r (32

bits

)Da

ta*

**

Reco

rd D

ata

B105

Unsig

ned

Inte

ger (

32 b

its)

Data

**

*

(No

Head

er)

N/A

B200

Data

Tran

sfer

Dom

ain

B204

Inde

xed

Strin

gG

57PS

L Set

tings

Setti

ng0

11

2*

**

Sub-

Dom

ain

B208

Inde

xed

Strin

gG

90G

roup

1Se

tting

03

12

**

*

Versi

onB2

0CUn

signe

d In

tege

r (2

Byte

s)25

6Se

tting

065

535

12

**

*

Star

tB2

10N

ot U

sed

**

*

Leng

thB2

14N

ot U

sed

**

*

Refe

renc

eB2

18N

ot U

sed

**

*

Tran

sfer M

ode

B21C

Unsig

ned

Inte

ger I

ndex

ed S

tring

sG76

G76

6Se

tting

07

12

**

*

Data

Tra

nsfe

rB2

20Re

peat

ed g

roup

s of U

nsig

ned

Inte

gers

Setti

ng*

**O

nly se

ttabl

e if

Dom

ain

= PS

L Sett

ings

(No

Head

er)

N/A

B300

Distu

rban

ce R

ecor

der C

ontro

l*

**

UNUS

EDB3

01*

**

Reco

rder

Sou

rce

B302

Inde

xed

Strin

g0

0Sa

mpl

esDa

ta*

**

(No

Head

er)

N/A

B400

Distu

rban

ce R

ecor

d Ex

tracti

on*

**

Sele

ct Re

cord

B401

Unsig

ned

Inte

ger

0Se

tting

-199

199

10

**

*

Trig

ger T

ime

B402

IEC8

70 T

ime

& Da

teDa

ta*

**

Form

atB4

0AUn

signe

d In

tege

r1

Data

**

*

Uplo

adB4

0BUn

signe

d In

tege

rDa

ta*

**

3080

0G

1Da

ta*

**

Num

ber o

f Dist

urba

nce

Reco

rds

(0 to

200

)30

801

G1

Data

**

*O

ldes

t Sto

red

Distu

rban

ce R

ecor

d(1

to 6

5535

)30

802

G1

Data

**

*N

umbe

r of R

egist

ers i

n Cu

rrent

Pag

e30

803

3092

9G

1Da

ta*

**

Distu

rban

ce R

ecor

d Pa

ge (0

to 6

5535

)40

250

G1

Setti

ng1

6553

51

2*

**

Sele

ct Di

sturb

ance

Rec

ord

3093

030

933

G12

Data

**

*Tim

esta

mp

of se

lecte

d re

cord


Page 44 of 87M

enu

Text

UICo

urie

rM

odbu

sAd

dres

sM

odbu

sDe

fault

Set

ting

Cell

Type

Min

Max

Step

Pass

wor

dM

odel

Com

men

tCo

lRo

wDa

ta ty

peSt

rings

Star

tEn

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Page 45 of 87

Data types and indexed string settingsTYPE VALUE/BIT MASK DESCRIPTION

G1 1 Register UNSIGNED INTEGER

Range 0 to 65535

G2 1 Register NUMERIC SETTING

Value = (Setting - Minimum) / Step Size

G3 Variable number of Registers ASCII TEXT CHARACTERS

0x00FF Second character

0xFF00 First character

G4 2 Registers PLANT STATUS

“(Second reg, First Reg)”

“0x0000,0x0001” “CB1 Open (0 = Off, 1 = On)”

“0x0000,0x0002” “CB1 Closed (0 = Off, 1 = On)”

“0x0000,0x0004” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0008” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0010” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0020” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0040” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0080” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0100” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0200” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0400” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0800” “Not Used (0 = Off, 1 = On)”

“0x0000,0x1000” “Not Used (0 = Off, 1 = On)”

“0x0000,0x2000” “Not Used (0 = Off, 1 = On)”

“0x0000,0x4000” “Not Used (0 = Off, 1 = On)”

“0x0000,0x8000” “Not Used (0 = Off, 1 = On)”

“0x0001,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0002,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0004,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0008,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0010,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0020,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0040,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0080,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0100,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0200,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0400,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0800,0x0000” “Not Used (0 = Off, 1 = On)”

“0x1000,0x0000” “Not Used (0 = Off, 1 = On)”

“0x2000,0x0000” “Not Used (0 = Off, 1 = On)”

“0x4000,0x0000” “Not Used (0 = Off, 1 = On)”

“0x8000,0x0000” “Not Used (0 = Off, 1 = On)”

G5 2 Registers CONTROL STATUS


“0x0000,0x0001” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0002” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0004” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0008” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0010” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0020” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0040” “Not Used (0 = Off, 1 = On)”


Page 46 of 87

TYPE VALUE/BIT MASK DESCRIPTION

“0x0000,0x0080” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0100” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0200” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0400” “Not Used (0 = Off, 1 = On)”

“0x0000,0x0800” “Not Used (0 = Off, 1 = On)”

“0x0000,0x1000” “Not Used (0 = Off, 1 = On)”

“0x0000,0x2000” “Not Used (0 = Off, 1 = On)”

“0x0000,0x4000” “Not Used (0 = Off, 1 = On)”

“0x0000,0x8000” “Not Used (0 = Off, 1 = On)”

“0x0001,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0002,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0004,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0008,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0010,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0020,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0040,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0080,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0100,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0200,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0400,0x0000” “Not Used (0 = Off, 1 = On)”

“0x0800,0x0000” “Not Used (0 = Off, 1 = On)”

“0x1000,0x0000” “Not Used (0 = Off, 1 = On)”

“0x2000,0x0000” “Not Used (0 = Off, 1 = On)”

“0x4000,0x0000” “Not Used (0 = Off, 1 = On)”

“0x8000,0x0000” “Not Used (0 = Off, 1 = On)”

G6 1 Register RECORD CONTROL COMMAND REGISTER

0 No operation

1 Clear Event records

2 Clear Fault Record

3 Clear Maintenance Records

4 Reset Indications

G7 VTS INDICATE / BLOCK

0 Blocking

1 Indication

G8 1 Register LOGIC INPUT STATUS

0x0001 “Opto 1 Input State (0=Off, 1=Energised)”








0x0100 “Opto 9 Input State (0=Off, 1=Energised)” P343 only









Page 47 of 87


G9 RELAY OUTPUT STATUS


“0x0000,0x0001” “Relay 1 (0=Not Operated, 1=Operated)”







“0x0000,0x0080” “Relay 8 (0=Not Operated, 1=Operated)” P343 only







“0x0000,0x4000” “Relay 8 (0=Not Operated, 1=Operated)” Not Used







G10 1 Register “Signed fixed point number, 1 decimal place”

Range -3276.8 to 3276.7

G11 YES/NO

0 No

1 Yes

G12 4 registers TIME AND DATE

This will take the IEC 870 format

0x007F First register - Years

0x0FFF Second register - Month of year / Day of month / Day of week

0x9FBF Third Register - Summertime and hours / Validity and minutes

0xFFFF Fourth Register - Milli-seconds

G13 EVENT RECORD TYPE (MODBUS)

0 Latched alarm active

1 Latched alarm inactive

2 Self reset alarm active

3 Self reset alarm inactive

4 Relay event

5 Opto event

6 Protection event

7 Platform event

8 Fault logged event

9 Maintenance record logged event

G14 I> FUNCTION LINK “(Note: 1=Block, 0=Non Directional)”

Bit 0 I>1 VTS Block P341 only




Bit 4 Not Used


Page 48 of 87


Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G15 DISTURBANCE RECORD INDEX STATUS

0 No Record

1 Unextracted

2 Extracted

G16 FAULTED PHASE

0x0001 Start A

0x0002 Start B

0x0004 Start C

0x0008 Start N

0x0010 Trip A

0x0020 Trip B

0x0040 Trip C

0x0080 Trip N

G17 IRIG-B STATUS

0 Card not fitted

1 Card failed

2 Signal healthy

3 No signal

G18 RECORD SELECTION COMMAND REGISTER

0 No Operation

1 Select next event

2 Accept Event

3 Select next Disurbance Record

4 Accept disturbance record

5 Select Next Disturbance record page

G19 LANGUAGE

0 English

1 Francais

2 Deutsch

3 Espanol

G20 “(Second reg, First Reg)” PASSWORD (2 REGISTERS)

“0x0000, 0x00FF” First password character

“0x0000, 0xFF00” Second password character

“0x00FF, 0x0000” Third password character

“0xFF00, 0x0000” Fourth password character

NOTE THAT WHEN REGISTERS OF THIS TYPE ARE READ THE SLAVE WILL

“ALWAYS INDICATE AN “”*”” IN EACH CHARACTER POSITION TO PRESERVE “

THE PASSWORD SECURITY.

G21 IEC870 INTERFACE

0 RS485

1 Fibre Optic

G22 PASSWORD CONTROL ACCESS LEVEL

0 Level 0 - Passwords required for levels 1 & 2.

1 Level 1 - Password required for level 2.

2 Level 2 - No passwords required.


Page 49 of 87


G23 VOLTAGE AND V/HZ CURVE SELECTION

0 Disabled

1 DT

2 IDMT

G24 2 Registers “UNSIGNED LONG VALUE, 3 DECIMAL PLACES”

High order word of long stored in 1st register

Low order word of long stored in 2nd register

Example 123456.789 stored as 123456789

G25 1 Register “UNSIGNED VALUE, 3 DECIMAL PLACES”

Example 50.050 stored as 50050

Range -32.768 to 32.767

G26 RELAY STATUS

0x0001 Event

0x0002 Disturbance

0x0004 Alarm

0x0008 Trip

0x0010 Out of Service

0x0020 Plant

0x0040 Control

0x0080 Unused

0x0100 Unused

0x0200 Unused

0x0400 Unused

0x0800 Unused

0x1000 Unused

0x2000 Unused

0x4000 Unused

0x8000 Unused

G27 2 REGISTERS UNSIGNED LONG VALUE

High order word of long stored in 1st register

Low order word of long stored in 2nd register

Range -2.147E9 to 2.147E9

G28 1 REGISTER SIGNED VALUE POWER & WATT-HOURS

Power = (Secondary power/CT secondary) * (100/VT secondary)

Range -32768 to 32767

G29 3 REGISTER POWER MULTIPLER

All power measurments use a signed value of type G28 and a

2 register unsigned long multiplier of type G27

Value = Real Value*110/(CTsecondary*VTsecondary)

For Primary Power Multipler = CTprimary * VTprimary/110

For Secondary Power Multipler = CTsecondary * VTsecondary/110

Range -1.40E14 to 1.40E14

G30 1 REGISTER “SIGNED VALUE, 2 DECIMAL PLACES”

Range -327.68 to 327.67


Page 50 of 87


G31 ANALOGUE CHANNEL ASSIGNMENT SELECTOR

P341 P342 P343

0 VAN VAN VAN

1 VBN VBN VBN

2 VCN VCN VCN

3 VN VN VN

4 IA IA IA-1

5 IB IB IB-1

6 IC IC IC-1

7 IN Sensitive IN IN

8 IN Sensitive IN Sensitive

9 IA-2

10 IB-2

11 IC-2

G32 DIGITAL CHANNEL ASSIGNMENT SELECTOR (See DDB)

