P34x_EN_T_F33

MiCOM P342, P343 GuidesGenerator Protection Relays

This version of the Technical Guide is specific to the following models

Model Number Software NumberP342------0070C P342------0070-A/B/CP343------0070C P343------0070-A/B/C

For other models / software versions, please contact ALSTOM T&D – Energy,Automation & Information for the relevant information.

(Software versions P342------0010*, P342------0020*, P342------0030*,P342------0040*, P342------0050* and P343------0010*, P343------0020*,P343------0030*, P343------0040*, P343------0050* are not supported by thismenu database, see TG8614A (0010), TG8614B (0020 – 0040),P34x/EN T/C11 (0050) and P34x/EN T/D22 (0060) for information on themenu database for these software versions)

Technical GuideMiCOM P342, P343

Generator Protection Relays

Volume 1

Technical Guide P34x/EN T/F33

MiCOM P342, P343

GENERATOR PROTECTION RELAYS

MICOM P342, P343

CONTENT

Issue Control

Handling of Electronic Equipment

Safety Instructions

Introduction P34x/EN IT/F33

Application Notes P34x/EN AP/F33

Relay Description P34x/EN HW/F33

Technical Data P34x/EN TD/F33

SCADA Communications P34x/EN CT/F33

Relay Menu Database P34x/EN GC/F33

External Connection Diagrams P34x/EN CO/F33

Hardware/Software Version History andCompatibility P34x/EN VC/E33

P34x/EN T/F33 Technical Guide

MiCOM P342, P343

Issue Control P34x/EN T/E33

MiCOM P342, P343

Manual Issue F33 Amendments completed 17.10.2003

Doc.

Ref.Section Page Description

- - -

Front coverSoftware version details amended to reflect latest relaysoftware, on the back of the front cover

IT ThroughoutAll references to appendices and chapters replaced withnew subdocument references

IT 3.4 11

Password protectionMinor amendment made to Access level column of tableLast row of table : As level 1 plus: and Password 2required swapped around

AP ThroughoutAll references to appendices and chapters replaced withnew subdocument references

16

Configuration column1st row of table added

AP 2.1 16 - 17 Last 3 rows added to table

AP 2.5.1.1 40

Voltage controlled overcurrent protection1st paragraph after equations : last sentence added

AP 2.5.2.1 44

Setting guidelines for under impedance functionThis title amended

45

Undervoltage protection function (27)Paragraph before note : last 2 DDB signals on last linechanged

AP 2.6 46 K = Time Multiplier Setting equation amended

AP 2.9 52

Overfrequency protection functionParagraph 5 : 3rd sentence added

AP 2.10.1.3 57

Power factor elementParagraph 2 : Last sentence re-written

AP 2.11 59

Negative phase sequence thermal protectionFigure 18 : new diagram added

AP 2.12.3 67

Reverse power protection function1st paragraph after table : (“Power1 DO Timer/Power2DO Timer”) moved from 5th sentence to 3rd sentence

AP 2.14 73

Residual overvoltage/neutral voltagedisplacement protection functionParagraph after Figure 21 : DDB signals changed in 2nd

sentence

AP 2.18 91

Overfluxing protectionParagraph 4 : DDB signal changed in 1st sentence

95

Resistive temperature device (RTD) thermalprotection1st paragraph after bullet points : last sentence re-written

AP 2.20 96 Last paragraph of section added

AP 2.22.7.2 115

DDB outputDDB signals in table changed

P34x/EN T/E33 Technical GuideIssue Control

MiCOM P342, P343


Doc.


AP 2.24.2 122

Reset mechanisms for breaker fail timersLast row of 2nd table added

AP 2.24.3.1 123

Breaker fail timer settingsTypical delay data in undercurrent elements row of tablechanged

AP 2.24.4 123

Breaker fail undercurrent settingsParagraphs 3 and 4 added

AP 2.27 127

Current loop inputs and outputsNew section added

AP 2.27.1 127 - 129

Current loop inputsNew section added

AP 2.27.2 129 - 130

Setting guidelines for current loop inputsNew section added

AP 2.27.3 130 - 135

Current loop outputsNew section added

AP 2.27.4 135

Setting guidelines for current loop outputsNew section added

145

Circuit breaker condition monitoring featuresData in 1st table : deleted and changed

145 - 146 2nd table re-writtenAP 3.5.1 146 Paragraphs after 2nd table : added

AP 3.5.2 146

Setting guidelinesNew section added

AP 3.5.2.1 146

Setting the Σ Ι^ thresholdsNew section added

AP 3.5.2.2 146 - 147

Setting the number of operations thresholdsNew section added

AP 3.5.2.3 147

Setting the operating time thresholdsNew section added

AP 3.5.2.4 147

Setting the excessive fault frequency thresholdsNew section added

Relay alarm conditionsData in table re-written

AP 3.7.3 154 Last paragraph of section : added

AP 3.11 164

Control inputsLast paragraph of section : added

HW ThroughoutAll references to appendices and chapters replaced withnew subdocument references

HW 2.4.2 9

Output relay boardParagraph 1 : words two and six swapped around

Issue Control P34x/EN T/E33

MiCOM P342, P343


Doc.


HW 2.9 11 - 12

Current loop input output board (CLIO)New section added

HW 4.1.3 18

Platform software initialisation & monitoringParagraph 1 : minor additions to 1st sentence

HW 4.2 19

Continuous self-testingLast bullet point : addedLast paragraph : minor additions to 2nd sentence

TD ThroughoutAll references to appendices and chapters replaced withnew subdocument references

TD 1.1 7

CurrentsData changed in 1st table

TD 1.2 7

VoltagesData changed in 1st table

TD 1.6 8

Output relay contactsParagraph 1 : words two and six swapped around

TD 10.18 38

Negative phase sequence thermal (46)Data in table amended

TD 10.22 40

Pole slipping (78) P343Data in table amended

TD 10.23 41

Thermal overload (49)This title amendedData in table amended

TD 13.3 44 - 47

Current loop input and outputs (CLIO)New section added

TD 13.3.1 47

AccuracyNew section added

TD 13.3.2 47

PerformanceNew section added

CT ThroughoutAll references to appendices and chapters replaced withnew subdocument references

GC - -

Relay menu databaseAmended to reflect latest relay software

CO - -

External connection diagramsAdditional diagrams added

VC - -

Hardware/software version history andcompatibilityPresented in new layout and updated to reflect latest relaysoftware

P34x/EN T/E33 Technical GuideIssue Control

MiCOM P342, P343

HANDLING OF ELECTRONIC EQUIPMENT

A person’s normal movements can easily generate electrostatic potentials of severalthousand volts. Discharge of these voltages into semiconductor devices whenhandling circuits can cause serious damage, which often may not be immediatelyapparent but the reliability of the circuit will have been reduced.

The electronic circuits of AREVA T&D are immune to the relevant levels of electrostaticdischarge 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 semiconductordevices. However, if it becomes necessary to withdraw a module, the followingprecautions should be taken to preserve the high reliability and long life for which theequipment has been designed and manufactured.

1. Before removing a module, ensure that you are a same electrostatic potentialas the equipment by touching the case.

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

3. Do not pass the module to any person without first ensuring that you are bothat the same electrostatic potential. Shaking hands achieves equipotential.

4. Place the module on an antistatic surface, or on a conducting surface which isat the same potential as yourself.

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

More information on safe working procedures for all electronic equipment can befound in BS5783 and IEC 60147-0F.

If you are making measurements on the internal electronic circuitry of an equipmentin service, it is preferable that you are earthed to the case with a conductive wriststrap.

Wrist straps should have a resistance to ground between 500k – 10M ohms. If awrist strap is not available you should maintain regular contact with the case toprevent the build up of static. Instrumentation which may be used for makingmeasurements should be earthed to the case whenever possible.

AREVA T&D strongly recommends that detailed investigations on the electroniccircuitry, or modification work, should be carried out in a Special Handling Area suchas described in BS5783 or IEC 60147-0F.

CONTENT

1. SAFETY SECTION 3

1.1 Health and safety 3

1.2 Explanation of symbols and labels 3

2. INSTALLING, COMMISSIONING AND SERVICING 3

3. EQUIPMENT OPERATING CONDITIONS 4

3.1 Current transformer circuits 4

3.2 External resistors 4

3.3 Battery replacement 4

3.4 Insulation and dielectric strength testing 4

3.5 Insertion of modules and pcb cards 4

3.6 Fibre optic communication 5

4. OLDER PRODUCTS 5

5. DECOMMISSIONING AND DISPOSAL 5

6. TECHNICAL SPECIFICATIONS 6

1. SAFETY SECTION

This Safety Section should be read before commencing any work on theequipment.

1.1 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 them ina safe condition. It is assumed that everyone who will be associated with theequipment will be familiar with the contents of the Safety Section.

1.2 Explanation of symbols and labels

The meaning of symbols and labels may be used on the equipment or in the productdocumentation, 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 beused for a protective/safety earthterminal if that terminal is part of aterminal block or sub-assemblye.g. power supply.

*NOTE: THE TERM EARTH USED THROUGHOUT THE PRODUCT DOCUMENTATION IS THEDIRECT EQUIVALENT OF THE NORTH AMERICAN TERM GROUND.

2. INSTALLING, COMMISSIONING AND SERVICING

Equipment connections

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

Terminals exposed during installation, commissioning and maintenance may presenta 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 electrical shock or energy hazards.

Voltage and current connections should be made using insulated crimp terminationsto ensure that terminal block insulation requirements are maintained for safety. Toensure that wires are correctly terminated, the correct crimp terminal and tool for thewire 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 2.5mm2, unless otherwise stated in thetechnical 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)

− Remove front plate plastic film protection

− Remove insulating strip from battery compartment

3. EQUIPMENT OPERATING CONDITIONS

The equipment should be operated within the specified electrical and environmentallimits.

3.1 Current transformer circuits

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

3.2 External resistors

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

3.3 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.

3.4 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.

3.5 Insertion of modules and pcb cards

These must not be inserted into or withdrawn from equipment whist it is energisedsince this may result in damage.

3.6 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.

4. OLDER PRODUCTS

Electrical adjustments

Equipments which require direct physical adjustments to their operating mechanismto change current or voltage settings, should have the electrical power removedbefore making the change, to avoid any risk of electrical shock.

Mechanical adjustments

The electrical power to the relay contacts should be removed before checking anymechanical settings, to avoid any risk of electric shock.

Draw out case relays

Removal of the cover on equipment incorporating electromechanical operatingelements, may expose hazardous live parts such as relay contacts.

Insertion and withdrawal of extender cards

When using an extender card, this should not be inserted or withdrawn from theequipment whilst it is energised. This is to avoid possible shock or damage hazards.Hazardous live voltages may be accessible on the extender card.

Insertion and withdrawal of heavy current test plugs

When using a heavy current test plug, CT shorting links must be in place beforeinsertion or removal, to avoid potentially lethal voltages.

5. DECOMMISSIONING AND DISPOSAL

Decommissioning: The auxiliary supply circuit in the relay may include capacitorsacross the supply or to earth. To avoid electric shock or energyhazards, after completely isolating the supplies to the relay (bothpoles of any dc supply), the capacitors should be safelydischarged via the external terminals prior to decommissioning.

Disposal: It is recommended that incineration and disposal to watercourses is avoided. The product should be disposed of in a safemanner. Any products containing batteries should have themremoved before disposal, taking precautions to avoid shortcircuits. Particular regulations within the country of operation,may apply to the disposal of lithium batteries.

6. TECHNICAL SPECIFICATIONS

Protective fuse rating

The recommended maximum rating of the external protective fuse for this equipmentis 16A, Red Spot type or equivalent, unless otherwise stated in the technical datasection of the product documentation.

Insulation class: IEC 601010-1 : 1990/A2 : 2001Class IEN 61010-1: 2001Class I

This equipment requires aprotective (safety) earthconnection to ensure usersafety.

InsulationCategory(Overvoltage):

IEC 601010-1 : 1990/A2 : 1995Category IIIEN 61010-1: 2001Category III

Distribution level, fixedinsulation. Equipment in thiscategory is qualification testedat 5kV peak, 1.2/50µs,500Ω, 0.5J, between all supplycircuits and earth and alsobetween independent circuits.

Environment: IEC 601010-1 : 1990/A2 : 1995Pollution degree 2

EN 61010-1: 2001Pollution degree 2

Compliance is demonstratedby reference to generic safetystandards.

Product Safety: 72/23/EEC

EN 61010-1: 2001EN 60950-1: 2002

Compliance with the EuropeanCommission Low VoltageDirective.

Compliance is demonstratedby reference to generic safetystandards.


MiCOM P342, P343

INTRODUCTION

P34x/EN IT/F33 Introduction

MiCOM P342, P343


MiCOM P342, P343 Page 1/28

CONTENT

1. INTRODUCTION TO MICOM 3

2. INTRODUCTION TO MiCOM GUIDES 4

3. USER INTERFACES AND MENU STRUCTURE 6

3.1 Introduction to the relay 6

3.1.1 Front panel 6

3.1.2 Relay rear panel 7

3.2 Introduction to the user interfaces and settings options 8

3.3 Menu structure 9

3.3.1 Protection settings 10

3.3.2 Disturbance recorder settings 11

3.3.3 Control and support settings 11

3.4 Password protection 11

3.5 Relay configuration 12

3.6 Front panel user interface (keypad and LCD) 12

3.6.1 Default display and menu time-out 13

3.6.2 Menu navigation and setting browsing 14

3.6.3 Password entry 14

3.6.4 Reading and clearing of alarm messages and fault records 14

3.6.5 Setting changes 15

3.7 Front communication port user interface 16

3.8 Rear communication port user interface 17

3.8.1 Courier communication 18

3.8.2 MODBUS communication 20

3.8.3 IEC 60870-5 CS 103 communication 21

3.8.4 DNP 3.0 Communication 23

3.9 Second rear communication port 24


Page 2/28 MiCOM P342, P343

Figure 1: Relay front view 6

Figure 2: Relay rear view 8

Figure 3: Menu structure 10

Figure 4: Front panel user interface 13

Figure 5: Front port connection 16

Figure 6: PC – relay signal connection 17

Figure 7: Remote communication connection arrangements 19

Figure 8: Second rear port k-bus application 26

Figure 9: Second rear port EIA(RS)485 example 27

Figure 10: Second rear port EIA(RS)232 example 27



1. INTRODUCTION TO MICOM

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

Central to the MiCOM concept is flexibility.

MiCOM provides the ability to define an application solution and, through extensivecommunication capabilities, to integrate it with your power supply control 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, visit our website:

www.areva-td.com



2. INTRODUCTION TO MiCOM GUIDES

The guides provide a functional and technical description of the MiCOM protectionrelay and a comprehensive set of instructions for the relay’s use and application.

Divided into two volumes, as follows:

Volume 1 – Technical Guide, includes information on the application of the relay anda technical description of its features. It is mainly intended for protection engineersconcerned with the selection and application of the relay for the protection of thepower 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 section content within each volume is summarised below:

Volume 1 Technical Guide


Safety Section

P34x/EN IT Introduction

A guide to the different user interfaces of the protection relay describing how to startusing the relay.

P34x/EN AP Application Notes

Comprehensive and detailed description of the features of the relay including boththe protection elements and the relay’s other functions such as event and disturbancerecording, fault location and programmable scheme logic. This section includes adescription of common power system applications of the relay, calculation of suitablesettings, some typical worked examples, and how to apply the settings to the relay.

P34x/EN HW Relay Description

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

P34x/EN TD Technical Data

Technical data including setting ranges, accuracy limits, recommended operatingconditions, ratings and performance data. Compliance with technical standards isquoted where appropriate.

P34x/EN CT Communications and Interface Guide

This section provides detailed information regarding the communication interfaces ofthe relay, including a detailed description of how to access the settings databasestored within the relay. The section also gives information on each of thecommunication protocols that can be used with the relay, and is intended to allow theuser to design a custom interface to a SCADA system.