P341 P342 P343

0 Unused Unused Unused

1 R1 IN>1 Start R1 Trip CB R1 Trip CB

2 R2 I>1 Start R2 Trip PrimeMov R2 Trip PrimeMov

3 R3 Any Trip R3 Any Trip R3 Any Trip

4 R4 General Alarm R4 General Alarm R4 General Alarm

5 R5 CB Fail R5 CB Fail R5 CB Fail

6 R6 Control Close R6 E/F trip R6 E/F Trip

7 R7 Control Trip R7 V or F Trip R7 Volt Trip

8 L1 Setting group L1 Setting Group R8 Freq Trip

9 L2 Setting group L2 Setting Group R9 Diff Trip

10 L3 Block IN>3&4 L3 Block IN>2 R10 SysBack Trip

11 L4 Block I> 3&4 L4 Block I>2 R11 NPS Trip

12 L5 Reset L5 Reset R12 Ffail Trip

13 L6 Ext Prot Trip L6 Ext Prot Trip R13 Power trip

14 L7 52a L7 52a R14 V/Hz trip

15 L8 52b L8 52b L1 Setting Group

16 LED 1 LED 1 L2 Setting Group

17 LED 2 LED 2 L3 Block IN>2

18 LED 3 LED 3 L4 Block I>2

19 LED 4 LED 4 L5 Reset

20 LED 5 LED 5 L6 Ext Prot Trip

21 LED 6 LED 6 L7 52a

22 LED 7 LED 7 L8 52b

23 LED 8 LED 8 L9 Not Used

24 SG-opto Invalid SG-opto Invalid L10 Not Used

25 Prot’n Disabled Prot’n Disabled L11 Not Used

26 VT Fail Alarm VT Fail Alarm L12 Not Used

27 CT Fail Alarm CT Fail Alarm L13 Not Used

28 CB Fail Alarm CB Fail Alarm L14 Not Used

29 I^ Maint Alarm I^ Maint Alarm L15 Not Used

30 I^ Lockout Alarm I^ Lockout Alarm L16 Not Used

31 CB Ops Maint CB Ops Maint LED 1

32 CB Ops Lockout CB Ops Lockout LED 2

33 CB Op Time Maint CB Op Time Maint LED 3

34 CB Op Time Lock CB Op Time Lock LED 4

35 Fault Freq Lock Fault Freq Lock LED 5

36 CB Status Alarm CB Status Alarm LED 6

37 Man CB Trip Fail Man CB Trip Fail LED 7


Page 51 of 87


38 Man CB Cls Fail Man CB Cls Fail LED 8

39 Man CB Unhealthy Man CB Unhealthy SG-opto Invalid

40 F out of range NPS Alarm Prot’n Disabled

41 Freq Prot Alm V/Hz Alarm VT Fail Alarm

42 Voltage Prot Alm Field Fail Alarm CT Fail Alarm

43 User Alarm 1 RTD Thermal Alm CB Fail Alarm

44 User Alarm 2 RTD Open Cct I^ Maint Alarm

45 User Alarm 3 RTD short Cct I^ Lockout Alarm

46 User Alarm 4 RTD Data Error CB Ops Maint

47 df/dt Trip RTD Board Fail CB Ops Lockout

48 V Shift Trip Freq Prot Alm CB Op Time Maint

49 IN>1 Trip Voltage Prot Alm CB Op Time Lock

50 IN>2 Trip User Alarm 1 Fault Freq Lock

51 IN>3 Trip User Alarm 2 CB Status Alarm

52 IN>4 Trip User Alarm 3 Man CB Trip Fail

53 IREF> Trip User Alarm 4 Man CB Cls Fail

54 ISEF>1 Trip Field Fail1 Trip Man CB Unhealthy

55 ISEF>2 Trip Field Fail2 Trip NPS Alarm

56 ISEF>3 Trip NPS Trip V/Hz Alarm

57 ISEF>4 Trip Sys Back Trip Field Fail Alarm

58 VN>1 Trip Sys Back Trip A RTD Thermal Alm

59 VN>2 Trip Sys Back Trip B RTD Open Cct

60 V<1 Trip Sys Back Trip C RTD short Cct

61 V<1 Trip A/AB V/Hz Trip RTD Data Error

62 V<1 Trip B/BC RTD 1 Trip RTD Board Fail

63 V<1 Trip C/CA RTD 2 Trip Freq Prot Alm

64 V<2 Trip RTD 3 Trip Voltage Prot Alm

65 V<2 Trip A/AB RTD 4 Trip User Alarm 1

66 V<2 Trip B/BC RTD 5 Trip User Alarm 2

67 V<2 Trip C/CA RTD 6 Trip User Alarm 3

68 V>1 Trip RTD 7 Trip User Alarm 4

69 V>1 Trip A/AB RTD 8 Trip 100% ST EF Trip

70 V>1 Trip B/BC RTD 9 Trip DeadMachine trip

71 V>1 Trip C/CA RTD 10 Trip Gen Diff Trip

72 V>2 Trip Any RTD Trip Gen Diff Trip A

73 V>2 Trip A/AB IN>1 Trip Gen Diff Trip B

74 V>2 Trip B/BC IN>2 Trip Gen Diff Trip C

75 V>2 Trip C/CA IREF> Trip Field Fail1 Trip

76 F<1 Trip ISEF>1 Trip Field Fail2 Trip

77 F<2 Trip VN>1 Trip NPS Trip

78 F<3 Trip VN>2 Trip Sys Back Trip

79 F<4 Trip V<1 Trip Sys Back Trip A

80 F>1 Trip V<1 Trip A/AB Sys Back Trip B

81 F>2 Trip V<1 Trip B/BC Sys Back Trip C

82 Power1 Trip V<1 Trip C/CA V/Hz Trip

83 Power2 Trip V<2 Trip RTD 1 Trip

84 I>1 Trip V<2 Trip A/AB RTD 2 Trip

85 I>1 Trip A V<2 Trip B/BC RTD 3 Trip

86 I>1 Trip B V<2 Trip C/CA RTD 4 Trip

87 I>1 Trip C V>1 Trip RTD 5 Trip

88 I>2 Trip V>1 Trip A/AB RTD 6 Trip

89 I>2 Trip A V>1 Trip B/BC RTD 7 Trip

90 I>2 Trip B V>1 Trip C/CA RTD 8 Trip

91 I>2 Trip C V>2 Trip RTD 9 Trip

92 I>3 Trip V>2 Trip A/AB RTD 10 Trip


Page 52 of 87


93 I>3 Trip A V>2 Trip B/BC Any RTD Trip

94 I>3 Trip B V>2 Trip C/CA IN>1 Trip

95 I>3 Trip C F<1 Trip IN>2 Trip

96 I>4 Trip F<2 Trip IREF> Trip

97 I>4 Trip A F<3 Trip ISEF>1 Trip

98 I>4 Trip B F<4 Trip VN>1 Trip

99 I>4 Trip C F>1 Trip VN>2 Trip

100 Any Start F>2 Trip V<1 Trip

101 VN>1 Start Power1 Trip V<1 Trip A/AB

102 VN>2 Start Power2 Trip V<1 Trip B/BC

103 V<1 Start I>1 Trip V<1 Trip C/CA

104 V<1 Start A/AB I>1 Trip A V<2 Trip

105 V<1 Start B/BC I>1 Trip B V<2 Trip A/AB

106 V<1 Start C/CA I>1 Trip C V<2 Trip B/BC

107 V<2 Start I>2 Trip V<2 Trip C/CA

108 V<2 Start A/AB I>2 Trip A V>1 Trip

109 V<2 Start B/BC I>2 Trip B V>1 Trip A/AB

110 V<2 Start C/CA I>2 Trip C V>1 Trip B/BC

111 V>1 Start Any Start V>1 Trip C/CA

112 V>1 Start A/AB VN>1 Start V>2 Trip

113 V>1 Start B/BC VN>2 Start V>2 Trip A/AB

114 V>1 Start C/CA V<1 Start V>2 Trip B/BC

115 V>2 Start V<1 Start A/AB V>2 Trip C/CA

116 V>2 Start A/AB V<1 Start B/BC F<1 Trip

117 V>2 Start B/BC V<1 Start C/CA F<2 Trip

118 V>2 Start C/CA V<2 Start F<3 Trip

119 Power1 Start V<2 Start A/AB F<4 Trip

120 Power2 Start V<2 Start B/BC F>1 Trip

121 I>1 Start V<2 Start C/CA F>2 Trip

122 I>1 Start A V>1 Start Power1 Trip

123 I>1 Start B V>1 Start A/AB Power2 Trip

124 I>1 Start C V>1 Start B/BC I>1 Trip

125 I>2 Start V>1 Start C/CA I>1 Trip A

126 I>2 Start A V>2 Start I>1 Trip B

127 I>2 Start B V>2 Start A/AB I>1 Trip C

128 I>2 Start C V>2 Start B/BC I>2 Trip

129 I>3 Start V>2 Start C/CA I>2 Trip A

130 I>3 Start A Power1 Start I>2 Trip B

131 I>3 Start B Power2 Start I>2 Trip C

132 I>3 Start C I>1 Start Any Start

133 I>4 Start I>1 Start A VN>1 Start

134 I>4 Start A I>1 Start B VN>2 Start

135 I>4 Start B I>1 Start C V<1 Start

136 I>4 Start C I>2 Start V<1 Start A/AB

137 IN>1 Start I>2 Start A V<1 Start B/BC

138 IN>2 Start I>2 Start B V<1 Start C/CA

139 IN>3 Start I>2 Start C V<2 Start

140 IN>4 Start IN>1 Start V<2 Start A/AB

141 ISEF>1 Start IN>2 Start V<2 Start B/BC

142 ISEF>2 Start ISEF>1 Start V<2 Start C/CA

143 ISEF>3 Start F<1 Start V>1 Start

144 ISEF>4 Start F<2 Start V>1 Start A/AB

145 F<1 Start F<3 Start V>1 Start B/BC

146 F<2 Start F<4 Start V>1 Start C/CA

147 F<3 Start F>1 Start V>2 Start


Page 53 of 87


148 F<4 Start F>2 Start V>2 Start A/AB

149 F>1 Start VTS Fast Block V>2 Start B/BC

150 F>2 Start VTS Slow Block V>2 Start C/CA

151 VTS Fast Block CTS Block Power1 Start

152 VTS Slow Block Bfail1 Trip 3ph Power2 Start

153 CTS Block Bfail2 Trip 3ph I>1 Start

154 Bfail1 Trip 3ph IA< Start I>1 Start A

155 Bfail2 Trip 3ph IB< Start I>1 Start B

156 Control Trip IC< Start I>1 Start C

157 Control Close ISEF< Start I>2 Start

158 Close in Prog IN< Start I>2 Start A

159 Reconnection V/Hz Start I>2 Start B

160 I> BlockStart FFail1 Start I>2 Start C

161 IN/SEF>Blk Start FFail2 Start IN>1 Start

162 df/dt Start Sys Back Start IN>2 Start

163 IA< Start Sys Back Start A ISEF>1 Start

164 IB< Start Sys Back Start B 100% ST EF Start

165 IC< Start Sys Back Start C F<1 Start

166 ISEF< Start RTD 1 Alarm F<2 Start

167 Lockout Alarm RTD 2 Alarm F<3 Start

168 CB Open 3 ph RTD 3 Alarm F<4 Start

169 CB Closed 3 ph RTD 4 Alarm F>1 Start

170 Field Volts Fail RTD 5 Alarm F>2 Start

171 RTD 6 Alarm VTS Fast Block

172 RTD 7 Alarm VTS Slow Block

173 RTD 8 Alarm CTS Block

174 RTD 9 Alarm Bfail1 Trip 3ph

175 RTD 10 Alarm Bfail2 Trip 3ph

176 Lockout Alarm IA< Start

177 CB Open 3 ph IB< Start

178 CB Closed 3 ph IC< Start

179 Field Volts Fail ISEF< Start

180 IN< Start

181 V/Hz Start

182 FFail1 Start

183 FFail2 Start

184 Sys Back Start

185 Sys Back Start A

186 Sys Back Start B

187 Sys Back Start C

188 RTD 1 Alarm

189 RTD 2 Alarm

190 RTD 3 Alarm

191 RTD 4 Alarm

192 RTD 5 Alarm

193 RTD 6 Alarm

194 RTD 7 Alarm

195 RTD 8 Alarm

196 RTD 9 Alarm

197 RTD 10 Alarm

198 Lockout Alarm

199 CB Open 3 ph

200 CB Closed 3 ph

201 Field Volts Fail


Page 54 of 87


G34 TRIGGER MODE

0 Single

1 Extended

G35 Numeric Setting (as G2 but 2 registers)

Number of steps from minimum value

expressed as 2 register 32 bit unsigned int

G37 ENABLED / DISABLED

0 Disabled

1 Enabled

G38 COMMUNICATION BAUD RATE

0 9600 bits/s

1 19200 bits/s

2 38400 bits/s

G39 COMMUNICATIONS PARITY

0 Odd

1 Even

2 None

G43 IDMT CURVE TYPE

0 Disabled

1 DT

2 IEC S Inverse

3 IEC V Inverse

4 IEC E Inverse

5 UK LT Inverse

6 IEEE M Inverse

7 IEEE V Inverse

8 IEEE E Inverse

9 US Inverse

10 US ST Inverse

G44 DIRECTION

0 Non-Directional

1 Directional Fwd

2 Directional Rev

G46 POLARISATION

0 Zero Sequence

1 Neg Sequence

G47 MEASURING MODE

0 Phase-Phase

1 Phase-Neutral

G48 OPERATION MODE

0 Any Phase

1 Three Phase

G49 VN OR IN INPUT

0 Measured

1 Derived


Page 55 of 87


G50 RTD SELECT

0x0001 RTD Input 1

0x0002 RTD Input 2

0x0004 RTD Input 3

0x0008 RTD Input 4

0x0010 RTD Input 5

0x0020 RTD Input 6

0x0040 RTD Input 7

0x0080 RTD Input 8

0x0100 RTD Input 9

0x0200 RTD Input 10

G52 DEFAULT DISPLAY

0 3Ph + N Current

1 3Ph Voltage

2 Power

3 Date and Time

4 Description

5 Plant Reference

6 Frequency

7 Access Level

G53 SELECT FACTORY DEFAULTS

0 No Operation

1 All Settings

2 Setting Group 1

3 Setting Group 2

4 Setting Group 3

5 Setting Group 4

G54 SELECT PRIMARY SECONDARY MEASUREMENTS

0 Primary

1 Secondary

G55 CIRCUIT BREAKER CONTROL

0 No Operation

1 Trip

2 Close

G56 PHASE MEASUREMENT REFERENCE

0 VA

1 VB

2 VC

3 IA

4 IB

5 IC

G57 Data Transfer Domain

0 PSL Settings

1 PSL Configuration

G58 SEF/REF SELECTION

0 SEF

1 Wattmetric

2 Hi Z REF


Page 56 of 87


3 Lo Z REF P342 and P343 only

4 Lo Z REF+SEF P342 and P343 only

5 Lo Z REF+Wattmet P342 and P343 only

G59 BATTERY STATUS

0 Dead

1 Healthy

G60 Time Delay Selection

0 DT

1 Inverse

G61 ACTIVE GROUP CONTROL

0 Select via Menu

1 Select via Opto

G62 SAVE AS

0 No Operation

1 Save

2 Abort

G63 IN> FUNCTION LINK “(Note: 1=Block, 0=Non Directional)”

Bit 0 IN>1 VTS Block P341 only




Bit 4 Not Used

Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G64 ISEF> FUNCTION LINK “(Note: 1=Block, 0=Non Directional)”

Bit 0 ISEF>1 VTS Block

Bit 1 ISEF>2 VTS Block P341 only



Bit 4 Not Used

Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G65 F< FUNCTION LINK

Bit 0 F<1 Poledead Blk




Bit 4 Not Used

Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G66 MESSAGE FORMAT

0 No Trigger

1 Trigger L/H

2 Trigger H/L


Page 57 of 87


G68 CB Fail Reset Options

0 I< Only

1 CB Open & I<

2 Prot Reset & I<

G69 VTS RESET MODE

0 Manual

1 Auto

G71 PROTOCOL

0 Courier

1 IEC870-5-103

2 Modbus

G76 TRANSFER MODE

0 Prepare Rx

1 Complete Rx

2 Prepare Tx

3 Complete Tx

4 Rx Prepared

5 Tx Prepared

6 OK

7 Error

G79 CUSTOM SETTINGS

0 Disabled

1 Basic

2 Complete

G80 VISIBLE / INVISIBLE

0 Invisible

1 Visible

G81 RESET LOCKOUT BY

0 User Interface

1 CB Close

G84 Modbus value+bit position START ELEMENTS 1


“0x0000,0x0001” General Start

“0x0000,0x0002” Start Power1

“0x0000,0x0004” Start Power2

“0x0000,0x0008” Start FFail1 P342 and P343 only

“0x0000,0x0010” Start FFail2 P342 and P343 only

“0x0000,0x0020” Start Sys Back P342 and P343 only

“0x0000,0x0040” Start I>1

“0x0000,0x0080” Start I>2

“0x0000,0x0100” Start I>3 P341 only

“0x0000,0x0200” Start I>4 P341 only

“0x0000,0x0400” Start IN>1

“0x0000,0x0800” Start IN>2

“0x0000,0x1000” Start IN>3 P341 only

“0x0000,0x2000” Start IN>4 P341 only

“0x0000,0x4000” Start ISEF>1

“0x0000,0x8000” Start ISEF>2 P341 only



Page 58 of 87



“0x0004,0x0000” Start NVD VN>1

“0x0008,0x0000” Start NVD VN>2

“0x0010,0x0000” Start 100% ST EF P343 only

“0x0020,0x0000”

“0x0040,0x0000”

“0x0080,0x0000”

“0x0100,0x0000”

“0x0200,0x0000”

“0x0400,0x0000”

“0x0800,0x0000”

“0x1000,0x0000”

“0x2000,0x0000”

“0x4000,0x0000”

“0x8000,0x0000”

G85 Modbus value+bit position TRIP ELEMENTS 1


“0x0000,0x0001” Any Trip

“0x0000,0x0002” Trip Gen Diff P343 only

“0x0000,0x0004” Trip Power1

“0x0000,0x0008” Trip Power2

“0x0000,0x0010” Trip FFail1 P342 and P343 only

“0x0000,0x0020” Trip FFail2 P342 and P343 only

“0x0000,0x0040” Trip NPS P342 and P343 only

“0x0000,0x0080” Trip Sys Back P342 and P343 only

“0x0000,0x0100” Trip I>1

“0x0000,0x0200” Trip I>2

“0x0000,0x0400” Trip I>3 P431 only

“0x0000,0x0800” Trip I>4 P431 only

“0x0000,0x1000” Trip IN>1

“0x0000,0x2000” Trip IN>2

“0x0000,0x4000” Trip IN>3 P431 only

“0x0000,0x8000” Trip IN>4 P431 only

“0x0001,0x0000” Trip ISEF>1

“0x0002,0x0000” Trip ISEF>2 P431 only



“0x0010,0x0000” Trip IREF>

“0x0020,0x0000” Trip NVD VN>1

“0x0040,0x0000” Trip NVD VN>2

“0x0080,0x0000” Trip 100% ST EF P343 only

“0x0100,0x0000” Trip Dead Mach P343 only

“0x0200,0x0000”

“0x0400,0x0000”

“0x0800,0x0000”

“0x1000,0x0000”

“0x2000,0x0000”

“0x4000,0x0000”

“0x8000,0x0000”

G86 Bit Description TRIP ELEMENTS 2


“0x0000,0x0001” Trip V<1

“0x0000,0x0002” Trip V<2


Page 59 of 87


“0x0000,0x0004” Trip V< A/AB

“0x0000,0x0008” Trip V< B/BC

“0x0000,0x0010” Trip V< C/CA

“0x0000,0x0020” Trip V>1

“0x0000,0x0040” Trip V>2

“0x0000,0x0080” Trip V> A/AB

“0x0000,0x0100” Trip V> B/BC

“0x0000,0x0200” Trip V> C/CA

“0x0000,0x0400” Trip F<1

“0x0000,0x0800” Trip F<2

“0x0000,0x1000” Trip F<3

“0x0000,0x2000” Trip F<4

“0x0000,0x4000” Trip F>1

“0x0000,0x8000” Trip F>2

“0x0001,0x0000” Trip V/Hz P342 and P343 only

“0x0002,0x0000” Trip df/dt P341 only

“0x0004,0x0000” Trip V Shift P341 only

“0x0008,0x0000” Trip RTD 1 P342 and P343 only










“0x2000,0x0000”

“0x4000,0x0000”

“0x8000,0x0000”

G87 Bit Description FAULT ALARMS


“0x0000,0x0001” CB Fail 1

“0x0000,0x0002” CB Fail 2

“0x0000,0x0004” VTS

“0x0000,0x0008” CTS

“0x0000,0x0010” Alarm FFail P342 and P343 only

“0x0000,0x0020” Alarm NPS P342 and P343 only

“0x0000,0x0040” Alarm V/Hz P342 and P343 only

“0x0000,0x0080” Alarm RTD 1 P342 and P343 only










“0x0002,0x0000”

“0x0004,0x0000”

“0x0008,0x0000”

“0x0010,0x0000”

“0x0020,0x0000”


Page 60 of 87


“0x0040,0x0000”

“0x0080,0x0000”

“0x0100,0x0000”

“0x0200,0x0000”

“0x0400,0x0000”

“0x0800,0x0000”

“0x1000,0x0000”

“0x2000,0x0000”

“0x4000,0x0000”

“0x8000,0x0000”

G88 ALARMS

0 Alarm Disabled

1 Alarm Enabled

G90 GROUP SELECTION

0 Group 1

1 Group 2

2 Group 3

3 Group 4

G93 COMMISSION TEST

0 No Operation

1 Apply Test

2 Remove Test

G94 COMMISSION TEST

0 No Operation

1 Apply Test

G95 SYSTEM FUNCTION LINKS

Bit 0 Trip led self reset (1 = enable self reset)

Bit 1 Not Used

Bit 2 Not Used

Bit 3 Not used

Bit 4 Not Used

Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G96 Bit Position ALARM INDEXED STRINGS

0 Battery Fail

1 Field Volt Fail

2 SG-opto Invalid

3 Prot’n Disabled

4 VT Fail Alarm

5 CTS Fail Alarm

6 CB Fail

7 I^ Maint Alarm

8 I^ Maint Lockout

9 CB OPs Maint

10 CB OPs Lock

11 CB Time Maint

12 CB Time Lockout

13 Fault Freq Lock


Page 61 of 87


14 CB Status Alarm

15 CB Trip Fail P341 only

16 CB Close Fail P341 only

17 Man CB Unhealthy P341 only

18 F out of Range P341 only

18 NPS Alarm P342 and P343 only

19 V/Hz Alarm P342 and P343 only

20 Field Fail Alarm P342 and P343 only

21 RTD Thermal Alm P342 and P343 only

22 RTD Open Cct P342 and P343 only

23 RTD short Cct P342 and P343 only

24 RTD Data Error P342 and P343 only

25 RTD Board Fail P342 and P343 only

26 Freq Prot Alm

27 Voltage Prot Alm

28 User Alarm 1

29 User Alarm 2

30 User Alarm 3

31 User Alarm 4

G98 COPY TO

0 No Operation

1 Group 1

2 Group 2

3 Group 3

4 Group 4

G99 CB CONTROL

0 Disabled

1 Local

2 Remote

3 Local+Remote

4 Opto

5 Opto+local

6 Opto+Remote

7 Opto+Rem+local

G101 GENERATOR DIFFERENTIAL FUNCTION SELECT

0 Disabled

1 Percentage Bias

2 High Impedance

G102 POWER FUNCTION SELECT

0 Disabled

1 Reverse

2 Low Forward

3 Over

G103 SYSTEM BACKUP FUNCTION SELECT

0 Disabled

1 Underimpedance

2 Volt controlled

3 Volt restrained


Page 62 of 87


G104 SYSTEM BACKUP VECTOR ROTATION

0 None

1 Delta-Star

G105 DEFINITE TIME OVERCURRENT SELECTION

0 Disabled

1 DT

G107 Modbus value+bit position START ELEMENTS 2


“0x0000,0x0001” Start V<1

“0x0000,0x0002” Start V<2

“0x0000,0x0004” Start V< A/AB

“0x0000,0x0008” Start V< B/BC

“0x0000,0x0010” Start V< C/CA

“0x0000,0x0020” Start V>1

“0x0000,0x0040” Start V>2

“0x0000,0x0080” Start V> A/AB

“0x0000,0x0100” Start V> B/BC

“0x0000,0x0200” Start V> C/CA

“0x0000,0x0400” Start F<1

“0x0000,0x0800” Start F<2

“0x0000,0x1000” Start F<3

“0x0000,0x2000” Start F<4

“0x0000,0x4000” Start F>1

“0x0000,0x8000” Start F>2

“0x0001,0x0000” Start V/Hz P342 and P343 only

“0x0002,0x0000” Start df/dt P341 only

“0x0004,0x0000”

“0x0008,0x0000”

“0x0010,0x0000”

“0x0020,0x0000”

“0x0040,0x0000”

“0x0080,0x0000”

“0x0100,0x0000”

“0x0200,0x0000”

“0x0400,0x0000”

“0x0800,0x0000”

“0x1000,0x0000”

“0x2000,0x0000”

“0x4000,0x0000”