P34x/EN GC Relay Menu Database: User interface/Courier/MODBUS/IEC60870-5-103/DNP 3.0

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



P34x/EN CO External Connection Diagrams

All external wiring connections to the relay.

P34x/EN VC Hardware / Software Version History and Compatibility

Volume 2 Operation Guide


Safety Section

P34x/EN IT Introduction

A guide to the different user interfaces of the protection relay describing how to startusing the relay.

P34x/EN IN Installation

Recommendations on unpacking, handling, inspection and storage of the relay. Aguide to the mechanical and electrical installation of the relay is providedincorporating earthing recommendations.

P34x/EN CM Commissioning and Maintenance

Instructions on how to commission the relay, comprising checks on the calibrationand functionality of the relay. A general maintenance policy for the relay is outlined.

P34x/EN PR Problem Analysis

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

P34x/EN GC Relay Menu Database: User interface/Courier/MODBUS/IEC 60870-5-103/DNP 3.0

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

P34x/EN CO External Connection Diagrams

All external wiring connections to the relay.

P34x/EN VC Hardware / Software Version History and Compatibility

Repair Form



3. USER INTERFACES AND MENU STRUCTURE

The settings and functions of the MiCOM protection relay can be accessed both fromthe front panel keypad and LCD, and via the front and rear communication ports.Information on each of these methods is given in this section to describe how to getstarted 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 panel canbe provided by an optional transparent front cover. With the cover in place read onlyaccess to the user interface is possible. Removal of the cover does not compromisethe environmental withstand capability of the product, but allows access to the relaysettings. When full access to the relay keypad is required, for editing the settings, thetransparent cover can be unclipped and removed when the top and bottom coversare open. If the lower cover is secured with a wire seal, this will need to be removed.Using the side flanges of the transparent cover, pull the bottom edge away from therelay front panel until it is clear of the seal tab. The cover can then be movedvertically down to release the two fixing lugs from their recesses in the front panel.

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Figure 1: Relay front view



Note: *May vary according to relay type/model

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 (), 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 therelay (up to 15m distance) via an EIA(RS)232 serial data connection.

− a 25-pin female D-type port providing internal signal monitoring and highspeed local 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 to indicatethe 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 may betriggered by a fault, event or maintenance record. The LED will flash until the alarmshave been accepted (read), after which the LED will change to constant illumination,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 be onat all times. It will be extinguished if the relay’s self-test facilities indicate that there isan error with the relay’s hardware or software. The state of the healthy LED isreflected 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 the relay.Also connected at the rear is the twisted pair wiring for the rear EIA(RS)485communication 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 section P34x/EN CO/E33 for complete connectiondetails.

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,IEC 60870-5-103 or DNP3.0. The protocol for the rear port must be specifiedwhen the relay is ordered.

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




Keypad/LCD

Courier MODBUSIEC870-5-

103DNP3.0

Display & modification ofall settings • • •

Digital I/O signal status • • • • •

Display/extraction ofmeasurements • • • • •

Display/extraction of faultrecords • • •

Extraction of disturbancerecords • • •

Programmable schemelogic settings •

Reset of fault & alarmrecords • • • • •

Clear event & fault records • • • •

Time synchronisation • • • •

Control commands • • • • •

Table 1

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 column containsthe heading which describes the settings contained within that column. Movementbetween the columns of the menu can only be made at the column heading level. Acomplete list of all of the menu settings is given in section P34x/EN GC/E33 of themanual.




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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 been confirmed that thenew settings are to be adopted. This technique is employed to provide extra security,and so that several setting changes that are made within a group of protectionsettings will all take effect at the same time.

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, and isused 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 that triggerthe 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 is enableddetermines which of the relay’s settings can be changed and iscontrolled by entry of two different passwords. The levels of access are summarisedin Table 2.

Access level Operations enabled

Level 0 No password required

Read access to all settings, alarms, eventrecords and fault records

Level 1Password 1 or 2 required

As level 0 plus:Control commands, e.g.circuit breaker open/close. Reset of fault and alarm conditions. Reset LEDs. Clearing of event and fault records.

Level 2Password 2 required

As level 1 plus: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 ‘System data’




column of the menu. The level of access is independently enabled for each interface,that is to say if level 2 access is enabled for the rear communication port, the frontpanel access will remain at level 0 unless the relevant password is entered at the frontpanel. The access level enabled by the password entry will time-out independentlyfor each interface after a period of inactivity and revert to the default level. If thepasswords are lost an emergency password can be supplied - contact AREVA T&Dwith the relay’s serial number. The current level of access enabled for an interfacecan be determined by examining the 'Access level' cell in the 'System data' column,the access level for the front panel User Interface (UI), can also be found as one ofthe 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 level 1, 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 (notethat 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 disable manyof the functions of the relay. The settings associated with any function that is disabledare made invisible, i.e. they are not shown in the menu. To disable a functionchange 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 settings tobe copied to another group.

To do this firstly set the ‘Copy from’ cell to the protection setting group to be copied,then set the ‘Copy to’ cell to the protection group where the copy is to be placed. Thecopied settings are initially placed in the temporary scratchpad, and will only be usedby 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 they havebeen 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 master station.

3.6 Front panel user interface (keypad and LCD)

When the keypad is exposed it provides full access to the menu options of the relay,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 value




changes and menu navigation; the longer the key is held depressed, the faster therate of change or movement becomes.

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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 been confirmedwill 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, from thedefault display the different default display options can be scrolled through using theand keys. However the menu selected default display will be restored followingthe menu time-out elapsing. Whenever there is an uncleared alarm present in therelay (e.g. fault record, protection alarm, control alarm etc.) the default display willbe 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 shown inFigure 4. Thus, starting at the default display the key will display the first columnheading. To select the required column heading use the and keys. The settingdata 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[up arrow symbol] key down or by a single press of the clear key . It is onlypossible to move across columns at the column heading level. To return to thedefault display press the key or the clear key from any of the columnheadings. It is not possible to go straight to the default display from within one of thecolumn cells using the auto-repeat facility of the key, as the auto-repeat will stopat the column heading. To move to the default display, the key must be releasedand 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 shownabove

A flashing cursor will indicate which character field of the password may be changed.Press the and keys to vary each character between A and Z. To movebetween the character fields of the password, use the and keys. The password isconfirmed by pressing the enter key . The display will revert to ‘Enter Password’ ifan incorrect password is entered. At this point a message will be displayed indicatingwhether a correct password has been entered and if so what level of access has beenunlocked. If this level is sufficient to edit the selected setting then the display willreturn to the setting page to allow the edit to continue. If the correct level ofpassword has not been entered then the password prompt page will be returned to.To escape from this prompt press the clear key . Alternatively, the password canbe entered using the ‘Password’ cell of the ‘System data’ 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 instead 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 default displayand by the yellow alarm LED flashing. The alarm messages can either be self-resetting or latched, in which case they must be cleared manually. To view the alarmmessages press the read key . When all alarms have been viewed, but not




cleared, the alarm LED will change from flashing to constant illumination and thelatest fault record will be displayed (if there is one). To scroll through the pages ofthis 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 ; to return to the alarms/faults present displayand leave the alarms uncleared, press . Depending on the password configurationsettings, it may be necessary to enter a password before the alarm messages can becleared (see section on password entry). When the alarms have been cleared theyellow alarm LED will extinguish, as will the red trip LED if it was illuminated followinga trip.

Alternatively it is possible to accelerate the procedure, once the alarm viewer hasbeen entered using the key, the key can be pressed, this will move the displaystraight to the fault record. Pressing again will move straight to the alarm resetprompt where pressing 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 flashing cursoron the LCD to indicate that the value can be changed. This will only happen if theappropriate password has been entered, otherwise the prompt to enter a passwordwill appear. The setting value can then be changed by pressing the or keys. If thesetting to be changed is a binary value or a text string, the required bit or character tobe changed must first be selected using the and keys. When the desired newvalue has been reached it is confirmed as the new setting value by pressing. Alternatively, the new value will be discarded either if the clear button ispressed or if the menu time-out occurs.

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

Update settings?Enter or clear

Pressing will result in the new settings being adopted, pressing 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 after theyare 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 connector locatedunder the bottom hinged cover. It provides EIA(RS)232 serial data communicationand is intended for use with a PC locally to the relay (up to 15m distance) as shownin Figure 5. This port supports the Courier communication protocol only. Courier isthe communication language developed by AREVA T&D to allow communication withits range of protection relays. The front port is particularly designed for use with therelay settings program MiCOM S1 which is a Windows 98/NT based softwarepackage.

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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

None of the other pins are connected in the relay. The relay should be connected tothe serial port of a PC, usually called COM1 or COM2. PCs are normally DataTerminal Equipment (DTE) devices which have a serial port pin connection as below(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 to theRx pin on the PC, and the Rx pin on the relay must be connected to the Tx pin on thePC, 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. onethat connects pin 2 to pin 2, pin 3 to pin 3, and pin 5 to pin 5. Note that a commoncause of difficulty with serial data communication is connecting Tx to Tx and Rx to Rx.




This could happen if a ‘cross-over’ serial connector is used, i.e. one that connects pin2 to pin 3, and pin 3 to pin 2, or if the PC has the same pin configuration as therelay.

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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 Courier

Baud rate 19,200 bits/s

Courier address 1

Message 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 messages arereceived on the front port for 15 minutes then any password access level that hasbeen enabled will be revoked.

3.8 Rear communication port user interface

The rear port can support one of four communication protocols (Courier, MODBUS,DNP3.0, IEC 60870-5-103), the choice of which must be made when the relay isordered. The rear communication port is provided by a 3-terminal screw connectorlocated on the back of the relay. See section P34x/EN CO/E33 for details of theconnection terminals. The rear port provides K-Bus/EIA(RS)485 serial datacommunication and is intended for use with a permanently-wired connection to aremote control centre. Of the three connections, 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, IEC 60870-5-103 and DNP3.0 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 ‘Commssettings’ cell in the ‘Configuration’ column is set to ‘Visible’, then move to the‘Communications’ column. The first cell down the column shows the communicationprotocol being used by the rear port.




3.8.1 Courier communication

Courier is the communication language developed by AREVA T&D to allow remoteinterrogation of its range of protection relays. Courier works on a master/slave basiswhere the slave units contain information in the form of a database, and respondwith information from the database when it is requested by a master unit.

The relay is a slave unit which is designed to be used with a Courier master unit suchas MiCOM S1, MiCOM S10, PAS&T or a SCADA system. MiCOM S1 is a WindowsNT4.0/98 compatible software package which is specifically designed for settingchanges with the relay.

To use the rear port to communicate with a PC-based master station using Courier, aKITZ K-Bus to EIA(RS)232 protocol converter is required. This unit is available fromAREVA T&D. A typical connection arrangement is shown in Figure 7. For moredetailed information on other possible connection arrangements refer to the manualfor the Courier master station software and the manual for the KITZ protocolconverter. Each spur of the K-Bus twisted pair wiring can be up to 1000m in lengthand have up to 32 relays connected to it.




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Having made the physical connection to the relay, the relay’s communication settingsmust be configured. To do this use the keypad and LCD user interface. In the relaymenu firstly check that the ‘Comms settings’ cell in the ‘Configuration’ column is setto ‘Visible’, then move to the ‘Communications’ column. Only two settings apply tothe rear port using Courier, the relay’s address and the inactivity timer. Synchronouscommunication 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:

ProtocolCourier




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

Remote address 1

Since up to 32 relays can be connected to one K-bus spur, as indicated in Figure 7, itis necessary for each relay to have a unique address so that messages from themaster 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 address isthen 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 revoking anypassword access that was enabled. For the rear port this can be set between 1 and30 minutes.

Note that protection and disturbance recorder settings that are modified using an on-line editor such as PAS&T must be confirmed with a write to the ‘Save changes’ cell ofthe ‘Configuration’ column. Off-line editors such as MiCOM S1 do not require thisaction 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. MODBUScommunication is achieved via a twisted pair connection to the rear port and can beused 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. Inthe 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




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

MODBUS address 23

Up to 32 relays can be connected to one MODBUS spur, and therefore it is necessaryfor each relay to have a unique address so that messages from the master controlstation are accepted by one relay only. MODBUS uses an integer number between 1and 247 for the relay address. It is important that no two relays have the sameMODBUS address. The MODBUS address is then used by the master station tocommunicate with the relay.

The next cell down controls the inactivity timer:

Inactivity timer 10.00 mins


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 that whateverbaud rate is selected on the relay is the same as that set on the MODBUS masterstation.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.

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 use atwisted pair connection over distances up to 1000m. As an option for IEC 60870-5-103, the rear port can be specified to use a fibre optic connection for direct




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 LCD userinterface. 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 are describedbelow. Move down the ‘Communications’ column from the column heading to thefirst 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 it isnecessary for each relay to have a unique address so that messages from the mastercontrol station are accepted by one relay only. IEC 60870-5-103 uses an integernumber between 0 and 254 for the relay address. It is important that no two relayshave the same IEC 60870-5-103 address. The IEC 60870-5-103 address is thenused by the master station to communicate with the relay.



IEC 60870-5-103 communication is asynchronous. Two baud rates are supported bythe relay, ‘9600 bits/s’ and ‘19200 bits/s’. It is important that whatever baud rate isselected on the relay is the same as that set on the IEC 60870-5-103 master station.

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

Measure’t period 30.00 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 following cell is not currently used but is available for future expansion

Inactive timer

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




Physical linkEIA(RS)485

The default setting is to select the electrical EIA(RS)485 connection. If the optionalfibre optic connectors are fitted to the relay, then this setting can be changed to ‘Fibreoptic’. This cell is also invisible if second rear comms port is fitted as it is mutuallyexclusive with the fibre optic connectors.

The next cell down can be used for monitor or command blocking:

CS103 Blocking

There are three settings associated with this cell; these are:

• Disabled - No blocking selected.

• Monitor Blocking - When the monitor blocking DDB Signal is active high, either by energising an opto input or control input, reading of the status information and disturbance records is not permitted. When in this mode the relay returns a “Termination of general interrogation” message to the master station.

• Command Blocking - When the command blocking DDB signal is active high, eitherby energising an opto input or control input, all remote commands will be ignored (i.e. CB Trip/Close, change settinggroup etc.). When in this mode the relay returns a “negative acknowledgement of command” message to the master station.

3.8.4 DNP 3.0 Communication

The DNP 3.0 protocol is defined and administered by the DNP User Group.Information about the user group, DNP 3.0 in general and protocol specificationscan be found on their website: www.dnp.org

The relay operates as a DNP 3.0 slave and supports subset level 2 of the protocolplus some of the features from level 3. DNP 3.0 communication is achieved via atwisted pair connection to the rear port and can be used over a distance of 1000mwith up to 32 slave devices.

To use the rear port with DNP 3.0 communication, the relay’s communication settingsmust be configured. To do this use the keypad and LCD user interface. In the relaymenu firstly check that the ‘Comms setting’ cell in the ‘Configuration’ column is set to‘Visible’, then move to the ‘Communications’ column. Four settings apply to the rearport using DNP 3.0, which are described below. Move down the ‘Communications’column from the column heading to the first cell which indicates the communicationsprotocol:

ProtocolDNP 3.0




The next cell controls the DNP 3.0 address of the relay:

DNP 3.0 address232

Upto 32 relays can be connected to one DNP 3.0 spur, and therefore it is necessaryfor each relay to have a unique address so that messages from the master controlstation are accepted by only one relay. DNP 3.0 uses a decimal number between 1and 65519 for the relay address. It is important that no two relays have the sameDNP 3.0 address. The DNP 3.0 address is then used by the master station tocommunicate with the relay.



DNP 3.0 communication is asynchronous. Six baud rates are supported by the relay‘1200bits/s’, ‘2400bits/s’, ‘4800bits/s’, ’9600bits/s’, ‘19200bits/s’ and‘38400bits/s’. It is important that whatever baud rate is selected on the relay is thesame as that set on the DNP 3.0 master station.

The next cell down the column 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 the DNP 3.0master station.