“0x8000,0x0000”

G108 Bit position RTD OPEN CIRCUIT FLAGS

0 RTD 1 label

1 RTD 2 label

2 RTD 3 label

3 RTD 4 label

4 RTD 5 label

5 RTD 6 label

6 RTD 7 label

7 RTD 8 label

8 RTD 9 label

9 RTD 10 label


Page 63 of 87


G109 Bit position RTD SHORT CIRCUIT FLAGS

0 RTD 1 label

1 RTD 2 label

2 RTD 3 label

3 RTD 4 label

4 RTD 5 label

5 RTD 6 label

6 RTD 7 label

7 RTD 8 label

8 RTD 9 label

9 RTD 10 label

G110 Bit position RTD DATA ERROR

0 RTD 1 label

1 RTD 2 label

2 RTD 3 label

3 RTD 4 label

4 RTD 5 label

5 RTD 6 label

6 RTD 7 label

7 RTD 8 label

8 RTD 9 label

9 RTD 10 label

G111 IDMT CURVE TYPE

0 DT

1 IEC S Inverse

2 IEC V Inverse

3 IEC E Inverse

4 UK LT Inverse

5 IEEE M Inverse

6 IEEE V Inverse

7 IEEE E Inverse

8 US Inverse

9 US ST Inverse

G118 CB CONTROL LOGIC INPUT ASSIGNMENTS

0 None

1 52A

2 52B


Page 64 of 87

EVENT RECORD DATA FORMATEvent Text Additional Event Description Modbus Courier P341 P342 P34316 Chars Text Event Type Cell Ref Value

G13

Logic Inputs Change in Opto Input 5 0020 Binary Flag (8 bits) * *

Binary Flag (16 bits) *

Value contains new opto input status

Output Contacts Change in output contact status 4 0021 Binary Flag (7 bits) * *

Binary Flag (14 bits)

Value contains new output contact status

Alarm Events:

“Unsigned Integer (32 bits) Bit 31 Direction 1=ON, 0 = OFF”

Battery Fail ON/OFF Battery Fail 2/3 0022 1 * * *

Field Volt Fail ON/OFF Field Voltage Fail 2/3 0022 2 * * *

SG-opto Invalid ON/OFF Setting Group via opto invalid 2/3 0022 3 * * *

Prot’n Disabled ON/OFF Protection Disabled 2/3 0022 4 * * *

VT Fail Alarm ON/OFF VTS Alarm 2/3 0022 5 * * *

CT Fail Alarm ON/OFF CTS Alarm 2/3 0022 6 * * *

CB Fail Alarm ON/OFF CB Trip Fail Protection 0/1 0022 7 * * *

I^ Maint Alarm ON/OFF Broken Current Maintenance Alarm 2/3 0022 8 * * *

I^ Lockout Alarm ON/OFF Broken Current Lockout Alarm 2/3 0022 9 * * *

CB Ops Maint ON/OFF No of CB Ops Maintenance Alarm 2/3 0022 10 * * *

CB Ops Lockout ON/OFF No of CB Ops Maintenance Lockout 2/3 0022 11 * * *

CB Op Time Maint ON/OFF CB Op Time Maintenance Alarm 2/3 0022 12 * * *

CB Op Time Lock ON/OFF CB Op Time Lockout Alarm 2/3 0022 13 * * *

Fault Freq Lock ON/OFF Excessive Fault Frequency Lockout Alarm 2/3 0022 14 * * *

CB Status Alarm ON/OFF CB Status Alarm 0/1 0022 15 * * *

Man CB Trip Fail ON/OFF CB Failed to Trip 0/1 0022 16 *

Man CB Cls Fail ON/OFF CB Failed to Close 0/1 0022 17 *

Man CB Unhealthy ON/OFF No Healthy Control Close 0/1 0023 18 *

F out of range ON/OFF Frequency out of range 2/3 0022 19 *

NPS Alarm ON/OFF Negative Phase Sequence Alarm 0/1 0022 19 * *

V/Hz Alarm ON/OFF Volts Per Hz Alarm 0/1 0022 20 * *

Field Fail Alarm ON/OFF Field failure Alarm (Latched) 0/1 0022 21 * *

RTD Thermal Alm ON/OFF RTD thermal Alarm (Latched) 0/1 0022 22 * *

RTD Open Cct ON/OFF RTD open circuit failure (Latched) 0/1 0022 23 * *

RTD short Cct ON/OFF RTD short circuit failure (Latched) 0/1 0022 24 * *

RTD Data Error ON/OFF RTD data inconsistency error (Latched) 0/1 0022 25 * *

RTD Board Fail ON/OFF RTD Board failure (Latched) 0/1 0022 26 * *

Freq Prot Alm ON/OFF User definable frequency protection alarm (Latched) 0/1 0022 27 * * *

Voltage Prot Alm ON/OFF User definable voltage protection alarm (Latched) 0/1 0022 28 * * *

User Alarm 1 ON/OFF User Definable Alarm 1 (Latched) 0/1 0022 29 * * *

User Alarm 2 ON/OFF User Definable Alarm 2 (Latched) 0/1 0022 30 * * *

User Alarm 3 ON/OFF User Definable Alarm 3 (Self Reset) 2/3 0022 31 * * *

User Alarm 4 ON/OFF User Definable Alarm 4 (Self Reset) 2/3 0022 32 * * *

Protection Events:

“Unsigned Integer (32 bits) Bit 31 Direction 1=ON, 0 = OFF”

100% ST EF Trip ON/OFF 100% Stator Earth Fault Trip 6 0023 178 *

DeadMachine trip ON/OFF Dead machine protection Trip 6 0023 179 *

Gen Diff Trip ON/OFF Generator Differential trip 3ph 6 0023 180 *

Gen Diff Trip A ON/OFF Generator Differential Trip A 6 0023 181 *

Gen Diff Trip B ON/OFF Generator Differential Trip B 6 0023 182 *

Gen Diff Trip C ON/OFF Generator Differential Trip C 6 0023 183 *

Field Fail1 Trip ON/OFF Field failure Stage 1 start 6 0023 184 * *

Field Fail2 Trip ON/OFF Field failure Stage 2 start 6 0023 185 * *

NPS Trip ON/OFF Negative Phase Sequence Trip 6 0023 186 * *

Sys Back Trip ON/OFF System Backup Trip 3ph 6 0023 187 * *

Sys Back Trip A ON/OFF System Backup Trip A 6 0023 188 * *


Page 65 of 87

Event Text Additional Event Description Modbus Courier P341 P342 P34316 Chars Text Event Type Cell Ref Value

G13

Sys Back Trip B ON/OFF System Backup Trip B 6 0023 189 * *

Sys Back Trip C ON/OFF System Backup Trip C 6 0023 190 * *

V/Hz Trip ON/OFF Volts per Hz Trip 6 0023 191 * *

RTD 1 Trip ON/OFF RTD 1 TRIP 6 0023 192 * *










df/dt Trip ON/OFF Rate of change of frequency Trip 6 0023 202 *

Any RTD Trip ON/OFF Any RTD Trip 6 0023 202 * *

V Shift Trip ON/OFF Voltage vector shift trip 6 0023 203 *

IN>1 Trip ON/OFF 1st Stage EF Trip 6 0023 204 * * *

IN>2 Trip ON/OFF 2nd Stage EF Trip 6 0023 205 * * *

IN>3 Trip ON/OFF 3rd Stage EF Trip 6 0023 206 *

IN>4 Trip ON/OFF 4th Stage EF Trip 6 0023 207 *

IREF> Trip ON/OFF REF Trip 6 0023 208 * * *

ISEF>1 Trip ON/OFF 1st Stage SEF Trip 6 0023 209 * * *

ISEF>2 Trip ON/OFF 2nd Stage SEF Trip 6 0023 210 *

ISEF>3 Trip ON/OFF 3rd Stage SEF Trip 6 0023 211 *

ISEF>4 Trip ON/OFF 4th Stage SEF Trip 6 0023 212 *

VN>1 Trip ON/OFF 1st Stage Residual O/V Trip 6 0023 213 * * *

VN>2 Trip ON/OFF 2nd Stage Residual O/V Trip 6 0023 214 * * *

V<1 Trip ON/OFF 1st Stage Phase U/V Trip 3ph 6 0023 215 * * *

V<1 Trip A/AB ON/OFF 1st Stage Phase U/V Trip A/AB 6 0023 216 * * *

V<1 Trip B/BC ON/OFF 1st Stage Phase U/V Trip B/BC 6 0023 217 * * *

V<1 Trip C/CA ON/OFF 1st Stage Phase U/V Trip C/CA 6 0023 218 * * *

V<2 Trip ON/OFF 2nd Stage Phase U/V Trip 3ph 6 0023 219 * * *

V<2 Trip A/AB ON/OFF 2nd Stage Phase U/V Trip A/AB 6 0023 220 * * *

V<2 Trip B/BC ON/OFF 2nd Stage Phase U/V Trip B/BC 6 0023 221 * * *

V<2 Trip C/CA ON/OFF 2nd Stage Phase U/V Trip C/CA 6 0023 222 * * *

V>1 Trip ON/OFF 1st Stage Phase O/V Trip 3ph 6 0023 223 * * *

V>1 Trip A/AB ON/OFF 1st Stage Phase O/V Trip A/AB 6 0023 224 * * *

V>1 Trip B/BC ON/OFF 1st Stage Phase O/V Trip B/BC 6 0023 225 * * *

V>1 Trip C/CA ON/OFF 1st Stage Phase O/V Trip C/CA 6 0023 226 * * *

V>2 Trip ON/OFF 2nd Stage Phase O/V Trip 3ph 6 0023 227 * * *

V>2 Trip A/AB ON/OFF 2nd Stage Phase O/V Trip A/AB 6 0023 228 * * *

V>2 Trip B/BC ON/OFF 2nd Stage Phase O/V Trip B/BC 6 0023 229 * * *

V>2 Trip C/CA ON/OFF 2nd Stage Phase O/V Trip C/CA 6 0023 230 * * *

F<1 Trip ON/OFF Under frequency Stage 1 trip 6 0023 231 * * *




F>1 Trip ON/OFF Over frequency Stage 1 Trip 6 0023 235 * * *

F>2 Trip ON/OFF Over frequency Stage 2 Trip 6 0023 236 * * *

Power1 Trip ON/OFF Power stage 1 trip 6 0023 237 * * *

Power2 Trip ON/OFF Power stage 2 trip 6 0023 238 * * *

I>1 Trip ON/OFF 1st Stage O/C Trip 3ph 6 0023 239 * * *

I>1 Trip A ON/OFF 1st Stage O/C Trip A 6 0023 240 * * *

I>1 Trip B ON/OFF 1st Stage O/C Trip B 6 0023 241 * * *

I>1 Trip C ON/OFF 1st Stage O/C Trip C 6 0023 242 * * *


Page 66 of 87


G13

I>2 Trip ON/OFF 2nd Stage O/C Trip 3ph 6 0023 243 * * *

I>2 Trip A ON/OFF 2nd Stage O/C Trip A 6 0023 244 * * *

I>2 Trip B ON/OFF 2nd Stage O/C Trip B 6 0023 245 * * *

I>2 Trip C ON/OFF 2nd Stage O/C Trip C 6 0023 246 * * *

I>3 Trip ON/OFF 3rd Stage O/C Trip 3ph 6 0023 247 *

I>3 Trip A ON/OFF 3rd Stage O/C Trip A 6 0023 248 *

I>3 Trip B ON/OFF 3rd Stage O/C Trip B 6 0023 249 *

I>3 Trip C ON/OFF 3rd Stage O/C Trip C 6 0023 250 *

I>4 Trip ON/OFF 4th Stage O/C Trip 3ph 6 0023 251 *

I>4 Trip A ON/OFF 4th Stage O/C Trip A 6 0023 252 *

I>4 Trip B ON/OFF 4th Stage O/C Trip B 6 0023 253 *

I>4 Trip C ON/OFF 4th Stage O/C Trip C 6 0023 254 *

Any Start ON/OFF Any Start 6 0023 255 * * *

VN>1 Start ON/OFF 1st Stage Residual O/V Start 6 0023 256 * * *

VN>2 Start ON/OFF 2nd Stage Residual O/V Start 6 0023 257 * * *

V<1 Start ON/OFF 1st Stage Phase U/V Start 3ph 6 0023 258 * * *

V<1 Start A/AB ON/OFF 1st Stage Phase U/V Start A/AB 6 0023 259 * * *

V<1 Start B/BC ON/OFF 1st Stage Phase U/V Start B/BC 6 0023 260 * * *

V<1 Start C/CA ON/OFF 1st Stage Phase U/V Start C/CA 6 0023 261 * * *

V<2 Start ON/OFF 2nd Stage Phase U/V Start 3ph 6 0023 262 * * *

V<2 Start A/AB ON/OFF 2nd Stage Phase U/V Start A/AB 6 0023 263 * * *

V<2 Start B/BC ON/OFF 2nd Stage Phase U/V Start B/BC 6 0023 264 * * *

V<2 Start C/CA ON/OFF 2nd Stage Phase U/V Start C/CA 6 0023 265 * * *

V>1 Start ON/OFF 1st Stage Phase O/V Start 3ph 6 0023 266 * * *

V>1 Start A/AB ON/OFF 1st Stage Phase O/V Start A/AB 6 0023 267 * * *

V>1 Start B/BC ON/OFF 1st Stage Phase O/V Start B/BC 6 0023 268 * * *

V>1 Start C/CA ON/OFF 1st Stage Phase O/V Start C/CA 6 0023 269 * * *

V>2 Start ON/OFF 2nd Stage Phase O/V Start 3ph 6 0023 270 * * *

V>2 Start A/AB ON/OFF 2nd Stage Phase O/V Start A/AB 6 0023 271 * * *

V>2 Start B/BC ON/OFF 2nd Stage Phase O/V Start B/BC 6 0023 272 * * *

V>2 Start C/CA ON/OFF 2nd Stage Phase O/V Start C/CA 6 0023 273 * * *

Power1 Start ON/OFF Power Stage 1 start 6 0023 274 * * *

Power2 Start ON/OFF Power stage 1 start 6 0023 275 * * *

I>1 Start ON/OFF 1st Stage O/C Start 3ph 6 0023 276 * * *

I>1 Start A ON/OFF 1st Stage O/C Start A 6 0023 277 * * *

I>1 Start B ON/OFF 1st Stage O/C Start B 6 0023 278 * * *

I>1 Start C ON/OFF 1st Stage O/C Start C 6 0023 279 * * *

I>2 Start ON/OFF 2nd Stage O/C Start 3ph 6 0023 280 * * *

I>2 Start A ON/OFF 2nd Stage O/C Start A 6 0023 281 * * *

I>2 Start B ON/OFF 2nd Stage O/C Start B 6 0023 282 * * *

I>2 Start C ON/OFF 2nd Stage O/C Start C 6 0023 283 * * *

I>3 Start ON/OFF 3rd Stage O/C Start 3ph 6 0023 284 *

I>3 Start A ON/OFF 3rd Stage O/C Start A 6 0023 285 *

I>3 Start B ON/OFF 3rd Stage O/C Start B 6 0023 286 *

I>3 Start C ON/OFF 3rd Stage O/C Start C 6 0023 287 *

I>4 Start ON/OFF 4th Stage O/C Start 3ph 6 0023 288 *

I>4 Start A ON/OFF 4th Stage O/C Start A 6 0023 289 *

I>4 Start B ON/OFF 4th Stage O/C Start B 6 0023 290 *

I>4 Start C ON/OFF 4th Stage O/C Start C 6 0023 291 *

IN>1 Start ON/OFF 1st Stage EF#1 Start 6 0023 292 * * *

IN>2 Start ON/OFF 2nd Stage EF#1 Start 6 0023 293 * * *

IN>3 Start ON/OFF 3rd Stage EF#1 Start 6 0023 294 *

IN>4 Start ON/OFF 4th Stage EF#1 Start 6 0023 295 *

ISEF>1 Start ON/OFF 1st Stage SEF Start 6 0023 296 * * *

ISEF>2 Start ON/OFF 2nd Stage SEF Start 6 0023 297 *


Page 67 of 87


G13

ISEF>3 Start ON/OFF 3rd Stage SEF Start 6 0023 298 *

ISEF>4 Start ON/OFF 4th Stage SEF Start 6 0023 299 *

100% ST EF Start ON/OFF 100% Stator Earth Fault Start 6 0023 300 *

F<1 Start ON/OFF Under frequency Stage 1 START 6 0023 301 * * *




F>1 Start ON/OFF Over frequency Stage 1 START 6 0023 305 * * *

F>2 Start ON/OFF Over frequency Stage 2 START 6 0023 306 * * *

Bfail1 Trip 3ph ON/OFF tBF1 Trip 3Ph 6 0023 310 * * *

Bfail2 Trip 3ph ON/OFF tBF2 Trip 3Ph 6 0023 311 * * *

Control Trip ON/OFF Control Trip 6 0023 312 *

Control Close ON/OFF Control Close 6 0023 313 *

Close in Prog ON/OFF Control Close in Progress 6 0023 314 *

df/dt Start ON/OFF Rate of change of frequency Start 6 0023 318 *

V/Hz Start ON/OFF Volts per Hz Start 6 0023 324 * *

FFail1 Start ON/OFF Field failure Stage 1 start 6 0023 325 * *

FFail2 Start ON/OFF Field failure Stage 2 start 6 0023 326 * *

Sys Back Start ON/OFF System Backup Start 3Ph 6 0023 327 * *

Sys Back Start A ON/OFF System Backup Start A 6 0023 328 * *

Sys Back Start B ON/OFF System Backup Start B 6 0023 329 * *

Sys Back Start C ON/OFF System Backup Start C 6 0023 330 * *

RTD 1 Alarm ON/OFF RTD 1 Alarm 6 0023 331 * *










CB Open 3 ph ON/OFF 3 ph CB Open 6 0023 342 * * *

CB Closed 3 ph ON/OFF 3 ph CB Closed 6 0023 343 * * *

General Events Unsigned Integer (32 bits)

Alarms Cleared Relay Alarms Cleared 7 FFFF 0 * * *

Events Cleared Relay Event Records Cleared 7 0B01 1 * * *

Faults Cleared Relay Fault Records Cleared 7 0B02 2 * * *

Maint Cleared Relay Maintenance Records Cleared 7 0B03 3 * * *

PW Unlocked UI Control and Support Settings Changed 7 0002 4 * * *

PW Invalid UI Disturbance Recorder Settings Changed 7 0002 5 * * *

PW1 Modified UI Change to Protection Setting Group 1 7 0002 6 * * *

PW2 Modified UI Change to Protection Setting Group 2 7 0002 7 * * *

PW Expired UI Change to Protection Setting Group 3 7 0002 8 * * *

PW Unlocked F Change to Protection Setting Group 4 7 0002 9 * * *

PW Invalid F Active Group Selection Changed 7 0002 10 * * *

PW1 Modified F Password Unlocked via User Interface 7 0002 11 * * *

PW2 Modified F Invalid Password entered on User Interface 7 0002 12 * * *

PW Expired F Password unlock expired User Interface 7 0002 13 * * *

PW Unlocked R Password Unlocked via Front Port 7 0002 14 * * *

PW Invalid R Invalid Password entered on Front Port 7 0002 15 * * *

PW1 Modified R Password unlock expired Front Port 7 0002 16 * * *

PW2 Modified R Password Unlocked via Rear Port 7 0002 17 * * *

PW Expired R Invalid Password entered on Rear Port 7 0002 18 * * *

IRIG-B Active Password unlock expired Rear Port 7 0805 19 * * *


Page 68 of 87


G13

IRIG-B Inactive Password Level 1 Modified on User Interface 7 0805 20 * * *

Time Synch Password Level 1 Modified on Front Port 7 0801 21 * * *

C&S Changed Password Level 1 Modified on User Interface 7 FFFF 22 * * *

Dist Changed Password Level 2 Modified on User Interface 7 0904 23 * * *

Group 1 Changed Password Level 2 Modified on Front Port 7 0904 24 * * *

Group 2 Changed Password Level 2 Modified on User Interface 7 0904 25 * * *

Group 3 Changed IRIG-B Timesync Active (Valid Signal) 7 0904 26 * * *

Group 4 Changed IRIG-B Timesync Inactive (No Signal) 7 0904 27 * * *

Act Grp Changed Relay Clock Adjusted 7 0903 28 * * *

Indication Reset Relay Indications Reset 7 01FF 29 * * *

Power On Relay Powered Up 7 FFFF 30 * * *

Cell Ref Value Extraction Column Record Number

Fault Recorded Fault Records: 8 0100 0 B000 16bit UINT

Text Self Monitoring: Cell Ref Value Extraction Column Record Number

Maint Recorded Maintenance Records 9 FFFF 0 B100 16bit UINT

Maintenance Record Text: Description Continuous

Fast W’Dog Error Fast Watchdog Error * * *

Battery Failure Battery Failure * * * *

BBRAM Failure Battery Back RAM Failure * * * *

Field Volt Fail Field Voltage Failure * * * *

Bus Reset Error Bus Error * * *

Slow W’Dog Error Slow Watchdog Error * * *

SRAM Failure Bus SRAM Bus Failure * * * *

SRAM Failure Blk SRAM Block Failure * * * *

FLASH Failure Flash checksum Error * * * *

Code Verify Fail Software Code Verification Failure * * * *

EEPROM Failure EEPROM Failure * * * *

Software Failure Software Error * * * *

Hard Verify Fail Hardware Verification Error * * *

Non Standard General Error * * * *


Page 69 of 87

IEC60870-5-103: Interoperability Compatability Level 2

Physical Layer

Electrical Interface: EIA RS-485

Number of loads 1 for one protection equipment

Optical Interface (Order option)

Plastic Fibre BFOC/2.5 type connector

Transmission speed

User Setting: 9600 or 19200

Application Layer

More than one COMMON ADDRESS OF ASDU

Standard information numbers in monitor direction

ASDU TYP COT FUN INF Description GI Model Number Address InterpretationP341 P342 P343

System Functions(Monitor)

8 10 255 0 End of General Interrogration 0

6 8 255 0 Time Syncronisation 0

5 3 224 2 Reset FCB 0

5 4 224 3 Reset CU 0

5 5 224 4 Start/Restart 0

5 6 224 5 Power On 0

“Note 1: Indenfication message in ASDU 5: ALSTOM, Software ref P34x.”

Note 2: The Function type is a settable quantity.