The next cell down the column sets the time synchronisation request from the masterby the relay:

Time SynchEnabled

The time synch can be set to either enabled or disabled. If enabled it allows the DNP3.0 master to synchronise the time.

3.9 Second rear communication port

For relays with Courier, MODBUS, IEC60870-5-103 or DNP3 protocol on the firstrear communications port there is the hardware option of a second rearcommunications port, which will run the Courier language. This can be used overone of three physical links: twisted pair K-Bus (non polarity sensitive), twisted pairEIA(RS)485 (connection polarity sensitive) or EIA(RS)232.




The settings for this port are located immediately below the ones for the first port asdescribed in previous sections of P34x/EN IT/E33. Move down the settings until thefollowing sub heading is displayed.

REAR PORT2 (RP2)

The next cell down indicates the language, which is fixed at Courier for RP2.

RP2 ProtocolCourier

The next cell down indicates the status of the hardware, e.g.

RP2 Card StatusEIA(RS)232 OK

The next cell allows for selection of the port configuration.

RP2 Port ConfigEIA(RS)232

The port can be configured for EIA(RS)232, EIA(RS)485 or K-Bus.

In the case of EIA(RS)232 and EIA(RS)485 the next cell selects the communicationmode.

RP2 Comms ModeIEC60870 FT1.2

The choice is either IEC60870 FT1.2 for normal operation with 11-bit modems, or10-bit no parity.

The next cell down controls the comms port address.

RP2 Address255

Since up to 32 relays can be connected to one K-bus spur, as indicated in Figure 7, itis necessary for each relay to have a unique address so that messages from themaster 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 address isthen used by the master station to communicate with the relay.

The next cell down controls the inactivity timer.




RP2 Inactivity Timer15 mins


In the case of EIA(RS)232 and EIA(RS)485 the next cell down controls the baud rate.For K-Bus the baud rate is fixed at 64kbit/second between the relay and the KITZinterface at the end of the relay spur.

RP2 Baud Rate19200

Courier communications is asynchronous. Three baud rates are supported by therelay, ‘9600 bits/s’, ‘19200 bits/s’ and ‘38400 bits/s’.

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2 Master stations configuration: SCADA (Px40 1st RP) via CK222, EIA485 2ndrear port via remote PC, Px40 & Px30 mixture plus front access

2nd RP (EIA485)

1st RP (Modbus/ IEC103)

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EIA232

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MiCOMS1

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Note: 1st RP could be any chosen protocol, 2nd RP is always Courier

CK222

KITZ202/4

EIA485

“EIA(RS)485 Application” example

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Figure 9: Second rear port EIA(RS)485 example

P2086ENA2 Master stations configuration: SCADA (Px40 1st RP) via CK222, EIA232 2nd rearport via remote PC, max EIA232 bus distance 15m, PC local front/rear access

2nd RP (EIA232)

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EIA232

Master 1 Master 2

EIA232

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CK222

15mmax

1st RP (Modbus / DNP/ IEC103)

EIA485

“EIA(RS)232 Application” example

Figure 10: Second rear port EIA(RS)232 example




MiCOM P342, P343

APPLICATION NOTES

P34x/EN AP/F33 Application Notes

MiCOM P342, P343



CONTENT

1. INTRODUCTION 11

1.1 Protection of generators 11

1.2 MiCOM Generator protection relays 12

1.2.1 Protection features 13

1.2.2 Non-protection features 14

2. APPLICATION OF INDIVIDUAL PROTECTION FUNCTIONS 14

2.1 Configuration column 14

2.2 CT and VT ratios 17

2.3 Generator differential protection 17

2.3.1 Biased differential protection 19

2.3.2 Setting guidelines for biased differential protection 20

2.3.3 High impedance differential protection 21

2.3.4 Setting guidelines for high impedance differential protection 22

2.3.5 Interturn (split phase) protection 26

2.3.5.1 Differential interturn protection 26

2.3.5.2 Application of biased differential protection for interturn protection 27

2.3.5.3 Application of overcurrent protection for interturn protection 29

2.3.5.4 Interturn protection by zero sequence voltage measurement 30

2.4 Phase fault overcurrent protection 32

2.4.1 RI curve 34

2.4.2 Application of timer hold facility 34

2.4.3 Setting guidelines for overcurrent protection 35

2.5 System back-up protection 35

2.5.1 Voltage dependant overcurrent protection 38

2.5.1.1 Voltage controlled overcurrent protection 38

2.5.1.2 Voltage restrained overcurrent protection 40

2.5.1.3 Setting guidelines for voltage controlled overcurrent function 41

2.5.2 Under impedance protection 43

2.5.2.1 Setting guidelines for under impedance function 44

2.6 Undervoltage protection function (27) 44

2.6.1 Setting guidelines for undervoltage protection 46

2.7 Overvoltage protection 47



2.7.1 Setting guidelines for overvoltage protection 48

2.8 Underfrequency protection 49

2.8.1 Setting guidelines for underfrequency protection 50

2.9 Overfrequency protection function 52

2.9.1 Setting guidelines for overfrequency protection 52

2.10 Field failure protection function (40) 53

2.10.1 Setting guidelines for field failure protection 55

2.10.1.1 Impedance element 1 55

2.10.1.2 Impedance element 2 56

2.10.1.3 Power factor element 56

2.11 Negative phase sequence thermal protection 57

2.11.1 Setting guidelines for negative phase sequence thermal protection 60

2.12 Reverse power/over power/low forward power 62

2.12.1 Sensitive power protection function 63

2.12.2 Low forward power protection function 65

2.12.2.1 Low forward power setting guideline 66

2.12.3 Reverse power protection function 66

2.12.3.1 Reverse power setting guideline 67

2.12.4 Over power protection 68

2.12.4.1 Over power setting guideline 68

2.13 Stator earth fault protection function 68

2.13.1 IDG curve 70

2.13.2 Setting guidelines for stator earth fault potection 71

2.14 Residual overvoltage/neutral voltage displacement protection function 72

2.14.1 Setting guidelines for residual overvoltage/neutral voltage displacementprotection 74

2.15 Sensitive earth fault protection function 75

2.15.1 Setting guidelines for sensitive earth fault protection 77

2.16 Restricted earth fault protection 77

2.16.1 Low impedance biased differential REF protection 78

2.16.1.1 Setting guidelines for low impedance biased REF protection 81

2.16.2 High impedance restricted earth fault protection 81

2.16.2.1 Setting guidelines for high impedance REF protection 83

2.17 100% stator earth fault protection 86

2.17.1 Setting guidelines for 100% stator earth fault protection 90



2.18 Overfluxing protection 91

2.18.1 Setting guidelines for overfluxing protection 92

2.19 Dead machine/unintentional energisation at standstill protection 93

2.19.1 Setting guidelines for dead machine protection 94

2.20 Resistive temperature device (RTD) thermal protection 94

2.20.1 Setting guidelines for RTD thermal protection 96

2.21 P342 pole slipping protection 97

2.21.1 Reverse power protection 97

2.21.2 System back-up protection function 97

2.21.3 Field failure protection function 98

2.22 P343 pole slipping protection 99

2.22.1 Introduction 99

2.22.2 Loss of synchronism characteristics 100

2.22.3 Generator pole slipping characteristics 103

2.22.3.1 What happens if EG / ES has different values less than one (1)? 103

2.22.3.2 What happens if different system impedances are applied? 103

2.22.3.3 How to determine the generator reactance during a pole slipping condition? 103

2.22.3.4 How to determine the slip rate of pole slipping? 104

2.22.4 General requirements for pole slipping protection 104

2.22.5 Lenticular scheme 104

2.22.5.1 Characteristic 104

2.22.5.2 Generating and motoring modes 105

2.22.6 Pole slipping protection operation 106

2.22.6.1 State machine 106

2.22.6.2 Protection functions and logic structure 109

2.22.6.3 Motoring mode 110

2.22.6.4 Generating and motoring mode 110

2.22.7 Setting guidelines for pole slipping protection 111

2.22.7.1 Settings 114

2.22.7.2 DDB output 115

2.22.7.3 Pole slipping setting examples 115

2.22.8 Example calculation 115

2.23 Thermal overload protection 116

2.23.1 Introduction 116



2.23.2 Thermal replica 117

2.23.3 Setting guidelines 119

2.24 Circuit breaker failure protection 120

2.24.1 Breaker failure protection configurations 120

2.24.2 Reset mechanisms for breaker fail timers 121

2.24.3 Typical settings 123

2.24.3.1 Breaker fail timer settings 123

2.24.4 Breaker fail undercurrent settings 123

2.25 Breaker flashover protection 124

2.26 Blocked overcurrent protection 126

2.27 Current loop inputs and outputs 127

2.27.1 Current loop inputs 127

2.27.2 Setting guidelines for current loop inputs 129

2.27.3 Current loop outputs 130

2.27.4 Setting guidelines for current loop outputs 135

3. APPLICATION OF NON-PROTECTION FUNCTIONS 135

3.1 VT supervision 135

3.1.1 Loss of all three phase voltages under load conditions 136

3.1.2 Absence of three phase voltages upon line energisation 136

3.1.2.1 Inputs 138

3.1.2.2 Outputs 138

3.1.3 Menu settings 139

3.2 CT supervision 140

3.2.1 The CT supervision feature 140

3.2.2 Setting the CT supervision element 141

3.3 Circuit breaker state monitoring 141

3.3.1 Circuit breaker state monitoring features 141

3.4 Pole dead logic 143

3.5 Circuit breaker condition monitoring 144

3.5.1 Circuit breaker condition monitoring features 145

3.5.2 Setting guidelines 146

3.5.2.1 Setting the Σ Ι^ thresholds 146

3.5.2.2 Setting the number of operations thresholds 146

3.5.2.3 Setting the operating time thresholds 147



3.5.2.4 Setting the excessive fault frequency thresholds 147

3.5.3 Circuit breaker state monitoring features 147

3.6 Trip circuit supervision (TCS) 148

3.6.1 TCS scheme 1 148

3.6.1.1 Scheme description 148

3.6.2 Scheme 1 PSL 149







3.7 Event & fault records 152

3.7.1 Change of state of opto-isolated inputs 153

3.7.2 Change of state of one or more output relay contacts 153

3.7.3 Relay alarm conditions 154

3.7.4 Protection element starts and trips 155

3.7.5 General events 155

3.7.6 Fault records 155

3.7.7 Maintenance reports 155

3.7.8 Setting changes 155

3.7.9 Resetting of event/fault records 156

3.7.10 Viewing event records via MiCOM S1 support software 156

3.7.11 Event filtering 158

3.8 Disturbance recorder 159

3.9 Measurements 160

3.9.1 Measured voltages and currents 160

3.9.2 Sequence voltages and currents 161

3.9.3 Power and energy quantities 161

3.9.4 Rms. voltages and currents 161

3.9.5 Demand values 161

3.9.5.1 Fixed demand values 162

3.9.5.2 Rolling demand values 162

3.9.5.3 Peak demand values 162



3.9.6 Settings 162

3.9.6.1 Default display 162

3.9.6.2 Local values 162

3.9.6.3 Remote values 163

3.9.6.4 Measurement REF 163

3.9.6.5 Measurement mode 163

3.9.6.6 Fixed demand period 163

3.9.6.7 Rolling sub-period and number of sub-periods 163

3.10 Changing setting groups 163

3.11 Control inputs 164

3.12 VT connections 164

3.12.1 Open delta (vee connected) VT's 164

3.12.2 VT single point earthing 165

3.13 PSL DATA column 165

3.14 Auto reset of trip LED indication 165

4. CURRENT TRANSFORMER REQUIREMENTS 166

4.1 Generator differential function 166

4.1.1 Biased differential protection 166

4.1.2 High impedance differential protection 167

4.2 Voltage dependent overcurrent, field failure and negative phasesequence protection functions 167

4.3 Sensitive directional earth fault protection function residual currentinput 168

4.3.1 Line current transformers 168

4.3.2 Core balanced current transformers 168

4.4 Stator earth fault protection function 169

4.4.1 Non-directional definite time/IDMT earth fault protection 169

4.4.2 Non-directional instantaneous earth fault protection 169

4.5 Restricted earth fault protection 169

4.5.1 Low impedance 169

4.5.2 High impedance 170

4.6 Reverse and low forward power protection functions 170

4.6.1 Protection class current transformers 170

4.6.2 Metering class current transformers 170



4.7 Converting an IEC185 current transformer standard protectionclassification to a kneepoint voltage 171

4.8 Converting IEC185 current transformer standard protection classificationto an ANSI/IEEE standard voltage rating 172

5. COMMISSIONING TEST MENU 172

5.1 Opto I/P status 173

5.2 Relay O/P status 173

5.3 Test port status 174

5.4 LED status 174

5.5 Monitor bits 1 to 8 174

5.6 Test mode 174

5.7 Test pattern 175

5.8 Contact test 175

5.9 Test LEDs 175

5.10 Using a monitor/download port test box 175

Figure 1: Principle of circulating current differential protection 18

Figure 2: Biased differential protection operating characteristic 19

Figure 3: Relay connections for biased differential protection 20

Figure 4: Principle of high impedance differential protection 21

Figure 5: Relay connections for high impedance differential protection 22

Figure 6: Generator interturn protection using separate CTs 26

Figure 7: Generator interturn protection using core balance (window) CTs 27

Figure 8: Transverse biased differential protection for double wound machines 28

Figure 9: Generator differential and interturn protection 29

Figure 10: Overcurrent interturn protection 30

Figure 11: Interturn protection by zero sequence voltage measurement 31

Figure 12: Typical generator fault current decrement curve 36

Figure 13: Modification of current pickup level for voltage controlled overcurrentprotection 38

Figure 14: Modification of current pickup level for voltage restrained overcurrentprotection 41

Figure 15: Under impedance element tripping characteristic 43



Figure 16: Co-ordination of underfrequency protection function with system load shedding 51

Figure 17: Field failure protection characteristics 53

Figure 18: Negative phase sequence thermal characteristic 59

Figure 19: Effective coverage of stator earth fault protection 69

Figure 20: IDG characteristic 71

Figure 21: Alternative relay connections for residual overvoltage/NVD protection 73

Figure 22: Relay connections for biased REF protection 79

Figure 23: Biased REF protection operating characteristic 79

Figure 24: Neutral scaling for biased REF protection 80

Figure 25: Principle of high impedance differential protection 82

Figure 26: Relay connections for high impedance REF protection 82

Figure 27: Distribution of the 3rd harmonic component along the stator winding of alarge generator, (a) normal operation, (b) stator earth fault at the star point(c), stator earth fault at the terminals 87

Figure 28: 100% Stator earth fault protection block diagram 88

Figure 29: Connection for 3rd harmonic undervoltage and overvoltage for 100% statorearth fault protection 89

Figure 30: Fixed scheme logic for unintentional energisation of standstill protection 93

Figure 31: Connection for RTD thermal probes 95

Figure 32: Field failure protection function characteristics (small co-generator) 98

Figure 33: Simplified two machine system 101

Figure 34: Apparent impedance loci viewed at the generator terminal (point A) 102

Figure 35: Pole slipping protection using blinder and lenticular characteristic 105

Figure 36: State machine 106

Figure 37: Regions and zones definition (generating mode) 107

Figure 39: Regions and zones definition (motoring mode) 110

Figure 40: Lenticular scheme characteristic 111

Figure 41: Pole slipping protection using blinder and lenticular characteristic 113

Figure 42: Example system configuration 115

Figure 43: CB fail logic 124

Figure 44: Breaker flashover protection for directly connected machine 125

Figure 45: Breaker flashover protection for indirectly connected machine 125

Figure 46a: Simple busbar blocking scheme (single incomer) 126

Figure 46b: Simple busbar blocking scheme (single incomer) 127

Figure 47: Relationship between the transducer measuring quantity and the currentinput range 128



Figure 48: Relationship between the current output and the relay measurement 131

Figure 49: VTS logic 137

Figure 50: CT supervision function block diagram 140

Figure 51: CB state monitoring 143

Figure 52: Pole dead logic 144

Figure 53: TCS scheme 1 148

Figure 54: PSL for TCS schemes 1 and 3 149


Figure 56: PSL for TCS scheme 2 151


Figure 58: Trip LED logic diagram 166


Page 10/176 MiCOM P342, P343


MiCOM P342, P343 Page 11/176

1. INTRODUCTION

1.1 Protection of generators

An ac generator forms the electromechanical stage of an overall energy conversionprocess that results in the production of electrical power. A reciprocating engine, orone of many forms of turbine, acts as a prime mover to provide the rotarymechanical input to the alternator.

There are many forms of generating plant that utilise a variety of sources of energyavailable, e.g. combustion of fossil fuels, hydro dams and nuclear fission.Generation schemes may be provided for base-load production, peak-lopping or forproviding standby power.

Electrical protection should quickly detect and initiate shutdown for major electricalfaults associated with the generating plant and, less urgently, to detect abnormaloperating conditions which may lead to plant damage.

Abnormal electrical conditions can arise as a result of a failure within the generatingplant itself, but can also be externally imposed on the generator. Commoncategories of faults and abnormal conditions which can be detected electrically arelisted as follows: (Not all conditions have to be detected for all applications.)

Major electrical faults

• Insulation failure of stator windings or connections

Secondary electrical faults

• Insulation failure of excitation system

• Failure of excitation system

• Unsynchronised over voltage

Abnormal prime mover or control conditions

• Failure of prime mover

• Over frequency

• Over fluxing

• Dead machine energisation

• Breaker flashover

System related

• Feeding an uncleared fault

• Prolonged or heavy unbalanced loading

• Prolonged or heavy overload

• Loss of synchronism

• Over frequency

• Under frequency

• Synchronised over voltage

• Over fluxing


Page 12/176 MiCOM P342, P343

• Undervoltage

In addition various types of mechanical protection may be necessary, such asvibration detection, lubricant and coolant monitoring, temperature detection etc.

The action required following response of an electrical or mechanical protection isoften categorised as follows:

• Urgent shutdown

• Non-urgent shutdown

• Alarm only

An urgent shutdown would be required, for example, if a phase to phase faultoccurred within the generator electrical connections. A non-urgent shutdown mightbe sequential, where the prime mover may be shutdown prior to electricallyunloading the generator, in order to avoid over speed. A non-urgent shutdown maybe initiated in the case of continued unbalanced loading. In this case, it is desirablethat an alarm should be given before shutdown becomes necessary, in order to allowfor operator intervention to remedy the situation.

For urgent tripping, it may be desirable to electrically maintain the shutdowncondition with latching protection output contacts, which would require manualresetting. For a non-urgent shutdown, it may be required that the output contacts areself-reset, so that production of power can be re-started as soon as possible.

The P342/3 is able to maintain all protection functions in service over a wide rangeof operating frequency due to its frequency tracking system (5-70 Hz). The P343frequency tracking capability is of particular interest for pumped storage generationschemes, where synchronous machines can be operated from a variable frequencysupply when in pumping mode. Additionally, in the case of combined cyclegenerating plant, it may be necessary to excite and synchronise a steam turbinegenerating set with a gas turbine set at low frequency, prior to running up to nominalfrequency and synchronising with the power system.

When the P342/3 protection functions are required to operate accurately at lowfrequency, it will be necessary to use CTs with larger cores. In effect, the CTrequirements need to be multiplied by fn/f, where f is the minimum requiredoperating frequency and fn is the nominal operating frequency.

1.2 MiCOM Generator protection relays

MiCOM relays are a new range of products from AREVA T&D. Using the latestnumerical technology the range includes devices designed for the application to awide range of power system plant such as motors, generators, feeders, overheadlines and cables.

Each relay is designed around a common hardware and software platform in orderto achieve a high degree of commonality between products. One such product in therange is the P340 Generator protection relays. The relays have been designed tocater for the protection of a wide range of generators from small machines, providingstandby power on industrial sites, to large machines in power stations providing forthe base load on the grid transmission network.

The relays also include a comprehensive range of non-protection features to aid withpower system diagnosis and fault analysis. All these features can be accessedremotely from one of the relays remote serial communications options.


MiCOM P342, P343 Page 13/176

1.2.1 Protection features

The P340 relays contain a wide variety of protection functions for the protection ofgenerators. There are 2 separate models available to cover a wide range ofapplications. The protection features of each model are summarised below:

• Generator differential protection - Phase segregated differential protectionoperating on a biased or high impedance principle. Provides high speed,discriminative protection for all fault types. P343 only

• Phase fault overcurrent protection - Two stage non-directional back-up protection.

• Voltage dependent overcurrent/under impedance protection - Back-up protectionfor generators with limited fault current capacity.

• Earth fault overcurrent protection - Two stage non-directional back-up protection.

• Neutral voltage displacement protection - Two stage element providing protectionagainst earth faults on high impedance earthed systems.

• Sensitive directional earth fault protection - Discriminative earth fault protectionfor parallel connected generators.

• 100% Stator earth fault protection - Provides protection against earth faults closeto the generator star point. P343 only

• Under/overvoltage protection - Two stage undervoltage and two stageovervoltage protection.

• Under/over frequency protection - Four stage under frequency and two stage overfrequency protection.

• Reverse power - Protection against loss of prime mover.

• Low forward power - Provides an interlock for non urgent tripping.

• Over power - Back-up overload protection.

• Field failure - Two stage element for protection against loss of excitation.

• Negative phase sequence protection - Provides protection against unbalancedloading which can cause overheating of the generator.

• Overfluxing - Provides protection for the generator/transformer against unusual voltage or frequency conditions.

• Pole slipping – Provides protection against loss of synchronisation between thegeneration and the system P343 only

• Unintentional energisation at standstill (dead machine) protection - Protectionagainst inadvertent closing of the generator circuit breaker when the machine isnot running. P343 only

• Voltage transformer supervision - To prevent mal-operation of voltage dependentprotection elements upon loss of a VT input signal.

• Thermal protection via RTD inputs - Thermal protection for the machine providedby measuring the temperature of winding/bearings etc. via resistive thermaldevices embedded within the machine. 10 RTD inputs can be provided.

• Programmable scheme logic - Allowing user defined protection and control logicto suit particular customer applications.


Page 14/176 MiCOM P342, P343

1.2.2 Non-protection features

Below is a summary of the P340 relay non-protective features.

• Measurements - Various measurements of value for display on the relay oraccessed from the serial communications, e.g. Currents, voltages, temperatureetc.

• Fault/event/disturbance records - Available from the serial communications or onthe relay display (fault and event records only on relay display).

• Real time clock / time synchronisation - Time synchronisation possible from relayIRIG-B input.

• Four setting groups - Independent setting groups to cater for alternative powersystem arrangements or customer specific applications.

• Remote serial communications - To allow remote access to the relays. Thefollowing communications protocols are supported; Courier, MODBUS, IEC870-5-103 (VDEW) and DNP3.0.

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

• Circuit breaker state monitoring - Provides indication of discrepancy betweencircuit breaker auxiliary contacts.

• Circuit breaker condition monitoring - Provides records / alarm outputs regardingthe number of CB operations, sum of the interrupted current and the breakeroperating time.

• Commissioning test facilities.

2. APPLICATION OF INDIVIDUAL PROTECTION FUNCTIONS

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

2.1 Configuration column

The P340 relays include a column in the menu called the “CONFIGURATION”column. This affects the operation of each of the individual protection functions. Theaim of this column is to allow general configuration of the relay from a single point inthe menu. Any of the functions that are disabled or made invisible from this columndo not then appear within the main relay menu.

The following table shows the relay menu for the configuration column, with defaultsettings. The brief description of the function of each setting is also provided.

Menu Text Default Setting Available Setting Function

CONFIGURATION

Restore Defaults No Operation

No OperationAll SettingsSetting Group 1Setting Group 2Setting Group 3Setting Group 4

Restore defaultsettings to any orall group ofsettings


MiCOM P342, P343 Page 15/176


CONFIGURATION

Setting Group Select via Menu Select via MenuSelect via Optos

Change settinggroups by?

Active Settings Group 1

Group 1Group 2Group 3Group 4

Select activesetting group usedfor protectionsettings

Save Changes No OperationNo OperationSaveAbort

Saves all settingchanges frombuffer memoryinto stored settings

Copy From Group 1 Group1, 2, 3 or 4

Selects a group ofsettings to copy tothe groupdesignated in“Copy to” cell

Copy To No Operation Group1,2,3 or 4

Copies the groupof settings selectedin the “Copyfrom” cell to theselected settinggroup

Setting Group 1 Enabled Enabled or Disabled

Selects if Group 1settings areavailable on therelay

Setting Group 2 Disabled Enabled or Disabled






Gen Differential Enabled Enabled or DisabledEnables protectionelement in therelay

Power Enabled Enabled or Disabled “

Field Failure Enabled Enabled or Disabled “

NPS Thermal Enabled Enabled or Disabled “

System Backup Enabled Enabled or Disabled “

Overcurrent Enabled Enabled or Disabled “


Page 16/176 MiCOM P342, P343


CONFIGURATION

ThermalOverload Enabled Enabled or Disabled “

Standard E/F Enabled Enabled or Disabled “

SEF/REF SPower SEF/REF Disabled or SEF/REFor Sensitive Power “

Residual O/VNVD Enabled Enabled or Disabled “

100% Stator E/F Disabled Enabled or Disabled “

V/Hz Disabled Enabled or Disabled “

Dead Machine Disabled Enabled or Disabled “

Volt Protection Enabled Enabled or Disabled “

Freq Protection Enabled Enabled or Disabled “

RTD Inputs Enabled Enabled or Disabled “

CB Fail Disabled Enabled or Disabled “

Pole Slipping Enabled Enabled or Disabled “

Supervision Disabled Enabled or Disabled “

Input Labels Visible Invisible or VisibleMakes settingsvisible in the relaymenu

Output Labels Visible Invisible or Visible “

RTD Labels Visible Invisible or Visible “

CT & VT Ratios Visible Invisible or Visible “

Event Recorder Invisible Invisible or Visible “

Disturb Recorder Invisible Invisible or Visible “

Measure’t Setup Invisible Invisible or Visible “

Comms Settings Visible Invisible or Visible “

CommissionTests Visible Invisible or Visible “

Setting Values Primary Primary or Secondary

Selects if relayprotection settingsare displayed inprimary orsecondarycurrent/voltagevalues

Control Inputs Visible Invisible or VisibleMakes settingsvisible in the relaymenu


MiCOM P342, P343 Page 17/176


CONFIGURATION

CLIO Inputs Enabled Enabled or DisabledEnables protectionelement in therelay

CLIO Outputs Enabled Enabled or Disabled “

2.2 CT and VT ratios

The P340 relay allows the current, voltage and impedance settings to be applied tothe relay in either primary or secondary quantities. This is done by programming the“Setting Values” cell of the “CONFIGURATION” column to either ‘Primary’ or‘Secondary’. When this cell is set to ‘Primary’, all current, voltage and impedancesetting values are scaled by the programmed CT and VT ratios. These are found inthe “VT & CT RATIOS” column, settings for which are shown below.

Setting RangeMenu Text Default Setting

Min MaxStep Size

CT AND VT RATIOS

Main VT Primary 110V 100V 1000000V 1V

Main VT Sec’y110V

(Vn=100/120V)400V

(Vn=380/480)

80V(Vn=100/120V)

360V(Vn=380/480V)

14V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

NVD VT Primary 110V 100V 1000000V 1V

NVD VT Sec'y110V

(Vn=100/120V)400V

(Vn=380/480)

80V(Vn=100/120V)

360V(Vn=380/480V)

140V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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 Generator differential protection

Failure of stator windings, or connection insulation, can result in severe damage tothe windings and the stator core. The extent of the damage will depend upon thefault current level and the duration of the fault. Protection should be applied to limitthe degree of damage in order to limit repair costs. For primary generating plant,high-speed disconnection of the plant from the power system may also be necessaryto maintain system stability.

For generators rated above 1 MVA, it is common to apply generator differentialprotection. This form of unit protection allows discriminative detection of windingfaults, with no intentional time delay, where a significant fault current arises.The zone of protection, defined by the location of the CTs, should be arranged tooverlap protection for other items of plant, such as a busbar or a step-uptransformer.


Page 18/176 MiCOM P342, P343

Circulating current differential protection operates on the principle that currententering and leaving a zone of protection will be equal. Any difference betweenthese currents is indicative of a fault being present in the zone. If CTs are connectedas shown in Figure 1 it can be seen that current flowing through the zone ofprotection will cause current to circulate around the secondary wiring. If the CTs areof the same ratio and have identical magnetising characteristics they will produceidentical secondary currents and hence zero current will flow through the relay. If afault exists within the zone of protection there will be a difference between the outputfrom each CT; this difference flowing through the relay causing it to operate.

Figure 1: Principle of circulating current differential protection

Heavy through current, arising from an external fault condition, can cause one CT tosaturate more than the other, resulting in a difference between the secondary currentproduced by each CT. It is essential to stabilise the protection for these conditions.Two methods are commonly used. A biasing technique, where the relay setting israised as through current increases. Alternatively, a high impedance technique,where the relay impedance is such that under maximum through fault conditions, thecurrent in the differential element is insufficient for the relay to operate.

The generator differential protection function available in the P343 relay can be usedin either biased differential or high impedance differential mode. Both modes ofoperation are equally valid; users may have a preference for one over the other. Theoperating principle of each is described in the following sections.

The generator differential protection may also be used for interturn protection whichis described in the following sections.

A DDB (Digital Data Bus) signal is available to indicate the tripping of each phase ofdifferential protection (DDB 419, DDB 420, DDB 421), in addition a 3 phase tripDDB signal is provided (DDB 418). These signals are used to operate the outputrelays and trigger the disturbance recorder as programmed into the ProgrammableScheme Logic (PSL). The state of the DDB signals can also be programmed to beviewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.

The following table shows the relay menu for the Differential protection element,including the available setting ranges and factory defaults:


MiCOM P342, P343 Page 19/176


Min MaxStep Size

GROUP 1GEN DIFF

GenDiff Function Biased Disabled, Biased,High Impedance, Interturn N/A

Gen Diff Ιs1 0.1 0.05 Ιn A 0.5 Ιn A 0.01 Ιn A

Gen Diff k1 0 0 20% 5%

Gen Diff Ιs2 1.5 1.0 Ιn A 5.0 Ιn A 0.1 Ιn A

Gen Diff k2 150 20% 150% 10%

Interturn Is_A 0.1 0.05 Ιn A 2 Ιn A 0.01 Ιn A

Interturn Is_B 0.1 0.05 Ιn A 2 Ιn A 0.01 Ιn A

Interturn Is_C 0.1 0.05 Ιn A 2 Ιn A 0.01 Ιn A

InterturnITimeDelay 0.1 s 0 s 100 s 0.01 s

2.3.1 Biased differential protection

In a biased differential relay, the through current is used to increase the setting of thedifferential element. For heavy through faults, it is unlikely that the CT outputs ateach zone end will be identical, due to the effects of CT saturation. In this case adifferential current can be produced. However, the biasing will increase the relaysetting, such that the differential spill current is insufficient to operate the relay.

The through current is calculated as the average of the scalar sum of the currententering and leaving the zone of protection. This calculated through current is thenused to apply a percentage bias to increase the differential setting. The percentagebias can be varied to give the operating characteristic shown in Figure 2.

Figure 2: Biased differential protection operating characteristic


Page 20/176 MiCOM P342, P343

Two bias settings are provided in the P343 relay. The initial bias slope,“Gen Diff k1”, is applied for through currents upto “G en Diff Ιs2”. The second biasslope, “Gen Diff k2”, is applied for through currents above the "Gen Diff Ιs2" setting.