Status Indications

1 “1,7,9,11,12,20,21” 16 Auto-recloser active

1 “1,7,9,11,12,20,21” 17 Tele-protection active

1 “1,7,9,11,12,20,21” 18 Protection active

1 “1,7,9,11,12,20,21” 224 19 LED Reset 0 Reset Indication

1 “9,11” 20 Monitor direction blocked

1 “9,11” 224 21 Test mode 0 Protection Disabled

1 “9,11” 22 Local parameter setting

1 “1,7,9,11,12,20,21” 224 23 Characteristic 1 0 Group 1 Active




1 “1,7,9,11” 224 27 Auxillary input 1 0 Opto Input 1

















Page 70 of 87


Supervision Indications

1 “1,7,9” 32 Measurand supervision I

1 “1,7,9” 33 Measurand supervision V

1 “1,7,9” 35 Phase sequence supervision

1 “1,7,9” 36 Trip circuit supervision

1 “1,7,9” 37 I>> back-up supervision

1 “1,7,9” 224 38 VT fuse failure 0 VT Supervision Indication

1 “1,7,9” 39 Teleprotection disturbed

1 “1,7,9” 46 Group warning

1 “1,7,9” 47 Group alarm

Earth Fault Indications

1 “1,7,9” 48 Earth Fault L1



1 “1,7,9” 51 Earth Fault Fwd

1 “1,7,9” 52 Earth Fault Rev

Fault Indications

2 “1,7,9” 224 64 Start /pickup L1 0 I>1 A Phase Start

2 “1,7,9” 224 65 Start /pickup L2 0 I>1 B Phase Start

2 “1,7,9” 224 66 Start /pickup L3 0 I>1 C Phase Start










2 “1,7,9” 224 64 Start /pickup L1 4 Ssytem Backup A Phase Start

2 “1,7,9” 224 65 Start /pickup L2 4 Ssytem Backup B Phase Start

2 “1,7,9” 224 66 Start /pickup L3 4 Ssytem Backup C Phase Start

2 “1,7,9” 224 67 Start /pickup N 0 IN>1 Start




2 “1,7,9” 224 67 Start /pickup N 4 ISEF>1 Start




2 “1,7,9” 224 67 Start /pickup N 8 VN>1 Start

2 “1,7,9” 224 67 Start /pickup N 9 VN>2 Start

2 “1,7,9” 224 67 Start /pickup N 10 100% Stator Earth fault Start

2 “1,7” 224 68 General Trip 0 Any Trip

2 “1,7” 224 68 General Trip 1 System Backup trip

2 “1,7” 224 68 General Trip 2 V<1 Trip

2 “1,7” 224 68 General Trip 3 V<2 Trip

2 “1,7” 224 68 General Trip 4 V>1 Trip

2 “1,7” 224 68 General Trip 5 V>2 Trip

2 “1,7” 224 68 General Trip 6 F<1 Trip




Page 71 of 87



2 “1,7” 224 68 General Trip 10 F>1 Trip

2 “1,7” 224 68 General Trip 11 F>2 Trip

2 “1,7” 224 68 General Trip 12 Power 1 Trip

2 “1,7” 224 68 General Trip 13 Power 2 Trip

2 “1,7” 224 68 General Trip 14 Field Failure 1 Trip

2 “1,7” 224 68 General Trip 15 Field Failure 2 Trip

2 “1,7” 224 68 General Trip 16 V/Hz Trip

2 “1,7” 224 68 General Trip 17 df/dt Trip

2 “1,7” 224 68 General Trip 18 Voltage Vector Shift Trip

2 “1,7” 224 68 General Trip 19 NPS Trip

2 “1,7” 224 68 General Trip 20 Restrictive Earth Fault Trip

2 “1,7” 224 68 General Trip 21 100% Sator Earth Fault Trip

2 “1,7” 224 68 General Trip 22 Generator Differential Trip

2 “1,7” 224 68 General Trip 23 Dead Machine Trip

2 “1,7” 224 68 General Trip 24 Any RTD Trip

2 “1,7” 224 69 Trip L1 0 I>1 Phase A Trip

2 “1,7” 224 70 Trip L2 0 I>1 Phase B Trip

2 “1,7” 224 71 Trip L3 0 I>1 Phase C Trip










2 “1,7” 224 69 Trip L1 4 System Backup Phase A Trip

2 “1,7” 224 70 Trip L2 4 SysBack Phase B Trip

2 “1,7” 224 71 Trip L3 4 SysBack Phase C Trip

2 “1,7” 72 Trip I>> (back up)

4 “1,7” 73 Fault Location in ohms

2 “1,7” 74 Fault forward

2 “1,7” 75 Fault reverse

2 “1,7” 76 Teleprotection signal sent

2 “1,7” 77 Teleprotection signal received

2 “1,7” 78 Zone 1

2 “1,7” 79 Zone 2

2 “1,7” 80 Zone 3

2 “1,7” 81 Zone 4

2 “1,7” 82 Zone 5

2 “1,7” 83 Zone 6

2 “1,7,9” 224 84 General Start 0 Any Start

2 “1,7,9” 224 84 General Start 1 System Backup Start

2 “1,7,9” 224 84 General Start 2 V<1 Start

2 “1,7,9” 224 84 General Start 3 V<2 Start

2 “1,7,9” 224 84 General Start 4 V>1 Start

2 “1,7,9” 224 84 General Start 5 V>2 Start

2 “1,7,9” 224 84 General Start 6 F<1 Start




2 “1,7,9” 224 84 General Start 10 F>1 Start

2 “1,7,9” 224 84 General Start 11 F>2 Start


Page 72 of 87


2 “1,7,9” 224 84 General Start 12 Power 1 start

2 “1,7,9” 224 84 General Start 13 Power 2 Start

2 “1,7,9” 224 84 General Start 14 Field Failure 1 Start

2 “1,7,9” 224 84 General Start 15 Field Failure 2 Start

2 “1,7,9” 224 84 General Start 16 V/Hz Start

2 “1,7,9” 224 84 General Start 17 df/dt Start

2 “1,7” 224 85 Breaker Failure 0 CB Fail Alarm

2 “1,7” 86 Trip measuring system L1



2 “1,7” 89 Trip measuring system E

2 “1,7” 224 90 Trip I> 0 I>1 trip

2 “1,7” 224 90 Trip I> 1 I>2 Trip

2 “1,7” 224 91 Trip I>> 0 I>3 Trip

2 “1,7” 224 91 Trip I>> 0 I>2 Trip

2 “1,7” 224 91 Trip I>> 1 I>4 Trip

2 “1,7” 224 92 Trip IN> 0 IN>1 Trip

2 “1,7” 224 92 Trip IN> 1 IN>2 Trip

2 “1,7” 224 92 Trip IN> 2 ISEF>1 Trip

2 “1,7” 224 92 Trip IN> 3 ISEF>2 Trip

2 “1,7” 224 92 Trip IN> 4 VN>1 Trip

2 “1,7” 224 93 Trip IN>> 0 IN>3 Trip

2 “1,7” 224 93 Trip IN>> 0 IN>2 Trip

2 “1,7” 224 93 Trip IN>> 1 IN>4 Trip

2 “1,7” 224 93 Trip IN>> 1 ISEF>1 Trip

2 “1,7” 224 93 Trip IN>> 2 ISEF>3 Trip

2 “1,7” 224 93 Trip IN>> 3 ISEF>4 Trip

2 “1,7” 224 93 Trip IN>> 4 VN>2 Trip

Auto-Reclose Indications (Monitor)

1 “1,7” 128 CB ‘on’ by A/R

1 “1,7” 129 CB ‘on’ by long time A/R

1 “1,7,9” 130 AR blocked

Measurands (Monitor)

3.1 “2,7” 144 Measurand I

3.2 “2,7” 145 “Measurands I,V”

3.3 “2,7” 146 “Measurands I,V,P,Q”

3.4 “2,7” 147 “Measurands IN,VEN”

9 “2,7” 224 148 “Measurands IL1,2,3,VL1,2,3,P,Q,f” 0

Generic Functions(Monitor)

10 “42,43” 240 Read Headings

10 “42,43” 241 Read attributes of all entries of a group

10 “42,43” 243 Read directory of entry

10 “1,2,7,9,11,12,42,43” 244 Real attribute of entry

10 10 245 End of GGI

10 “41,44” 249 Write entry with confirm

10 “40,41” 250 Write entry with execute

10 40 251 Write entry aborted


Page 73 of 87

Standard Information numbers in control direction


System Functions (Control)

7 9 0 Init General Interrogation 0

6 8 224 Time Syncronisation 255

General Commands

20 20 16 Auto-recloser on/off

20 20 17 Teleprotection on/off

20 20 18 Protection on/off

20 20 224 19 LED Reset 0 Reset Indications and latches

20 20 224 23 Activate characteristic 1 0 Group 1 Active




Generic Functions

21 42 240 Read headings of all defined groups

21 42 241 Read single attribute of all entries of a group

21 42 243 Read directory of single entry

21 42 244 Read attribute of sngle entry

21 9 245 Generic General Interrogation (GGI)

10 40 248 Write entry

10 40 249 Write with confirm

10 40 250 Write with execute

10 40 251 Write entry abort

* Note the value in this column is added to the station address to produce the common address of the ASDU

Basic Application Functions

Test Mode

Blocking of monitor direction

Disturbance data

Generic services

Private data

Miscellaneous

Max .MVAL = times rated value

Measurand 1.2 2.4

Current L1

Current L2

Current L3

Voltage L1-E

Voltage L2-E

Voltage L3-E

Active Power P

Reactive Power Q

Frequency f

Voltage L1-L2


Page 74 of 87

DDB No Source Description English Text P341 P342 P343

0 Output Condition Output Relay 1 Output Label 1 (Setting) * * *







7 Output Condition Output Relay 8 Output Label 8 (Setting) *







14 Unused

15 Unused

16 Unused

17 Unused

18 Unused

19 Unused

20 Unused

21 Unused

22 Unused

23 Unused

24 Unused

25 Unused

26 Unused

27 Unused

28 Unused

29 Unused

30 Unused

31 Unused

32 Opto Opto Input 1 Opto Label 1 (setting) * * *








40 Opto Opto Input 9 Opto Label 9 (setting) *








48 Unused

49 Unused

50 Unused

51 Unused

52 Unused

53 Unused

54 Unused


Page 75 of 87


55 Unused

56 Unused

57 Unused

58 Unused

59 Unused

60 Unused

61 Unused

62 Unused

63 Unused

64 Output Condition Programmable LED 1 LED 1 * * *








72 PSL Input to Relay Output Condition Relay 1 * * *







79 PSL Input to Relay Output Condition Relay 8 *







86 PSL Input to LED Output Condition LED Cond IN 1 * * *








94 PSL Input to Auxiliary Timer 1 Timer in 1 * * *








102 Auxiliary Timer Output from Auxiliary Timer 1 Timer out 1 * * *









Page 76 of 87


110 PSL Trigger for Fault Recorder Fault_REC_TRIG * * *

111 Group Selection Setting Group via opto invalid Alarm SG-opto Invalid * * *

112 Commission Test Test Mode Enabled Alarm Prot’n Disabled * * *

113 VT Supervision VTS Indication VT Fail Alarm * * *

114 CT Supervision CTS Indication CT Fail Alarm * * *

115 Breaker Fail Breaker Fail Any Trip CB Fail Alarm * * *

116 CB Monitoring Broken Current Maintenance Alarm I^ Maint Alarm * * *

117 CB Monitoring Broken Current Lockout Alarm I^ Lockout Alarm * * *

118 CB Monitoring No of CB Ops Maintenance Alarm CB Ops Maint * * *

119 CB Monitoring No of CB Ops Maintenance Lockout CB Ops Lockout * * *

120 CB Monitoring Excessive CB Op Time Maintenance Alarm CB Op Time Maint * * *

121 CB Monitoring Excessive CB Op Time Lockout Alarm CB Op Time Lock * * *

122 CB Monitoring Excessive Fault Frequency Lockout Alarm Fault Freq Lock * * *

123 CB Status CB Status Alarm (Invalid CB auxilliary contacts) CB Status Alarm * * *

124 CB Control CB Failed to Trip Alarm Man CB Trip Fail * * *

125 CB Control CB Failed to Close Alarm Man CB Cls Fail * * *

126 CB Control CB Unhealthy on Control Close Alarm Man CB Unhealthy * * *

127 Frequency Tracking Frequency out of range F out of range *

127 NPS Thermal Negative Phase Sequence Alarm NPS Alarm * *

128 Overfluxing Volts Per Hz Alarm V/Hz Alarm * *

129 Field Failure Field failure Alarm Field Fail Alarm * *

130 RTD Thermal RTD thermal Alarm RTD Thermal Alm * *

131 RTD Thermal RTD open circuit failure RTD Open Cct * *

132 RTD Thermal RTD short circuit failure RTD short Cct * *

133 RTD Thermal RTD data inconsistency error RTD Data Error * *

134 RTD Thermal RTD Board failure RTD Board Fail * *

135 PSL Frequency protection alarm Freq Prot Alm * * *

136 PSL Voltage protection alarm Voltage Prot Alm * * *

137 PSL User settable alarm 1 User Alarm 1 * * *




141 PSL Block System Backup Time Delay SysBack Timer Bk * *

142 PSL Block Phase Overcurrent Stage 1 time delay I>1 Timer Block * * *

143 PSL Block Phase Overcurrent Stage 2 time delay I>2 Timer Block * * *

144 PSL Block Phase Overcurrent Stage 3 time delay I>3 Timer Block *

145 PSL Block Phase Overcurrent Stage 4 time delay I>4 Timer Block *

146 PSL Block Earth Fault Stage 1 time delay IN>1 Timer Block * * *

147 PSL Block Earth Fault Stage 2 time delay IN>2 Timer Block * * *

148 PSL Block Earth Fault Stage 3 time delay IN>3 Timer Block *

149 PSL Block Earth Fault Stage 4 time delay IN>4 Timer Block *

150 PSL Block SEF Stage 1 time delay ISEF>1 Timer Blk * * *

151 PSL Block SEF Stage 2 time delay ISEF>2 Timer Blk *



154 PSL Logic Input Trip CB Trip CB *

155 PSL Logic Input Close CB Close CB *

156 PSL Block Residual Overvoltage Stage 1 time delay VN>1 Timer Blk * * *

157 PSL Block Residual Overvoltage Stage 2 time delay VN>2 Timer Blk * * *

158 PSL Block Phase Undervoltage Stage 1 time delay V<1 Timer Block * * *

159 PSL Block Phase Undervoltage Stage 2 time delay V<2 Timer Block * * *

160 PSL Block Phase Overvoltage Stage 1 time delay V>1 Timer Block * * *

161 PSL Block Phase Overvoltage Stage 4 time delay V>2 Timer Block * * *

162 PSL Block Underfrequency Stage 1 Timer F<1 Timer Block * * *



Page 77 of 87




166 PSL Block Overfrequency Stage 1 Timer F>1 Timer Block * * *

167 PSL Block Overfrequency Stage 2 Timer F>2 Timer Block * * *

168 PSL External Trip 3ph External Trip 3ph * * *

169 PSL 52-A (3 phase) CB Aux 3ph(52-A) * * *

170 PSL 52-B (3 phase) CB Aux 3ph(52-B) * * *

171 PSL CB Healthy CB Healthy * * *

172 PSL MCB/VTS opto MCB/VTS * * *

173 PSL Reset Manual CB Close Time Delay Reset Close Dly * * *

174 PSL Reset Latched Relays & LED’s Reset LEDs * * *

175 PSL Reset Lockout Opto Input Reset Lockout * * *

176 PSL Reset CB Maintenance Values reset All Values * * *

177 PSL Reset NPS Thermal State Reset I2 Thermal * *

178 100% Stator Earth Fault 100% Stator Earth Fault Trip 100% ST EF Trip *

179 Dead Machine Dead machine protection Trip DeadMachine trip *

180 Generator Differential Generator Differential trip 3ph Gen Diff Trip *

181 Generator Differential Generator Differential Trip A Gen Diff Trip A *

182 Generator Differential Generator Differential Trip B Gen Diff Trip B *

183 Generator Differential Generator Differential Trip C Gen Diff Trip C *

184 Field Failure Field failure Stage 1 start Field Fail1 Trip * *

185 Field Failure Field failure Stage 2 start Field Fail2 Trip * *

186 NPS Thermal Negative Phase Sequence Trip NPS Trip * *

187 System Backup System Backup Trip 3ph Sys Back Trip * *

188 System Backup System Backup Trip A Sys Back Trip A * *

189 System Backup System Backup Trip B Sys Back Trip B * *

190 System Backup System Backup Trip C Sys Back Trip C * *

191 Overfluxing Volts per Hz Trip V/Hz Trip * *

192 RTD Thermal RTD 1 TRIP RTD 1 Trip * *










202 df/ft Rate of change of frequency Trip df/dt Trip *

202 RTD Thermal Any RTD Trip Any RTD Trip * *

203 Voltage Vector Shift Voltage vector shift trip V Shift Trip *

204 Earth Fault 1st Stage EF Trip IN>1 Trip * * *

205 Earth Fault 2nd Stage EF Trip IN>2 Trip * * *

206 Earth Fault 3rd Stage EF Trip IN>3 Trip *

207 Earth Fault 4th Stage EF Trip IN>4 Trip *

208 Restricted Earth Fault REF Trip IREF> Trip * * *

209 Sensitive Earth Fault 1st Stage SEF Trip ISEF>1 Trip * * *

210 Sensitive Earth Fault 2nd Stage SEF Trip ISEF>2 Trip *

211 Sensitive Earth Fault 3rd Stage SEF Trip ISEF>3 Trip *

212 Sensitive Earth Fault 4th Stage SEF Trip ISEF>4 Trip *

213 Neutral Displacement 1st Stage Residual O/V Trip VN>1 Trip * * *

214 Neutral Displacement 2nd Stage Residual O/V Trip VN>2 Trip * * *

215 Under Voltage 1st Stage Phase U/V Trip 3ph V<1 Trip * * *

216 Under Voltage 1st Stage Phase U/V Trip A/AB V<1 Trip A/AB * * *

217 Under Voltage 1st Stage Phase U/V Trip B/BC V<1 Trip B/BC * * *


Page 78 of 87


218 Under Voltage 1st Stage Phase U/V Trip C/CA V<1 Trip C/CA * * *

219 Under Voltage 2nd Stage Phase U/V Trip 3ph V<2 Trip * * *

220 Under Voltage 2nd Stage Phase U/V Trip A/AB V<2 Trip A/AB * * *

221 Under Voltage 2nd Stage Phase U/V Trip B/BC V<2 Trip B/BC * * *

222 Under Voltage 2nd Stage Phase U/V Trip C/CA V<2 Trip C/CA * * *

223 Over Voltage 1st Stage Phase O/V Trip 3ph V>1 Trip * * *

224 Over Voltage 1st Stage Phase O/V Trip A/AB V>1 Trip A/AB * * *

225 Over Voltage 1st Stage Phase O/V Trip B/BC V>1 Trip B/BC * * *

226 Over Voltage 1st Stage Phase O/V Trip C/CA V>1 Trip C/CA * * *

227 Over Voltage 2nd Stage Phase O/V Trip 3ph V>2 Trip * * *

228 Over Voltage 2nd Stage Phase O/V Trip A/AB V>2 Trip A/AB * * *

229 Over Voltage 2nd Stage Phase O/V Trip B/BC V>2 Trip B/BC * * *

230 Over Voltage 2nd Stage Phase O/V Trip C/CA V>2 Trip C/CA * * *

231 Under Frequency Under frequency Stage 1 trip F<1 Trip * * *




235 Over Frequency Over frequency Stage 1 Trip F>1 Trip * * *

236 Over Frequency Over frequency Stage 2 Trip F>2 Trip * * *

237 Power Power stage 1 trip Power1 Trip * * *

238 Power Power stage 2 trip Power2 Trip * * *

239 Over Current 1st Stage O/C Trip 3ph I>1 Trip * * *

240 Over Current 1st Stage O/C Trip A I>1 Trip A * * *

241 Over Current 1st Stage O/C Trip B I>1 Trip B * * *

242 Over Current 1st Stage O/C Trip C I>1 Trip C * * *

243 Over Current 2nd Stage O/C Trip 3ph I>2 Trip * * *

244 Over Current 2nd Stage O/C Trip A I>2 Trip A * * *

245 Over Current 2nd Stage O/C Trip B I>2 Trip B * * *

246 Over Current 2nd Stage O/C Trip C I>2 Trip C * * *

247 Over Current 3rd Stage O/C Trip 3ph I>3 Trip *

248 Over Current 3rd Stage O/C Trip A I>3 Trip A *

249 Over Current 3rd Stage O/C Trip B I>3 Trip B *

250 Over Current 3rd Stage O/C Trip C I>3 Trip C *

251 Over Current 4th Stage O/C Trip 3ph I>4 Trip *

252 Over Current 4th Stage O/C Trip A I>4 Trip A *

253 Over Current 4th Stage O/C Trip B I>4 Trip B *

254 Over Current 4th Stage O/C Trip C I>4 Trip C *

255 All protection Any Start Any Start * * *

256 Neutral displacement 1st Stage Residual O/V Start VN>1 Start * * *

257 Neutral displacement 2nd Stage Residual O/V Start VN>2 Start * * *

258 Under Voltage 1st Stage Phase U/V Start 3ph V<1 Start * * *

259 Under Voltage 1st Stage Phase U/V Start A/AB V<1 Start A/AB * * *

260 Under Voltage 1st Stage Phase U/V Start B/BC V<1 Start B/BC * * *

261 Under Voltage 1st Stage Phase U/V Start C/CA V<1 Start C/CA * * *

262 Under Voltage 2nd Stage Phase U/V Start 3ph V<2 Start * * *

263 Under Voltage 2nd Stage Phase U/V Start A/AB V<2 Start A/AB * * *

264 Under Voltage 2nd Stage Phase U/V Start B/BC V<2 Start B/BC * * *

265 Under Voltage 2nd Stage Phase U/V Start C/CA V<2 Start C/CA * * *

266 Over Voltage 1st Stage Phase O/V Start 3ph V>1 Start * * *

267 Over Voltage 1st Stage Phase O/V Start A/AB V>1 Start A/AB * * *

268 Over Voltage 1st Stage Phase O/V Start B/BC V>1 Start B/BC * * *

269 Over Voltage 1st Stage Phase O/V Start C/CA V>1 Start C/CA * * *

270 Over Voltage 2nd Stage Phase O/V Start 3ph V>2 Start * * *

271 Over Voltage 2nd Stage Phase O/V Start A/AB V>2 Start A/AB * * *

272 Over Voltage 2nd Stage Phase O/V Start B/BC V>2 Start B/BC * * *


Page 79 of 87


273 Over Voltage 2nd Stage Phase O/V Start C/CA V>2 Start C/CA * * *

274 Power Power Stage 1 start Power1 Start * * *

275 Power Power stage 1 start Power2 Start * * *

276 Over Current 1st Stage O/C Start 3ph I>1 Start * * *

277 Over Current 1st Stage O/C Start A I>1 Start A * * *

278 Over Current 1st Stage O/C Start B I>1 Start B * * *

279 Over Current 1st Stage O/C Start C I>1 Start C * * *

280 Over Current 2nd Stage O/C Start 3ph I>2 Start * * *

281 Over Current 2nd Stage O/C Start A I>2 Start A * * *

282 Over Current 2nd Stage O/C Start B I>2 Start B * * *

283 Over Current 2nd Stage O/C Start C I>2 Start C * * *

284 Over Current 3rd Stage O/C Start 3ph I>3 Start *

285 Over Current 3rd Stage O/C Start A I>3 Start A *

286 Over Current 3rd Stage O/C Start B I>3 Start B *

287 Over Current 3rd Stage O/C Start C I>3 Start C *

288 Over Current 4th Stage O/C Start 3ph I>4 Start *

289 Over Current 4th Stage O/C Start A I>4 Start A *

290 Over Current 4th Stage O/C Start B I>4 Start B *

291 Over Current 4th Stage O/C Start C I>4 Start C *

292 Earth Fault 1st Stage EF Start IN>1 Start * * *

293 Earth Fault 2nd Stage EF Start IN>2 Start * * *

294 Earth Fault 3rd Stage EF Start IN>3 Start *

295 Earth Fault 4th Stage EF Start IN>4 Start *

296 Sensitive Earth Fault 1st Stage SEF Start ISEF>1 Start * * *

297 Sensitive Earth Fault 2nd Stage SEF Start ISEF>2 Start *

298 Sensitive Earth Fault 3rd Stage SEF Start ISEF>3 Start *

299 Sensitive Earth Fault 4th Stage SEF Start ISEF>4 Start *

300 100% Stator Earth Fault 100% Stator Earth Fault Start 100% ST EF Start *

301 Under Frequency Under frequency Stage 1 START F<1 Start * * *




305 Over Frequency Over frequency Stage 1 START F>1 Start * * *

306 Over Frequency Over frequency Stage 2 START F>2 Start * * *

307 VT Supervision VTS Fast Block VTS Fast Block * * *

308 VT Supervision VTS Slow Block VTS Slow Block * * *

309 CT Supervision CTS Block CTS Block * * *

310 Breaker failure tBF1 Trip 3Ph Bfail1 Trip 3ph * * *

311 Breaker failure tBF2 Trip 3Ph Bfail2 Trip 3ph * * *

312 CB Control Control Trip Control Trip *

313 CB Control Control Close Control Close *

314 CB Control Control Close in Progress Close in Prog *

315 Reconnection Reconnection Time Delay Output Reconnection *

316 Over Current “I> Blocked O/C Start, inhibited by CB Fail” I> BlockStart *

Over Current “IN/ISEF> Blocked O/C Start, inhibited by CB Fail” IN/SEF>Blk Start *