The operating current of the biased differential element, for any value of throughcurrent, can be calculated using the following formulae:

ΙBIAS = Ι1 + Ι2

2

ΙDIFF > K2.ΙBIAS – (K2 – K1) Ιs2 + Ιs1 where ΙBIAS > Ιs2

ΙDIFF > K1.ΙBIAS + Ιs1 where ΙBIAS ™Ιs2

The Biased differential protection function uses the two sets of three phase currentmeasurement inputs (ΙA, ΙB, ΙC, ΙA2, ΙB2, ΙC2), connected to measure the phasecurrent at the neutral end and terminals of the machine, as shown in Figure 3. Thebias and differential currents are calculated by the relay software, providing a phasesegregated differential protection function, and may be viewed in the“MEASUREMENTS” columns in the relay menu.

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Figure 3: Relay connections for biased differential protection

2.3.2 Setting guidelines for biased differential protection

To select biased differential protection the “GenDiff Function” cell should be set to‘Biased’.

The differential current setting, “Gen Diff Ιs1”, should be set to a low setting toprotect as much of the machine winding as possible. A setting of 5% of rated currentof the machine is generally considered to be adequate. “Gen Diff Ιs2”, the thresholdabove which the second bias setting is applied, should be set to 120% of the machinerated current.

The initial bias slope setting, “Gen Diff k1”, should be set to 0% to provide optimumsensitivity for internal faults. The second bias slope may typically be set to 150% toprovide adequate stability for external faults.


MiCOM P342, P343 Page 21/176

These settings may be increased where low accuracy class CTs are used to supply theprotection.

2.3.3 High impedance differential protection

The high impedance principle is best explained by considering a differential schemewhere one CT is saturated for an external fault, as shown in Figure 4.

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(& )%

* % $+'

, ' $&&% $

-& * % *

.$

* *

,

,

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,"

*

/

/'%/ 0 * ,1

)'2*2$% 0'1

*/ 3

4+&56

Figure 4: Principle of high impedance differential protection

If the relay circuit is considered to be a very high impedance, the secondary currentproduced by the healthy CT will flow through the saturated CT. If the magnetisingimpedance of the saturated CT is considered to be negligible, the maximum voltageacross the relay circuit will be equal to the secondary fault current multiplied by theconnected 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 the relayis less than its current setting. As the impedance of the relay input alone is relativelylow, a series connected external resistor is required. The value of this resistor, RST, iscalculated by the formula shown in Figure 4. An additional non linear resistor,metrosil, may be required to limit the peak secondary circuit voltage during internalfault conditions.


Page 22/176 MiCOM P342, P343

To ensure that the protection will operate quickly during an internal fault the CTs usedto operate the protection must have a kneepoint voltage of at least 2Vs.

The high impedance differential protection function uses the ΙA2, ΙB2, ΙC2 currentinputs connected to measure the differential current in each phase, as shown inFigure 5.

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Figure 5: Relay connections for high impedance differential protection

2.3.4 Setting guidelines for high impedance differential protection

To select high impedance differential protection the “GenDiff Function” cell should beset to ‘High Impedance’.

The differential current setting, “G en Diff Ιs1”, should be set to a low setting toprotect as much of the machine winding as possible. A setting of 5% of rated currentof the machine is generally considered to be adequate. This setting may need to beincreased where low accuracy class CTs are used to supply the protection. A checkshould be made to ensure that the primary operating current of the element is lessthan the minimum fault current for which the protection should operate.

The primary operating current (Ιop) will be a function of the current transformer ratio,the relay operating current (Gen Diff Ιs1), the number of current transformers inparallel with a relay element (n) and the magnetising current of each currenttransformer (Ιe) at the stability voltage (Vs). This relationship can be expressed inthree ways:

1. To determine the maximum current transformer magnetising current to achievea specific primary operating current with a particular relay operating current.

Ιe < 1

n x

Ιop

CT ratio - Gen diff REF > Ιs1


MiCOM P342, P343 Page 23/176

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

Gen diff Ιs1 <

Ιop

CT ratio - nΙe

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

Ιop = (CT ratio) x (Gen diff Ιs1 + nΙe)

In order to achieve the required primary operating current with the currenttransformers that are used, a current setting (Gen Diff Ιs1) 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 the settingis a function of the required stability voltage setting (Vs) and the relay current setting(Gen Diff Ιs1).

RST = Vs

Gen diff Ιs1 =

1.5 ΙF (RCT + 2RL)

Gen diff Ιs1

Note: The above formula assumes negligible relay burden

USE OF “METROSIL” NON-LINEAR RESISTORS

Metrosils 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 to withstand3000V 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 current transformersaturation did not occur. This prospective voltage will be a function of maximuminternal fault secondary current, the current transformer ratio, the current transformersecondary winding resistance, the current transformer lead resistance to the commonpoint, the relay lead resistance and the stabilising resistor value.

Vp = 2 2Vk ( ) Vf - Vk

Vf = Ι'f (RCT + 2RL + RST)

where

Vp = peak voltage developed by the CT under internal fault conditions.

Vk = current transformer knee-point voltage.

Vf = maximum voltage that would be produced if CT saturation did notoccur.

Ι‘f = maximum internal secondary fault current.

RCT = current transformer secondary winding resistance.

RL = maximum lead burden from current transformer to relay.


Page 24/176 MiCOM P342, P343

RST = relay stabilising resistor.

When the value given by the formulae is greater than 3000V peak, metrosils shouldbe applied. They are connected across the relay circuit and serve the purpose ofshunting the secondary current output of the current transformer from the relay inorder to prevent very high secondary voltages.

Metrosils are externally mounted and take the form of annular discs. Their operatingcharacteristics follow the expression:

V = CΙ 0.25

where

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

C = constant of the non-linear resistor (“metrosil” )

Ι = 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:

Ι(rms) = 0.52

Vs (rms) x 2

C 4

where

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

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:

1. At the relay voltage setting, the non-linear resistor (“metrosil”) current shouldbe as low as possible, but no greater than approximately 30mA rms. for 1Acurrent transformers and approximately 100mA rms. for 5A currenttransformers.

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

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

Metrosil Units for Relays with a 1 Amp CT

The Metrosil units with 1 Amp CTs have been designed to comply with the followingrestrictions:

1. At the relay voltage setting, the Metrosil current should less than 30mA rms.

2. At the maximum secondary internal fault current the Metrosil unit should limitthe voltage to 1500V rms if possible.


MiCOM P342, P343 Page 25/176

The Metrosil units normally recommended for use with 1Amp CTs are as shown in thefollowing table:

Nominal Characteristic Recommended Metrosil TypeRelay VoltageSetting 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 withoutmounting brackets unless otherwise specified by the customer.


These Metrosil units have been designed to comply with the following requirements:-

1. At the relay voltage setting, the Metrosil current should less than 100mA rms(the actual maxium currents passed by the units shown below their typedescription.

2. At the maximum secondary internal fault current the Metrosil unit should limitthe voltage to 1500V rms for 0.25secs. At the higher relay settings, it is notpossible to limit the fault voltage to 1500V rms hence higher fault voltages haveto be tolerated (indicated by *, **, ***).

The Metrosil units normally recommended for use with 5 Amp CTs and single polerelays are as shown in the following table:

Recommended METROSIL TypeSecondaryInternal

Fault Current Relay Voltage Setting

Amps rms Up to 200V rms 250V rms 275V rms 300V rms

50A600A/S1/S1213C = 540/640

35mA rms

600A/S1/S1214C = 670/800

40mA rms

600A/S1/S1214C = 670/800

50mA rms

600A/S1/S1223C = 740/870*

50mA rms

100A600A/S2/P/S1217

C = 470/54070mA rms

600A/S2/P/S1215C = 570/670

75mA rms

600A/S2/P/S1215C = 570/670100mA rms

600A/S2/P/S1196C = 620/740100mA rms *

150A600A/S3/P/S1219

C = 430/500100mA rms

600A/S3/P/S1220C = 520/620

100mA rm

600A/S3/P/S1221C= 570/670**

100mA rms

600A/S3/P/S1222C = 620/740***

100mA rms

Note: *2400V peak **2200V peak ***2600V peak

In some situations single disc assemblies may be acceptable, contact AREVA T&D fordetailed applications.

1. The Metrosil units recommended for use with 5 Amp CTs can also be appliedfor use with triple pole relays and consist of three single pole units mounted onthe same central stud but electrically insulated for each other. To order theseunits please specify "Triple Pole Metrosil Type", followed by the single pole typereference.

2. Metrosil units for higher relay voltage settings and fault currents can besupplied if required.

For further advice and guidance on selecting METROSILS please contact theApplications department at AREVA T&D.


Page 26/176 MiCOM P342, P343

2.3.5 Interturn (split phase) protection

For generators with multi-turn stator windings, there is the possibility of a windinginter-turn fault occurring. Unless such a fault evolves to become a stator earth fault,it will not otherwise be detected with conventional protection arrangements.Hydrogenerators usually involve multi-stator windings with parallel windings.

2.3.5.1 Differential interturn protection

One differential scheme using bushing type CTs that is commonly used for interturnprotection is shown in Figure 6. In this scheme the circuits in each phase of the statorwinding are split into two equal groups and the current of each group are compared.A difference in these currents indicates an unbalance caused by an interturn fault.Since there is normally some current unbalance between windings the protection isset so that it will not respond to this normal unbalance but will pick-up for theunbalance caused by a single turn fault. In some cases the generator may run with afaulted turn until it is repaired and therefore the current pick-up level should beincreased to allow operation but still be able to detect a second fault. The P343IA2/IB2/IC2 current inputs can be used for this type of application and hasindependent settings per phase (Interturn Is_A, Interturn Is_B, Interturn Is_C).Therefore, the current setting can be increased on the faulted phase only withoutaffecting the sensitivity of the protection on the other unfaulted phases. A time delayis used to prevent operation on CT transient error currents that may occur duringexternal faults. The problem of CT transient error currents can be eliminated by usingcore balance (window) type CTs (see Figure 7).

This method of interturn protection will detect phase and some ground faults in thestator winding. However, because of the slow operating time of this protection it iscommon practice to provide standard high speed differential protection for eachphase and separate earth fault protection. If there are main 1 and main 2 P343protection relays, the IA2/IB2/IC2 inputs could be used for interturn protection on theone relay and used for standard differential protection across the generator in theother relay.

,

Figure 6: Generator interturn protection using separate CTs


MiCOM P342, P343 Page 27/176

Figure 7: Generator interturn protection using core balance (window) CTs

2.3.5.1.1 Setting guidelines for differential interturn protectionTo select interturn differential protection the “GenDiff Function” cell should be set to‘Interturn’.

The differential current settings, “Interturn Ιs_A, Interturn Ιs_B, Interturn Ιs_C”, shouldbe set to a low setting to protect as much of the machine winding as possible. Asetting of 5% of rated current of the machine is generally considered to be adequate.This setting may need to be increased where low accuracy class CTs are used tosupply the protection.

The time delay setting “Interturn ΙTim eDelay” should be set to prevent operation onCT transient error currents that may occur during external faults. A typical timesetting would be 0.1s.

2.3.5.2 Application of biased differential protection for interturn protection

For inter-turn protection applications where the generator stator is wound with 2 ormore identical 3 phase windings connected in parallel, provided the windings arebrought out separately, biased differential protection can be used connected to CTs inthe line ends of the 2 or more windings, see Figure 8. In this type of application abiased system should always be used as it is not possible to guarantee in advancethat exact current sharing between the windings will take place. A small error in thissharing current would produce instability in an unbiased system at high levels ofthrough fault current. Balanced current in the two windings produces a circulation ofcurrent in the current transformer secondary circuit, but any in zone fault, includingan interturn fault, will result in a circulation of current between the windingsproducing an output in the relay operating circuit.


Page 28/176 MiCOM P342, P343

Note, the biased differential protection in the P343 uses both sets of 3 phase currentinputs and so if the P343 differential protection was used for inter-turn protection noother protection function in the P343 would be available. As normally differentialprotection plus the many other protection functions in the P343 are required for thegenerator protection in addition to the interturn protection it is advisable to use aseparate biased differential relay for the interturn protection in this application.

Another scheme that could be used on this type of generator is shown in Figure 9.This arrangement is an attempt to get the benefits of inter-turn and differentialprotection with a saving in CTs and relays. However, this arrangement is not assensitive as other schemes using separate inter-turn relays or differential relays. Thescheme in Figure 9 requires the neutral end CTs having half the turns ratio of theterminal end CTs. The sensitivity of the protection for inter-turn faults is limited by thefact that the two CT ratios applied must be selected in accordance with the generatorrated current. A P343 could be used for this application with the IA/IB/IC inputsconnected to the terminal side CTs as these see the full rated current. Note, theIA/IB/IC inputs feed the current, impedance and power based protection. However,in the case of a single generator feeding an isolated system, back-up protectionshould use CTs at the neutral end of the machine to ensure internal faults on thegenerator windings are detected. Thus, for this type of application it is advised that aseparate biased differential protection is used for the inter-turn protection. A P342from separate CTs at the neutral end of the generator could then be used for the restof the protection.

('

89: 89:

89:

Figure 8: Transverse biased differential protection for double wound machines


MiCOM P342, P343 Page 29/176

4% %

89:

;

<56#;

*= & %

7; $%)+% '>4% %>5

Figure 9: Generator differential and interturn protection

2.3.5.3 Application of overcurrent protection for interturn protection

Another method that could be used for inter-turn protection is to use the currentoperated stator earth fault protection function using an additional single CT as shownin Figure 10. In this application the neutral voltage displacement protection (59N)would act as the main stator earth fault protection even though the current basedstator earth fault protection could still respond to some stator earth fault conditions.This form of interturn fault protection, using the 51N stator earth fault currentoperated element (IN>1/2 or ISEF>1) offers the possibility of greater sensitivitycompared to the technique shown in Figure 9. This is due to the fact that therequired ratio of the single CT for this application is arbitrary. The current setting ofthe main current operated element (IN>1/2 or ISEF>1) should be set in accordancewith the selected CT ratio to provide adequate primary sensitivity for the minimuminterturn fault current. For similar reasons the time delay applied should be setsimilar to that recommended for applications of the main current operated element ofnormal stator earth fault protection.


Page 30/176 MiCOM P342, P343

%

89:

7;*&4% %+$& %5

*= & %

67

Figure 10: Overcurrent interturn protection

2.3.5.4 Interturn protection by zero sequence voltage measurement

Interturn faults in a generator with a single winding can be detected by observing thezero sequence voltage across the machine. Normally, no zero sequence voltageshould exist but a short circuit of one or more turns on one phase will cause thegenerated e.m.f. to contain some zero sequence component. This method ofinterturn protection can be provided using the neutral voltage displacementprotection in the P342/3, see section 2.14.

External earth faults will also produce a zero sequence voltage on a directlyconnected generator. Most of the voltage will be dropped across the earthingresistor, the drop on the generator being small and the zero sequence componentbeing limited to one or two percent. It is preferable, therefore, to measure thevoltage drop across the winding, rather than the zero sequence voltage to earth atthe line terminals. This can be done using a voltage transformer connected to theline side of the generator, with the neutral point of the primary winding connected tothe generator neutral, above the earthing resistor or earthing transformer. Thisarrangement is shown in Figure 11. The zero sequence voltage can be measureddirectly from the voltage transformer broken delta winding connected to the neutralvoltage input, Vn, on the P342/3. Alternatively, the zero sequence voltage can bederived from the 3 phase voltage inputs, VA, VB, VC, to the relay.

The 3rd harmonic component of the emf may be larger than the required setting,however, there is no danger of maloperation as the 3rd harmonic component isfiltered by the relay’s Fourier filter.

With a direct-connected machine it is still possible that a close up earth fault willproduce a zero sequence voltage drop greater than that produced by the shortcircuiting of one turn. It is therefore necessary to apply a short time delay to thetripping element. With a generator-transformer unit an external earth fault can not


MiCOM P342, P343 Page 31/176

draw zero sequence current through the delta winding of the transformer. Therefore,no residual voltage will be produced from the voltage transformer and so no timedelay is required in this case for the trip element.

With this type of VT connection the zero sequence voltage from the VT is small for anexternal fault. Also, the output from the star connected secondary winding of the VTwill not be able to correctly represent phase-ground voltages (for external faults), onlyphase-phase voltages will remain accurate. Therefore, the sensitive directional earthfault protection and CT supervision element, which use zero sequence voltage, maynot operate and so should be disabled. The under and over voltage protection canbe set as phase-to-phase measurement with this type of VT connection. Theunderimpedance and the voltage dependent overcurrent use phase-phase voltagesanyway, therefore the accuracy should not be affected. The protection functionswhich use phase-neutral voltages are the power, the loss of excitation and poleslipping protection; all are for detecting abnormal generator operation under 3-phase balanced conditions, therefore the accuracy of these protection functionsshould not be affected.

If the neutral voltage displacement element is required for 95% stator earth faultprotection as well as interturn protection a separate VT connection at the terminals ofthe generator or a distribution transformer at the generator earth is required to obtainthe correct zero sequence voltage. Note, the neutral voltage displacement protectionin the P342/3 relay can use the measured residual voltage from the Vn input or thederived residual voltage from the 3 phase voltage inputs but not both. So, if thederived residual voltage is used for interturn protection as shown in Figure 11, thenthe measured residual voltage from a distribution transformer at the generatorneutral point can not be used for 95% stator earth fault protection using one relay.See section 2.14 for more information on the P342/3 neutral voltage displacementprotection.

/' $

!"!

> $&4%>'

% $)?/*

/ / / /

Figure 11: Interturn protection by zero sequence voltage measurement


Page 32/176 MiCOM P342, P343

2.4 Phase fault overcurrent protection

A two stage non directional overcurrent element is provided in the P340 relays. Thiselement can be used to provide time delayed back-up protection for the system andhigh set protection providing fast operation for machine faults.

The first stage has a time delayed characteristic that can be set as either InverseDefinite Minimum Time (IDMT) or Definite Time (DT). The second stage has a definitetime delay, which can be set to zero to produce instantaneous operation. Each stagecan be selectively enabled or disabled.

This element uses the ΙA, ΙB, and ΙC relay inputs and can be fed from CTs at theterminal or neutral end of the generator, depending on the application.

Each stage can be blocked by energising the relevant DDB signal via the PSL (DDB354, DDB 355). DDB signals are also available to indicate the start and trip of eachphase of each stage of protection, (Starts: DDB 597-604, Trips: DDB 477-484). Thestate of the DDB signals can be programmed to be viewed in the “Monitor Bit x” cellsof the “COMMISSION TESTS” column in the relay.

Setting ranges for this element are shown in the following table:


Min MaxStep Size

GROUP 1:OVERCURRENT

Ι>1 Function Disabled

Disabled, DT, IEC S Inverse,IEC V Inverse, IEC E Inverse,

UK LT Inverse, UK Rectifier, RI, IEEE MInverse, IEEE V Inverse, IEEE E Inverse,

US Inverse, US ST Inverse

Ι>1 Current Set 1 x Ιn A 0.08 x Ιn A 4 x Ιn A 0.01 x Ιn A

Ι>1 Time Delay 1 s 0 100 s 0.01 s

Ι>1 TMS 1 0.025 1.2 0.025

Ι>1 Time Dial 1 0.01 100 0.01

Ι>1 K(RI) 1 0.1 10 0.05

Ι>1 Reset Char DT DT or Inverse N/A

Ι>1 tRESET 0 s 0 s 100 s 0.01s

Ι>2 Function DT Disabled or DT N/A

Ι>2 Current Set 0.08 x Ιn A 0.08 x Ιn A 10 x Ιn A 0.01 x Ιn A

Ι>2 Time Delay 0 s 0 s 100 s 0.01 s

For inverse time delayed characteristics, the following options are available. Notethat all IDMT curves conform to the following formula:

IEC Curves

t = T x

K

(Ι/Ιs) α - 1 + L


MiCOM P342, P343 Page 33/176

IEEE Curves

t = TD x

K

(Ι/Ιs) α - 1 + L

t = operation time

K = constant

Ι = measured current

Ιs = current threshold setting

α = constant

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

T = Time multiplier setting

TD = Time dial setting for IEEE curves

Curve Description Standard K constant α constant L 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

Rectifier UK 45900 5.6 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 5.95 2 0.18

Short Time Inverse US 0.16758 0.02 0.11858

Note that the IEEE and US curves are set differently to the IEC/UK curves, with regardto the time setting. A time multiplier setting (TMS) is used to adjust the operating timeof the IEC curves, whereas a time dial setting is employed for the IEEE/US curves.Both the TMS and Time Dial settings act as multipliers on the basic characteristics butthe scaling of the time dial is approximately 10 times that of the TMS, as shown in theprevious menu. The menu is arranged such that if an IEC/UK curve is selected, the“Ι>1 Time Dial” cell is not visible and vice versa for the TMS setting. The UK rectifiercurve is not required for generator protection applications but it is included forconsistency with other MiCOM products which use overcurrent protection.

Note, that the IEC/UK inverse characteristics can be used with a definite time resetcharacteristic, however, the IEEE/US curves may have an inverse or definite time resetcharacteristic. The following equation can be used to calculate the inverse reset timefor IEEE/US curves:

tRESET = TD x S

(1 - M2) in seconds


Page 34/176 MiCOM P342, P343

where:


S = Constant

M = Ι / Ιs

Curve Description Standard S Constant

Moderately Inverse IEEE 4.85

Very Inverse IEEE 21.6

Extremely Inverse IEEE 29.1

Inverse US 5.95

Short Time Inverse US 2.261

2.4.1 RI curve

The RI curve (electromechanical) has been included in the first stage characteristicsetting options for Phase Overcurrent and Earth Fault protections. The curve isrepresented by the following equation:

t = K x

1

0.339 - 0.236/M

in seconds

With K adjustable from 0.1 to 10 in steps of 0.05

M = Ι / Ιs

2.4.2 Application of timer hold facility

The first stage of overcurrent protection in the P340 relays are provided with a timerhold facility.

Setting the hold timer to zero means that the overcurrent timer for that stage will resetinstantaneously once the current falls below 95% of the current setting. Setting thehold timer to a value other than zero, delays the resetting of the protection elementtimers for this period. This may be useful in certain applications, for example whengrading with electromechanical overcurrent relays which have inherent reset time

delays. It will also enable the element to become sensitive to a pole slippingcondition where the element will cyclically operate as the machine slips successivepoles.

If an IEC inverse or DT operating characteristic is chosen for, this time delay is set viathe “Ι>1 tRESET” setting.

If an IEEE/US operate curve is selected, the reset characteristic may be set to eitherdefinite time or inverse time as selected in cell “Ι>1 Reset Char”. If definite time(‘DT’) is selected the “Ι>1 tRESET” cell may be used to set the time delay. If inversetime reset (‘Inverse’) is selected the reset time will follow the inverse time operatingcharacteristic, modified by the time dial setting, selected for “Ι>1 Function”.

Another situation where the timer hold facility may be used to reduce fault clearancetimes is where intermittent faults may be experienced. When the reset time of theovercurrent relay is instantaneous the relay will be repeatedly reset and not be able totrip until the fault becomes permanent. By using the timer hold facility the relay willintegrate the fault current pulses, thereby reducing fault clearance time.


MiCOM P342, P343 Page 35/176

2.4.3 Setting guidelines for overcurrent protection

The first stage of overcurrent protection can be selected by setting “Ι>1 Function” toany of the inverse or DT settings. The first stage is disabled if “Ι>1 Function” is set to‘Disabled’.

The first stage can provide back-up protection for faults on the generator and thesystem. As such it should be co-ordinated with downstream protection to providediscrimination for system faults, setting the current threshold (“I>1 Current Set”), andthe time delay.

“Ι>1 TMS” – for IEC curves;

“Ι>1 Time Dial” – for US/IEEE curves;

“Ι>1 Time Delay” – for definite time accordingly.

In order to provide back-up protection for the generator and system, the elementmust be supplied from CTs connected in the generator tails. If terminal end CTs areused, the element will provide protection for the system only, unless the generator isconnected in parallel to a second source of supply.

The second stage of overcurrent protection can be enabled by setting “Ι>2 Function”to DT, providing a definite time operating characteristic. The second stage isdisabled if “Ι>2 Function” is set to ‘Disabled’. Where terminal CTs are used, thesecond stage can be set as an instantaneous overcurrent protection, providingprotection against internal faults on the machine. The current setting of the secondstage, “Ι>2 Current Set”, could be set to 120% of the maximum fault rating of thegenerator, typically 8 x full load current. The operating time, “Ι>2 Time Delay”,should be set to 0s to give instantaneous operation. The stage will therefore bestable for external faults where the fault current from the generator will be below thestage current setting. For faults within the machine, the fault current will be suppliedfrom the system and will be above the second stage current setting, resulting in fastclearance of the internal fault.

2.5 System back-up protection

A generator is a source of electrical power and will supply system faults until they arecleared by system protection. Back-up protection must be applied at the generator sothat faults are cleared in the event of downstream protection/circuit breakers failingto operate.

The fault current supplied by a generator will vary during a fault condition asindicated by the generator decrement curve, shown in Figure 12. The fault currentresponse is determined by the action of the automatic voltage regulator on themachine. With some generators, fault current initiates an AVR ‘boost’ circuit whichmaintains the fault current at a relatively high level. If the voltage regulator is set tomanual control or no boost circuit exists, the fault current can be severely restricted,leading to slow operation of back-up protection for system faults. In the worst casethe fault current will fall below the full load rating of the machine, so simpleovercurrent protection with a setting above full load current, cannot operate.


Page 36/176 MiCOM P342, P343

%%

<56 <56

Figure 12: Typical generator fault current decrement curve

System back-up protection must operate quickly during a fault and must not operatefor load conditions. To achieve these two objectives, two methods of system back-upprotection are commonly used:

1. Voltage dependant overcurrent protection. The presence of a fault is detectedby an under voltage element and the relay setting is adjusted accordingly.Voltage dependant overcurrent protection can beoperated in a ‘voltagecontrolled’ or ‘voltage restrained’ mode.

2. Under impedance protection. This element is set to monitor the systemimpedance at the terminals of the machine. If the impedance measured fallsbelow a set threshold then the element will operate.

Customer preference will determine the mode of operation. However, subtleapplication benefits can be claimed for one form of protection over the other incertain circumstances.

A single protection element, that can be configured as either voltage dependantovercurrent or under impedance, is provided in the P340 relay for system back-upprotection. The operation of the element is described in the following sections.

The function operates from the phase currents measured by the ΙA, ΙB and ΙCmeasurement inputs on the relay.

The voltage dependent overcurrent and underimpedance System Backup protectionelements can be blocked by energising the relevant DDB signal via the PSL, (VDepOCTimer Block, DDB 352 and UnderZ Timer Block, DDB 353). DDB signals are alsoavailable to indicate a 3 phase and per phase start and trip, (Voltage dependentovercurrent Starts: DDB 639-642, Voltage dependent overcurrent Trips: DDB 425-428, Underimpedance Starts: DDB 650-657, Underimpedance Trips: DDB 500-507).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.



MiCOM P342, P343 Page 37/176


Min MaxStep Size

GROUP 1:SYSTEM BACK-UP

Back-up FunctionVoltage

Controlled

Disabled, Voltage Controlled,Voltage Restrained,Under Impedance

Vector Rotation None None, Delta-Star N/A

V Dep OC Char IEC S Inverse

DT, IEC S Inverse, IEC V Inverse,IEC E Inverse, UK LT Inverse, UK Rectifier, RI,

IEEE M Inverse, IEEE V Inverse, IEEE EInverse, US Inverse, US ST Inverse

V Dep OC Ι> Set 1 x Ιn A 0.8 x Ιn A 4 x Ιn A 0.01 x Ιn A

V Dep OC T Dial 1 0.01 100 0.01

V Dep OC Reset DT DT or Inverse N/A

V Dep OC Delay 1 s 0 s 100 s 0.01 s

V Dep OC TMS 1 0.025 1.2 0.025

V Dep OC K(RI) 1 0.1 10 0.05

V Dep OC tRESET 0 s 0 s 100 s 0.01 s

V Dep OCV<1Set

80V(Vn=100/120V)

320 V(Vn=380/480V)

5V(Vn=100/120V)

80V(Vn=380/480V)

120V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

V Dep OCV<2Set

60V(Vn=100/120V)

240V(Vn=380/480V)

5V(Vn=100/120V)

80V(Vn=380/480V)

120V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

V Dep OC k Set 0.25 0.1 1 0.05s

Z<1 Setting

70/ΙnΩ(Vn=100/120V)

120/ΙnΩ(Vn=380/480V)

2/ΙnΩ(Vn=100/120V)

2/ΙnΩ(Vn=380/480V)

120/ΙnΩ(Vn=100/120V)

480/ΙnΩ(Vn=380/480V)

0.5/ΙnΩ(Vn=100/120V)

2/ΙnΩ(Vn=380/480V)

Z<1 Time Delay 5 s 0 s 100 s 0.01 s

Z<1 tRESET 0 s 0 s 100 s 0.01 s

Z< Stage 2 Disabled Disabled, Enabled

Z<2 Setting

70/ΙnΩ(Vn=100/120V)

120/ΙnΩ(Vn=380/480V)

2/ΙnΩ(Vn=100/120V)

2/ΙnΩ(Vn=380/480V)

120/ΙnΩ(Vn=100/120V)

480/ΙnΩ(Vn=380/480V)

0.5/ΙnΩ(Vn=100/120V)

2/ΙnΩ(Vn=380/480V)

Z<2 Time Delay 5 s 0 s 100 s 0.01 s

Z<2 tRESET 0 s 0 s 100 s 0.01 s

For inverse time delayed characteristics refer to the phase overcurrent elements,section 2.4.


Page 38/176 MiCOM P342, P343

2.5.1 Voltage dependant overcurrent protection

The generator terminal voltage will drop during fault conditions and so a voltagemeasuring element can be used to control the current setting of this element. Ondetection of a fault the current setting is reduced by a factor K. This ensures faults arecleared in spite of the presence of the generator decrement characteristic. Linevoltages are used to control each phase overcurrent element as shown below.

Phase Current Control Voltage

Ιa Vab

Ιb Vbc

Ιc Vca

A single stage, non directional overcurrent element is provided. The element has atime delayed characteristic that can be set as either Inverse Definite Minimum Time(IDMT) or Definite Time (DT). The element can be selectively enabled or disabled andcan be blocked via a relay input so that the element can be integrated into a blockedovercurrent protection scheme.

The element can be fed from CTs at the terminal or neutral end of the generator.

If voltage dependant overcurrent operation is selected, the element can be set in oneof two modes, voltage controlled overcurrent or voltage restrained overcurrent.

2.5.1.1 Voltage controlled overcurrent protection

In this mode of operation, the under voltage detector is used to produce a stepchange in the relay current setting (from “V Dep OC Ι> Set” to“V Dep OC k Set” x “V Dep OC Ι> Set”), when voltage falls below the voltagesetting, “V Dep OC V>1 Set”. Under load conditions the relay can have a highcurrent setting greater than full load current. Under fault conditions the relay isswitched to a more sensitive setting leading to fast fault clearance. The operatingcharacteristic of the current setting when voltage controlled mode is selected is shownin Figure 13.

@

@

%'

%>'/A

Figure 13: Modification of current pickup level for voltage controlled overcurrent protection


MiCOM P342, P343 Page 39/176

Where the generator is directly connected to a busbar, voltage controlled overcurrentprotection may be preferred.Setting guidelines for voltage controlled overcurrentfunction

Voltage controlled overcurrent protection can be selected by setting“Backup Function” to ‘Voltage controlled’. The protection is disabled if “BackupFunction” is set to ‘Disabled’.

The current setting, “V Dep OC Ι> Set”, should be set to have a primary operatingvalue in excess of the maximum generator load current.