318 df/dt Rate of change of frequency Start df/dt Start *

319 Under Current IA< operate IA< Start * * *

320 Under Current IB< operate IB< Start * * *

321 Under Current IC< operate IC< Start * * *

322 Under Current ISEF< operate ISEF< Start * * *

323 Under Current IN< operate IN< Start * *

324 Overfluxing Volts per Hz Start V/Hz Start * *

325 Field Failure Field failure Stage 1 start FFail1 Start * *

326 Field Failure Field failure Stage 2 start FFail2 Start * *

327 System Backup System Backup Start 3Ph Sys Back Start * *


Page 80 of 87


328 System Backup System Backup Start A Sys Back Start A * *

329 System Backup System Backup Start B Sys Back Start B * *

330 System Backup System Backup Start C Sys Back Start C * *

331 RTD Thermal RTD 1 Alarm RTD 1 Alarm * *










341 CB Monitoring Composite lockout alarm Lockout Alarm * * *

342 CB Status Monitor 3 ph CB Open CB Open 3 ph * * *

343 CB Status Monitor 3 ph CB Closed CB Closed 3 ph * * *

344 Field Voltage Monitor Field Voltage Failure Field Volts Fail * * *

345 Poledead All Poles Dead (Hidden from PSL) * * *

346 Poledead Any Pole Dead (Hidden from PSL) * * *

347 Poledead Phase A Pole Dead (Hidden from PSL) * * *

348 Poledead Phase B Pole Dead (Hidden from PSL) * * *

349 Poledead Phase C Pole Dead (Hidden from PSL) * * *

350 VT Supervision Accelerate Ind (Hidden from PSL) * * *

351 VT Supervision Any Voltage Dependent (Hidden from PSL) * * *

352 VT Supervision Ia over threshold (Hidden from PSL) * * *

353 VT Supervision Ib over threshold (Hidden from PSL) * * *

354 VT Supervision Ic over threshold (Hidden from PSL) * * *

355 VT Supervision Va over threshold (Hidden from PSL) * * *

356 VT Supervision Vb over threshold (Hidden from PSL) * * *

357 VT Supervision Vc over threshold (Hidden from PSL) * * *

358 VT Supervision I2 over threshold (Hidden from PSL) * * *

359 VT Supervision V2 over threshold (Hidden from PSL) * * *

360 VT Supervision Superimposed Ia over threshold (Hidden from PSL) * * *

361 VT Supervision Superimposed Ib over threshold (Hidden from PSL) * * *

362 VT Supervision Superimposed Ic over threshold (Hidden from PSL) * * *

363 CB Failure CBF current prot SEF stage trip (Hidden from PSL) * * *

364 CB Failure CBF non current prot stage trip (Hidden from PSL) * * *

365 CB Failure CBF current Prot SEF Trip (Hidden from PSL) * * *

366 CB Failure CBF Non Current Prot Trip (Hidden from PSL) * * *

367 Frequency tracking Freq High (Hidden from PSL) * * *

368 Frequency tracking Freq Low (Hidden from PSL) * * *

369 Frequency tracking Freq Not found (Hidden from PSL) * * *

370 Frequency tracking Stop Freq Track (Hidden from PSL) * * *

371 Reconnection Reconnect LOM (unqualified) (Hidden from PSL) *

372 Reconnection Reconnect Disable (unqualified) (Hidden from PSL) *

373 Reconnection Reconnect LOM (Hidden from PSL) *

374 Reconnection Reconnect Disable (Hidden from PSL) *

375 Unused

376 Unused

377 Unused

378 Unused

379 Unused

380 Unused

381 Unused

382 Unused


Page 81 of 87


383 Unused

384 Unused

385 Unused

386 Unused

387 Unused

388 Unused

389 Unused

390 Unused

391 Unused

392 Unused

393 Unused

394 Unused

395 Unused

396 Unused

397 Unused

398 Unused

399 Unused

400 Unused

401 Unused

402 Unused

403 Unused

404 Unused

405 Unused

406 Unused

407 Unused

408 Unused

409 Unused

410 Unused

411 Unused

412 PSL PSL Internal Node 1 * * *



























Page 82 of 87


























































Page 83 of 87






















Page 84 of 87

MiCOM P341 Programmable Scheme Logic

Opto Input Mappings

Fault REC TRIGDDB #110

R3 Any TripDDB #002

Fault Record Trigger Mapping

L8 52bDDB #039

CB Aux 3ph (52–B)DDB #170

L7 52aDDB #038

CB Aux 3ph (52–A)DDB #169

L6 Ext. Prot. TripDDB #037

Ext. Trip 3phDDB #168

L5 ResetDDB #036

Reset LEDsDDB #174

L4 Block I>3&4DDB #035

I>3 Timer BlockDDB #144

I>4 Timer BlockDDB #145

L3 Block IN1>3&4DDB #034

IN>3 Timer BlkDDB #148

IN>4 Timer BlkDDB #149


Page 85 of 87


Output Relay Mappings

df/dt TripDDB #202

V Shift TripDDB #203

IN>1 TripDDB #204

ISEF>1 TripDDB #209

V>1 TripDDB #223

V>2 TripDDB #227

F<1 TripDDB #231

F<2 TripDDB #232

F<3 TripDDB #233

F<4 TripDDB #234

R3 Any TripDDB #002Dwell

100

01

IN>2 TripDDB #205

IN>3 TripDDB #206

IN>4 TripDDB #207

IREF> TripDDB #208

ISEF>2 TripDDB #210

ISEF>3 TripDDB #211

ISEF>4 TripDDB #212

VN>1 TripDDB #213

VN>2 TripDDB #214

V<1 TripDDB #215

V<2 TripDDB #219

F>1 TripDDB #235

F>2 TripDDB #236

Power1 TripDDB #237

Power2 TripDDB #238

I>1 TripDDB #239

I>2 TripDDB #243

I>3 TripDDB #247

I>4 TripDDB #251


Page 86 of 87


Output Relay Mappings

VT Fail AlarmDDB #113

CT Fail AlarmDDB #114

CB Fail AlarmDDB #115

I^ Maint AlarmDDB #116

CB Ops LockoutDDB #119

CB Op Time MaintDDB #120

Fault Freq LockDDB #122

CB Status AlarmDDB #123

Man CB Trip FailDDB #124

Man CB Cls FailDDB #125

Man CB UnhealthyDDB #126

F Out of RangeDDB #127

1

SG-opto InvalidDDB #111

Field volts failDDB #344

R4 General AlarmDDB #003Dwell

0

500

I^ Lockout AlarmDDB #117

CB Ops MaintDDB #118

CB Op Time LockDDB #121

R1 IN>1 StartDDB #000Straight

0

0

IN/SEF>Blk StartDDB #317

R2 IN>1 StartDDB #001Straight

0

0

I>Blk StartDDB #316

R5 CB FailDDB #004Dwell

100

0

Bfail1 Trip 3phDDB #310

R6 Control CloseDDB #005Straight

0

0

Control CloseDDB #313

R7 Control TripDDB #006Straight

0

0

Control TripDDB #312


Page 87 of 87


LED MappingsIN>1 TripDDB #204

IN>2 TripDDB #205

IN>3 TripDDB #206

IN>4 TripDDB #207

ISEF>1 TripDDB #209

ISEF>2 TripDDB #210

ISEF>3 TripDDB #211

ISEF>4 TripDDB #212

IREF> TripDDB #208

VN>1 TripDDB #213

VN>2 TripDDB #214

1 LED 1DDB #064Latching

I>1 TripDDB #239

I>2 TripDDB #243

I>3 TripDDB #247

I>4 TripDDB #251

1


LED 2DDB #065Latching

df/dt TripDDB #202

V Shift TripDDB #203


V<2 TripDDB #219


V<1 TripDDB #215

V>1 TripDDB #223

V>2 TripDDB #227

1

F<3 TripDDB #233


F<2 TripDDB #232

F<4 TripDDB #234

F>1 TripDDB #235

F<1 TripDDB #231

F>2 TripDDB #236

1

Power1 TripDDB #237

Power2 TripDDB #238


Any StartDDB #255 1 LED 8

DDB #071Non-

Latching



Appendix BExternal Connection Diagrams

TECHNICAL GUIDE TG8617AMiCOM P341 Volume 1INTERCONNECTION PROTECTION RELAY Appendix B

Page 1 of 2

Figure 1. External connection diagram: (40TE) interconnection protection for embedded generation –Sheet 1.

C13

C14

C15

A B C

Dire

ction

of f

orwa

rd cu

rrent

flow

P2

S1

P1

S2

AB

C N

ab

cn

da

dn

C1 C2 C3 C4 C5 C6 C7 C8 C9

Note

2

5A 1A 5A 1A 5A 1A 5A 1A

I A

I NSe

nsitiv

e

S1S2

C19

C20

C21

C23

C22

C24

V A V B V C V N

MiC

OM

P341

(Par

t)

I B I C

Note

s1.

(a) (b)

CT sh

ortin

g lin

ks

Pin te

rmina

l (PC

B typ

e)

50 O

HM B

NC

conn

ector

9-wa

y and

25-

way f

emale

D-ty

pe so

cket

2. C

T con

necti

ons a

re sh

own

1A co

nnec

ted a

nd a

re ty

pica

l only

3. T

his re

lay sh

ould

be a

ssign

ed to

any

trip

to e

nsur

e co

rrect

oper

atio

n of

the

prote

ctive

relay

Phas

e ro

tatio

n

D1 D2O

pto

1D3 D4

Opt

o 2

D5 D6O

pto

3D7 D8

Opt

o 4

D9 D10

Opt

o 5

D11

D12

Opt

o 6

D13

D14

Opt

o 7

D15

D16

Opt

o 8

D17

D18

Comm

onco

nnec

t

F17

F18 F16

SCN 1

Data

read

y

10Da

taac

know

ledge

16Ex

terna

lre

set

17Do

wnloa

dco

mman

d2

– 9D0

– D7

11, 1

2, 1

5, 1

3,20

, 21,

23,

24

T0 –

T7

19, 1

8, 2

2, 2

50V

14N

ot co

nnec

ted

Test/

down

load

SK2

F1

Seria

l por

t

F2AC

or D

CAu

x. su

pply

Vx

F7 F8 F9 F10

48V

dc fi

eldvo

ltage

out

Powe

r sup

ply ve

rsion

24

– 48V

(nom

inal)

dc o

nly.

MiC

OM

P341

(Par

t)

TX RX

Fibre

opt

icco

mmun

icatio

n(o

ptio

nal)

IRIG

-B Inp

ut(O

ptio

nal)

Case

earth

F11

F12

Wat

chdo

gco

ntact

F13

F14

Wat

chdo

gco

ntact

E1 E2Re

lay 1

E3 E4Re

lay 2

E5 E6Re

lay 3

Any t

ripN

ote 3

E7 E8Re

lay 4

E9 E10

E11

Relay

5E1

2E1

3E1

4Re

lay 6

E15

E16

E17

Relay

7E1

81 2

TX3 4

RX

5 60V

7 8RT

S9

CTS

SK1


Page 2 of 2

Figure 2. External connection diagram: (40TE) interconnection protection for embedded generation –Sheet 2.

MiC

OM

P341

(Par

t)

D1 D2O

pto

1

D3 D4O

pto

2

D5 D6O

pto

3

D7 D8O

pto

4

D9 D10

Opt

o 5

D11

D12

Opt

o 6

D13

D14

Opt

o 7

D15

D16

Opt

o 8

D17

D18

Comm

onco

nnec

t

F11

F12

Wat

chdo

gco

ntact

F13

F14

Wat

chdo

gco

ntact

E1 E2Re

lay 1

E3 E4Re

lay 2

E5 E6Re

lay 3

E7 E8Re

lay 4

E9 E10

E11

Relay

5E1

2E1

3E1

4Re

lay 6

E15

E16

E17

Relay

7E1

8

See

Note

3

Note

3.

This

relay

shou

ld be

assi

gned

to a

ny tr

ip to

ens

ure

corre

ctop

erat

ion

of th

e pr

otecti

ve re

lay

Custo

mer s

etting

Defa

ult se

tting

Settin

g G

roup

Settin

g G

roup

Block

IN>3

&4

Block

I>3&

4

Rese

t

Ext.

Prot.

Trip

52 –

a

52 –

b

Custo

mer s

etting

Defa

ult se

tting

IN>1

Sta

rt

I>1

Start

Any T

rip

Gen

eral

Alar

m

CB Fa

il

Contr

ol Cl

ose

Contr

ol Tri

p


Page 3 of 2

A L S T O M T & D P r o t e c t i o n & C o n t r o l L t d St Leonards Works, Stafford, ST17 4LX EnglandTel: 44 (0) 1785 223251 Fax: 44 (0) 1785 212232 Email: [email protected] Internet: www.alstom.com

©2000 ALSTOM T&D Protection & Control Ltd

Our policy is one of continuous product development and the right is reserved to supply equipment which may vary from that described.

Publication TG8617A Printed in England.

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