The current setting multiplying factor, “V Dep OC k Set”, governs the protectionfunction setting under low voltage conditions. This should be set to give a primaryoperating current less than 50% of the minimum steady-state fault current for a multi-phase fault at the remote end of a feeder, with the generator being the only source.This ensures the element will provide adequate back-up protection for an unclearedfault on that feeder.

The voltage-controlled protection fault characteristic should co-ordinate with outgoingfeeder protection for a feeder fault under minimum plant conditions. The operatingcharacteristic, “V Dep OC Char” and the time delay (“V Dep OC TMS” – for IECcurves; “V Dep OC T Dial” – for US/IEEE curves; “V Dep OC Delay” for definite time)should be selected accordingly.

Where parallel sources are present, a remote feeder fault may not result in asufficient voltage reduction to enable the fault characteristic. For such applications atime undervoltage element can be used to clear the fault (see section 2.6).Alternatively, negative sequence thermal protection could be used (see section 2.11).

The voltage setting for switching between load and fault characteristics,“V Dep OC V<1 Set”, should be greater than the terminal voltage for a fault whereback-up protection is required. On a solidly earthed system the element can bemade insensitive to earth faults by ensuring that the voltage setting is below 57%Vn(minimum phase to phase voltage for a single phase to earth fault). A typical settingwould be 30%Vn. A voltage setting higher than 57%Vn will allow the relay operatingcharacteristic to change for both phase and earth faults.

More accurate settings may be determined with reference to the following equations.

The minimum fault current for a remote-end multi-phase fault on a feeder can bedetermined as follows. This calculation is based on no-load excitation being appliedand no field-forcing or AVR action during the fault.

Three-phase fault: Ιf =

En

(nRf)2 + (Xs + nXf)2

Phase to phase fault: Ιf =

3En

(2nRf)2 + (Xs + X2 + 2nXf)2

where

Ιf = Minimum generator primary current seen for a multi-phase feeder-end fault

En = No-load phase-neutral internal e.m.f. of generator

Xs = Direct-axis synchronous reactance of the generator


Page 40/176 MiCOM P342, P343

X2 = Negative phase sequence reactance of the generator

Rf = Feeder positive phase sequence resistance

Xf = Feeder positive phase sequence reactance

n = Number of parallel generators

The steady-state voltage seen by the relay under external fault conditions can bededuced as follows:

Three-phase fault: V- =

En 3 ((nRf)2 + (nXf)2)

(nRf)2 + (Xs + nXf)2

Phase-phase fault: V- =

2En 3 ((nRf)2 + (nXf)2)

(2nRf)2 + (Xs + 2nXf)2

The current setting multiplier, “V Dep OC k Set”, must be set such that“V Dep OC k Set” x “V Dep OC Ι Set” is less than Ιf as calculated above. Thevoltage setting, “V Dep OC V<1 Set”, must be greater than. V- as calculatedabove.

The voltage controlled overcurrent protection is provided with a timer hold facility, asdescribed in section 2.5.1.1. Setting the hold timer to a value other than zero delaysthe resetting of the protection element timers for this period.

If an IEC inverse or DT operating characteristic is chosen, this hold time delay is setvia the “V Dep OC tRESET” setting.

If an IEEE/US operate curve is selected, the reset characteristic may be set to eitherdefinite time or inverse time as selected in cell “V Dep OC Reset Char”. If definitetime (‘DT’) is selected the “V Dep OC tRESET” cell may be used to set the time delay,as above. If inverse time reset (‘Inverse’) is selected the reset time will follow theinverse time operating characteristic, modified by the time dial setting, selected for “VDep OC Function”.

2.5.1.2 Voltage restrained overcurrent protection

In voltage restrained mode the effective operating current of the protection element iscontinuously variable as the applied voltage varies between two voltage thresholds,“V Dep OC V<1 Set” and “V Dep OC V<2 Set”, as shown in Figure 14. In thismode, it is quite difficult to determine the behaviour of the protection function duringa fault. This protection mode is, however, considered to be better suited toapplications where the generator is connected to the system via a generatortransformer. With indirect connection of the generator, a solid phase-phase fault onthe local busbar will result in only a partial phase-phase voltage collapse at thegenerator terminals.


MiCOM P342, P343 Page 41/176

@

@

%'

%>'/A/A

Figure 14: Modification of current pickup level for voltage restrained overcurrent protection

To improve the sensitivity of the voltage-restrained overcurrent protection function, forHV phase-phase faults fed via a Yd1 or Yd11 step-up transformer, the appropriatevoltage signal transformation facility should be switched in as part of the P340settings. In the past, such correction of voltage signals has been addressed byadopting phase-neutral voltage measurement or the use of a star/delta interposing

VT. Such an approach cannot be adopted with P340 since the relay voltage inputsare common to other protection and measurement functions that would beundesirably affected by voltage signal correction.

The P340 voltage-restrained current setting is related to measured voltage as follows:

For V > Vs1: Current setting (Ιs) = Ι>

For Vs2 < V < Vs1: Current setting (Ιs) = K.Ι> + ( Ι > - K. Ι> )

V - Vs2

Vs1 - Vs2

For V < Vs2: Current setting (Ιs) = K.Ι>

where:

Ι> = “V Dep OC Ι> Set”

Ιs = Current setting at voltage V

V = Voltage applied to relay element

Vs1 = “V Dep OC V<1 Set”

Vs2 = “V Dep OC V<2 Set”

2.5.1.3 Setting guidelines for voltage controlled overcurrent function

Voltage restrained overcurrent protection can be selected by setting“Backup Function” to ‘Voltage Restrained’. The protection is disabled if“Backup Function” is set to ‘Disabled’.


Page 42/176 MiCOM P342, P343

The performance criteria on which the settings of the voltage-restrained overcurrentprotection function should be based are similar to those discussed for the voltagecontrolled mode in section 2.5.1.2. Co-ordination with downstream protectionshould be ensured when the relay is on its most sensitive settings i.e. for voltages lessthan the “V Dep OC V<2 Set” setting. Current threshold, characteristic and timedelay can be selected as described for the Voltage Controlled function described insection 2.5.1.2.

The voltage restrained overcurrent function should be able to respond to a remote-end fault on an outgoing feeder. Where the generator is connected via a step uptransformer, zero sequence quantities will not be present at the relay location for HVside earth faults. Therefore, it would be normal to use negative sequence thermalprotection for back-up protection in this case. The negative phase sequence thermalelement will also provide back-up protection for phase to phase faults. For thisreason, consideration will only be given to the detection of a remote-end three-phasefeeder fault, with the protected machine as the only source.

For a remote-end, three-phase fault, it is possible to calculate the level of current andvoltage at the relay location. It should be ensured that the relay current setting, “VDep OC k Set” x “V Dep OC Ι Set”, should be set to less than 50% of the faultcurrent. It must also be ensured that the voltage threshold, “V Dep OC V<2 Set”, isset to a value above the voltage measured at the relay. There would be no need forfurther reduction in the current setting for closer faults, which would yield highercurrents and lower voltages. Further reduction in the current setting for closer faultsmay make co-ordination with local feeder overcurrent protection more difficult (if thisis not already a problem).

The steady-state primary current and voltage magnitudes seen for a feeder remote-end three-phase fault are given as follows:

where:

Ιf = Minimum generator primary current seen for a multi-phase feeder-end fault

En = No-load phase-neutral internal e.m.f. of generator

Xs = Direct-axis synchronous reactance of the generator

X2 = Negative phase sequence reactance of the generator

Xt = Step-up transformer reactance

Rf = Feeder positive phase sequence resistance

Xf = Feeder positive phase sequence reactance

n = Number of parallel generators

All above quantities are to referred to the generator side of the transformer.

The upper voltage threshold setting, “V Dep OC V<1 Set”, should be set below theminimum corrected phase-phase voltage level for a close-up HV earth fault, to ensurethat the element is insensitive to the fault. In the case of HV solid earthing, thisvoltage would be a minimum of 57% of the nominal operating voltage.

The voltage restrained overcurrent protection is provided with a timer hold facility, asdescribed in section 2.5.1.1. Setting the hold timer to a value other than zero, delaysthe resetting of the protection element timers for this period.

If an IEC inverse or DT operating characteristic is chosen, this hold time delay is setvia the “V Dep OC tRESET” setting.


MiCOM P342, P343 Page 43/176

If an IEEE/US operate curve is selected, the reset characteristic may be set to eitherdefinite time or inverse time as selected in cell “V Dep OC Reset Char”. If definitetime (‘DT’) is selected the “V Dep OC tRESET” cell may be used to set the time delay,as above. If inverse time reset (‘Inverse’) is selected the reset time will follow theinverse time operating characteristic, modified by the time dial setting, selected for “VDep OC Function”.

2.5.2 Under impedance protection

When the element is set to under impedance mode the element operates with a timedelayed three phase non directional impedance characteristic, shown in Figure 15.

*

B

Figure 15: Under impedance element tripping characteristic

Impedance for each phase is calculated as shown:

Za = Vab

Ιa Zb =

Vbc

Ιb Zc

Vca

Ιc

With rated voltage applied, the element operates as a definite time overcurrent relay.It operates at a lower current as the voltage reduces, hence the element is similar to avoltage restrained overcurrent element, operating with a definite time characteristic.

Under impedance protection is an alternative to voltage dependent overcurrentprotection and is often preferred due to its ease of setting. The definite time delaymay be difficult to provide co-ordination with downstream inverse time overcurrentprotections but will be easier to co-ordinate with distance protection.

The impedance measurement is based on phase-phase voltage and phase-neutralcurrent. This is to make the protection immune to earth faults on the low voltage sideof the generator-transformer or for a machine directly connected to the busbars. Themain purpose is to provide back-up protection for phase-phase and 3 phase faults.Earth fault protection should be allowed to clear earth faults.

The underimpedance protection has 2 stages of impedance protection. Forgenerator transformer applications one stage could be used to reach into the step-uptransformer and one stage to reach further into the power system to provide 2 zonesof protection.


Page 44/176 MiCOM P342, P343

The minimum phase current and the line voltage required for the P342/P343 underimpedance protection to work is 20mA and 2V (Ιn = 1A, Vn = 100/120V) and100mA and 8V (Ιn = 5A, Vn = 380/480V). Note, that the under impedance consistsof separate three phase elements and the checking is done on a per phase basis, i.e.the inhibition of one phase will not affect the other phases.

2.5.2.1 Setting guidelines for under impedance function

Under impedance protection can be selected by setting “Backup Function” to‘Under Impedance’. The protection is disabled if “Backup Function” is set to‘Disabled’. As phase-phase voltage is used in the measurement of impedance theimpedance settings should be increased by a factor of √3 to account for this.

The first stage impedance setting, “Z<1 Setting”, should be set to 70% of themaximum load impedance. This gives an adequate margin for short time overloads,voltage variation etc., whilst giving adequate back-up protection for generator,generator-transformer and busbar faults.

For example Z<1 = 3 x 0.7 x

Vph - n

Ιflc x 1.2

allowing for a 20% overload of the generator full load current.

The second stage impedance setting “Z<2 Setting”, could be set to 50 – 60% of thegenerator-transformer impedance. This stage can then be used to obtain fasteroperation for faults closer to the generator.

The time delay, “Z<1 Time Delay” should allow co-ordination with downstreamovercurrent and distance protection devices and with the zone 2 underimpedanceprotection. The time delay, “Z<2 Time Delay” should allow co-ordination withgenerator and transfomer LV phase fault protection.

The under impedance protection is provided with a timer hold facility, as described insection 2.5.1.1. Setting the hold timer, “Z< tRESET”, to a value other than zero,delays the resetting of the protection element timer for this period.

2.6 Undervoltage protection function (27)

Under voltage protection is not a commonly specified requirement for generatorprotection schemes. However, under voltage elements are sometimes used asinterlocking elements for other types of protection, such as field failure. In the P340,this type of interlocking can be arranged via the relay scheme logic. Undervoltageprotection may also be used for back-up protection where it may be difficult toprovide adequate sensitivity with voltage dependant/underimpedance/negative phasesequence elements.

For an isolated generator, or isolated set of generators, a prolonged undervoltagecondition could arise for a number of reasons. One reason would be failure ofautomatic voltage regulation (AVR) equipment. Where an auxiliary transformer isused to supply generator ancillary equipment, such as boiler-feed pumps, air-blowers, lubrication pumps etc., a prolonged undervoltage condition could adverselyaffect the performance of the machine. If such a situation is envisaged, theapplication of time-delayed undervoltage protection might be a consideration.


MiCOM P342, P343 Page 45/176

A two stage undervoltage 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. Selectable, fixed Logic isincluded within the relay to allow the operation of the element to be inhibited duringperiods when the machine is isolated from the external system.

Each stage of undervoltage protection can be blocked by energising the relevant DDBsignal via the PSL, (DDB 158, DDB 159). DDB signals are also available to indicatea 3 phase and per phase start and trip, (Starts: DDB 579-586, Trips: DDB 453-460).

Note: If the undervoltage protection is set for phase-phase operation then theDDB signals V<1/2 Start/Trip A/AB, V<1/2 Start/Trip B/BC, V<1/2Start/ Trip C/CA refer to V<1/2 Start/Trip AB and V<1/2 Start/Trip BCand V<1/2 Start/Trip CA. If set for phase-neutral then the DDB signalsV<1/2 Start/Trip A/AB, V<1/2 Start/Trip B/BC, V<1/2 Start/Trip C/CArefer to V<1/2 Start/Trip A and V<1/2 Start/Trip B and V<1/2Start/Trip C.

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.



Min MaxStep Size

GROUP 1:

VOLTAGE 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

80V(Vn=100/120V)

320V(Vn=380/480V)

10V(Vn=100/120V)

40V(Vn=380/480V)

120V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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

80V(Vn=100/120V)

320V(Vn=380/480V)

10V(Vn=100/120V)

40V(Vn=380/480V)

120V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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

V<1 Poledead Inh Enabled Disabled, Enabled

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

t = K / (1 – M)


Page 46/176 MiCOM P342, P343

where

K = Time Multiplier Setting (V<1 TMS)

t = Operating Time in Seconds

M = Measured Voltage /Relay Setting Voltage (V<1 Voltage Set)

2.6.1 Setting guidelines for undervoltage 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. Thetime delay (“V<1 TMS” - for IDMT curve; “V<1 Time Delay”, “V<2 Time Delay” - fordefinite time) should be adjusted accordingly.

The undervoltage protection can be set to operate from phase-phase or phase-neutral voltage as selected by “V< Measur’t Mode”. Single or three phase operationcan be selected in “V<1 Operate Mode”. When ‘Any Phase’ is selected, the elementwill operate if any phase voltage falls below setting, when ‘Three Phase’ is selectedthe element will operate when all three phase voltages are below the setting.

If the undervoltage protection function is to be used for back-up protection, thevoltage setting, ”V<1 Voltage Set”, should be set above the steady-state phase-phasevoltage seen by the relay for a three-phase fault at the remote end of any feederconnected to the generator bus. Allowances should be made for the fault currentcontribution of parallel generators, which will tend to keep the generator voltage up.If the element is set to operate from phase to phase voltages operation for earthfaults can be minimised, i.e. set “V< Measur’t Mode” to ‘Phase-Phase’. To allowdetection of any phase to phase fault, “V< Operate Mode” should be set to ‘Any-Phase’. Equations for determining the phase-phase voltage seen by the relay undersuch circumstances are given in section 2.5.1.2.

The operating characteristic would normally be set to definite time, set“V<1 Function” to ‘DT’. The time delay, “V<1 Time Delay”, should be set to co-ordinate with downstream protections and the System Back-up protection of the relay,if enabled. Additionally, the delay should be long enough to prevent unwanted

operation of the under voltage protection for transient voltage dips. These may occurduring clearance of faults further into the power system or by starting of localmachines. The required time delay would typically be in excess of 3s-5s.

The second stage can be used as an alarm stage to warn the user of unusual voltageconditions so that corrections can be made. This could be useful if the machine isbeing operated with the AVR selected to manual control.

Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (e.g. requirements of G59in the UK), the local electricity supply authority may advise settings for the element.The settings must prevent the generator from exporting power to the system withvoltage outside of the statutory limits imposed on the supply authority.

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 “VPoledead Inh” to ‘Enabled’. This will ensure that when a poledead condition isdetected (i.e. all phase currents below the undercurrent threshold or CB Open, asdetermined by an opto isolator and the PSL) the undervoltage element will beinhibited.


MiCOM P342, P343 Page 47/176

2.7 Overvoltage protection

A generator terminal overvoltage condition could arise when the generator is runningbut not connected 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 fault withautomatic voltage regulating equipment or if the voltage regulator is set for manualcontrol and an operator error is made. Overvoltage protection should be set toprevent possible damage to generator insulation, prolonged overfluxing of thegenerating plant, or damage to power system loads.

When a generator is synchronised to a power system with other sources, anovervoltage could arise if the generator is lightly loaded supplying a high level ofpower system capacitive charging current. An overvoltage condition might also bepossible following a system separation, where a generator might experience full-loadrejection whilst still being connected to part of the original power system. Theautomatic voltage regulating equipment and machine governor should quicklyrespond to correct the overvoltage condition in these cases. However, over voltageprotection is advisable to cater for a possible failure of the voltage regulator or forthe regulator having been set to manual control. In the case of Hydro generators, theresponse time of the speed governing equipment can be so slow that transient overspeeding up to 200% of nominal speed could occur. Even with voltage regulatoraction, such over speeding can result in a transient over voltage as high as 150%.Such a high voltage could result in rapid insulation damage.

A two stage overvoltage element is provided. The element can be set to operate fromphase-phase or phase-neutral voltages. Each stage has an independent time delaywhich can be set to zero for instantaneous operation.

Each stage of overvoltage protection can be blocked by energising the relevant DDBsignal via the PSL, (DDB 368, DDB 369). DDB signals are also available to indicatea 3 phase and per phase start and trip, (Starts: DDB 587-594, Trips: DDB 461-468).

Note: If the overvoltage protection is set for phase-phase operation then theDDB signals V>1/2 Start/Trip A/AB, V>1/2 Start/Trip B/BC, V>1/2Start/Trip C/CA refer to V>1/2 Start/Trip AB and V>1/2 Start/Trip BCand V>1/2 Start/Trip CA. If set for phase-neutral then the DDB signalsV>1/2 Start/Trip A/AB, V>1/2 Start/Trip B/BC, V>1/2 Start/Trip C/CArefer to V>1/2 Start/Trip A and V>1/2 Start/Trip B and V>1/2Start/Trip C.



Min MaxStep Size

GROUP 1:VOLTAGE 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

150V(Vn=100/120V)

600V(Vn=380/480V)

60V(Vn=100/120V)

240V(Vn=380/480V)

185V(Vn=100/120V)

740V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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


Page 48/176 MiCOM P342, P343


Min MaxStep Size

GROUP 1:VOLTAGE PROTECTION

V>1 TMS 1 0.5 100 0.5

V>2 Status DT Disabled DT

V>2 Voltage Set

130V(Vn=100/120V)

520V(Vn=380/480V)

60V(Vn=100/120V)

240V(Vn=380/480V)

185V(Vn=100/120V)

740V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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


t = K / (M - 1)

where

K = Time Multiplier Setting (“V>1 TMS”)


M = Measured Voltage/Relay Setting Voltage (“V>1 Voltage Set”)

2.7.1 Setting guidelines for overvoltage 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 inthe “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 selectedaccordingly.

The undervoltage 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’ is selectedthe element will operate if any phase voltage falls below setting, when ‘Three Phase’is selected the element will operate when all three phase voltages are above thesetting.

Generators can typically withstand a 5% overvoltage condition continuously.The withstand times for higher overvoltages should be declared by the generatormanufacturer.

To prevent operation during earth faults, the element should operate from the phase-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 overvoltage threshold, “V>1Voltage Set”, should typically be set to 100%-120% of the nominal phase-phasevoltage seen by the relay. The time delay, “V>1 Time Delay”, should be set toprevent unwanted tripping of the delayed overvoltage protection function due totransient over voltages that do not pose a risk to the generating plant; e.g. followingload rejection where correct AVR/Governor control occurs. The typical delay to beapplied would be 1s-3s, with a longer delay being applied for lower voltagethreshold settings.


MiCOM P342, P343 Page 49/176

The second stage can be used to provide instantaneous high-set over voltageprotection. The typical threshold setting to be applied, “V>2 Voltage Set”, would be130-150% of the nominal phase-phase voltage seen by the relay, depending onplant manufacturers’ advice. For instantaneous operation, the time delay,“V>2 Time 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 (e.g. requirements of G59in the UK), the local electricity supply authority may advise settings for the element.The settings must prevent the generator from exporting power to the system withvoltages outside of the statutory limits imposed on the supply authority.

If phase to neutral operation is selected, care must be taken to ensure that theelement will grade with downstream protections during earth faults, where the phase-neutral voltage can rise significantly.

2.8 Underfrequency protection

Underfrequency operation of a generator will occur when the power system loadexceeds the prime mover capability of an islanded generator or group of generators.Power system overloading can arise when a power system becomes split, with loadleft connected to a set of ‘islanded’ generators that is in excess of their capacity. Suchevents could be compensated for by automatic load shedding. In this case,underfrequency operation would be a transient condition. In the event of the loadshedding being unsuccessful, the generators should be provided with back-upunderfrequency protection.

An underfrequency condition, at nominal voltage, may result in some over fluxing ofa generator and its associated electrical plant. However, the more criticalconsiderations would be in relation to blade stresses being incurred with high-speedturbine generators; especially steam-driven sets. When not running at nominalfrequency, abnormal blade resonance’s can be set up which, if prolonged, couldlead to turbine disc component fractures. Such effects can be accumulative and sooperation at frequencies away from nominal should be limited as much as possible,to avoid the need for early plant inspections/overhaul. Underfrequency running isdifficult to contend with, since there is little action that can be taken at the generatingstation in the event of overloading, other than to shut the generator down.

Four independent definite time-delayed stages of underfrequency protection areoffered. Two additional overfrequency stages can also be reconfigured asunderfrequency protection by reprogramming the Programmable Scheme Logic. Aswell as being able to initiate generator tripping, the underfrequency protection can

also be arranged to initiate local load-shedding, where appropriate. Selectable fixedscheme logic is provided to allow each stage of underfrequency protection to bedisabled when the outgoing CB is open, to prevent unnecessary load tripping.

Each stage of underfrequency protection can also be blocked by energising therelevant DDB signal via the PSL, (DDB 374 - DDB 377). DDB signals are alsoavailable to indicate start and trip of each stage, (Starts: DDB 622-625, Trips: DDB469-472). 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.



Page 50/176 MiCOM P342, P343


Min MaxStep Size

GROUP 1:FREQUENCY 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 4 s 0.1 s 100 s 0.1 s

F<2 Status Enabled Disabled, Enabled


F<2 Time Delay 4 s 0.1 s 100 s 0.1 s

F<3 Status Enabled Disabled Enabled


F<3 Time Delay 4 s 0.1 s 100 s 0.1 s

F<4 Status Enabled Disabled Enabled


F<4 Time Delay 4 s 0.1 s 100 s 0.1 s

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

2.8.1 Setting guidelines for underfrequency 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 timedelays, “F<x Time Delay”, for each stage should be selected accordingly.

The protection function should be set so that declared frequency-time limits for thegenerating set are not infringed. Typically, a 10% under frequency condition shouldbe continuously sustainable.

For industrial generation schemes, where generation and loads may be undercommon control/ownership, the P340 under frequency protection function could beused to initiate local system load-shedding. Four stage under frequency/loadshedding can be provided. The final stage of underfrequency protection should beused to trip the generator.

Where separate load shedding equipment is provided, the underfrequency protectionshould co-ordinate with it. This will ensure that generator tripping will not occur inthe event of successful load shedding following a system overload. Two stages ofunder frequency protection could be set-up, as illustrated in Figure 16, to co-ordinatewith multi-stage system load-shedding.


MiCOM P342, P343 Page 51/176

C%

A

A

*$

*%)&)

$ C%+&$$%$& >

$ C%+&%&'

$%$% C%&

Figure 16: Co-ordination of underfrequency protection function with system load shedding

To prevent operation of any underfrequency stage during normal shutdown of thegenerator “poledead” logic is included in the relay. This is facilitated for each stageby setting the relevant bit in “F< Function Link”. For example if “F< Function Link” isset to 0111, Stage 1, 2 and 3 of underfrequency protection will be blocked when thegenerator CB is open. Selective blocking of the frequency protection stages in thisway will allow a single stage of protection to be enabled during synchronisation oroffline running to prevent unsynchronised overfluxing of the machine. When themachine is synchronised, and the CB closed, all stages of frequency protection will beenabled providing a multi stage load shed scheme if desired.

Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (e.g. requirements of G59in the UK), the local electricity supply authority may advise settings for the element.The settings must prevent the generator from exporting power to the system withfrequency outside of the statutory limits imposed on the supply authority. Where thelocal external load exceeds the generator capacity, underfrequency protection may beused to provide ‘Loss of Mains’ protection.


Page 52/176 MiCOM P342, P343

2.9 Overfrequency protection function

Overfrequency running of a generator arises when the mechanical power input to thealternator is in excess of the electrical load and mechanical losses. The mostcommon occurrence of overfrequency is after substantial loss of load. When a rise inrunning speed occurs, the governor should quickly respond to reduce the mechanicalinput power, so that normal running speed is quickly regained. Overfrequencyprotection may be required as a back-up protection function to cater for governor orthrottle control failure following loss of load or during unsynchronised running.

Moderate overfrequency operation of a generator is not as potentially threatening tothe generator and other electrical plant as underfrequency running. Action can betaken at the generating plant to correct the situation without necessarily shutting downthe generator.

Severe overfrequency operation of a high-speed generating set could result in plantdamage, as described in section 2.12, as a result of the high centrifugal forces thatwould be imposed on rotating components.

Two independent time-delayed stages of overfrequency protection are provided.

Each stage of protection can be blocked by energising the relevant DDB signal via thePSL, (DDB 378, DDB 379). DDB signals are also available to indicate start and tripof each stage, (Starts: DDB 626-627, Trips: DDB 473-474). A further DDB ‘Field FailAlarm’ signal is generated from the field failure alarm stage (DDB 309). The state ofthe DDB signals can be programmed to be viewed in the “Monitor Bit x” cells of the“COMMISSION TESTS” column in the relay.



Min MaxStep Size

GROUP 1:FREQUENCY PROTECTION

Overfrequency Sub Heading

F>1 Status Enabled Disabled, Enabled

F>1 Setting 49.5 Hz 45 Hz 68 Hz 0.01 Hz

F>1 Time Delay 4 s 0.1 s 100 s 0.1 s

F>2 Status Enabled Disabled, Enabled

F>2 Setting 49.5 Hz 45 Hz 68 Hz 0.01 Hz

F>2 Time Delay 4 s 0.1 s 100 s 0.1 s

2.9.1 Setting guidelines for overfrequency protection

Each stage of overfrequency 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 P340 overfrequency settings should be selected to co-ordinate with normal,transient overfrequency excursions following full-load rejection. The generatormanufacturer should declare the expected transient overfrequency behaviour, whichshould comply with international governor response standards. A typicaloverfrequency setting would be 10% above nominal.


MiCOM P342, P343 Page 53/176

Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (e.g. requirements of G59in the UK), the local electricity supply authority may advise settings for the element.The settings must prevent the generator from exporting power to the system withfrequency outside of the statutory limits imposed on the supply authority.

2.10 Field failure protection function (40)

Complete loss of excitation may arise as a result of accidental tripping of theexcitation system, an open circuit or short circuit occurring in the excitation DC circuit,flashover of any slip rings or failure of the excitation power source. The field failureprotection of the P340 consists of two elements, an impedance element with two timedelayed stages and a power factor alarm element, illustrated below in Figure 17.The elements operate from A phase current and A phase voltage signals measuredby the ΙA and VA inputs on the relay. The minimum phase current and voltagerequired for P342/P343 field failure protection to work is 20mA and 1V (Ιn = 1A, Vn= 100/120V) and 100mA and 4V (Ιn = 5A, Vn = 380/480V).

B7$$&'$

3B

B)B)

3B$'

Figure 17: Field failure protection characteristics

When the excitation of a synchronous generator fails, its internal e.m.f. will decay.This results in the active power output of the machine falling and in an increasinglevel of reactive power being drawn from the power system. As the active poweroutput falls, the mechanical drive can accelerate the machine so that it will gentlypole slip and run at a super synchronous speed. This results in slip frequencycurrents being induced in the rotor body, damper windings and in the field windings.The slip-induced, low-frequency rotor currents will result in a rotor flux beingproduced. The machine would then be excited from the power system and hence beoperating as an induction generator. The ability to reach such a stabilised state willbe dependent on the machine’s effective speed-torque characteristic when operatingas an induction generator, and also on the power system being able to supply therequired reactive power without severe voltage depression.

Stable operation as an induction generator might be achieved at low slip (0.1-0.2%above synchronous speed), particularly in the case of salient pole machines. Themachine may be able to maintain an active power output (perhaps 20-30% of rating)whilst drawing reactive power from the power system (generating at a highly leadingpower factor). This condition could probably be sustained for many minutes withoutrotor damage being incurred and may not be detectable by traditional field failureimpedance characteristic elements. The P340, however, offers a power factor alarm


Page 54/176 MiCOM P342, P343

element in the field failure protection which can operate when the generator isrunning in this condition.

Cylindrical rotor machines have a much lower output capability when operating asan induction generator under excitation failure conditions. They are more likely to bepushed over the peak torque level of their induction generator speed-torquecharacteristic. If the peak induction generator torque level is exceeded, a machinecan stabilise at a much higher level of slip (perhaps 5% above synchronous speed).When this happens, the machine will draw a very high reactive current from thepower system and a stator winding current as high as 2.0 p.u. may be reached. Theslip-frequency rotor currents could lead to rotor core or winding damage if thecondition is sustained.

Operation as an induction generator under field failure conditions relies upon theability of the rest of the system being able to supply the required reactive power to themachine. If the system cannot supply enough reactive power the system voltage willdrop and the system may become unstable. This could occur if a large generatorrunning at high power suffers a loss of field when connected to a relatively weaksystem. To ensure fast tripping under this condition one of the impedance elementscan be used with a short time delay. This can trip the machine quickly to preservesystem stability. This element should have a small diameter to prevent tripping underpower swinging conditions. The second impedance element, set with a largerdiameter, can provide detection of field failure under lightly loaded conditions. Thissecond element should be time delayed to prevent operation during power swingconditions.

The Field Failure protection impedance elements are also provided with an adjustabledelay on reset (delayed drop off) timer. This time delay can be set to avoid delayedtripping that may arise as a result of cyclic operation of the impedance measuringelement, during the period of pole slipping following loss of excitation. Some carewould need to be exercised in setting this timer, since it could make the Field Failureprotection function more likely to give an unwanted trip in the case of stable powerswinging. The impedance element trip time delay should therefore be increasedwhen setting the reset time delay.

The delay on reset timer might also be set to allow the field failure protection functionto be used for detecting pole slipping of the generator when excitation is not fully lost;e.g. following time-delayed clearance of a nearby power system fault. This subject isdiscussed in more detail in section 2.21.

DDB signals are available to indicate the start and tripping of each stage (Starts:DDB 637, DDB 638, Trips: DDB 422, DDB 423). 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 field failure elements are shown in the following table:


Min MaxStep Size

GROUP 1FIELD FAILURE

FFail Alm Status Disabled Disabled Enabled

FFail Alm Angle 15° 15° 75° 1°

FFail Alm Delays 5s 0s 100s 0.1s

FFail1 Status Enabled Disabled, Enabled


MiCOM P342, P343 Page 55/176


Min MaxStep Size

GROUP 1FIELD FAILURE

FFail1 –Xa1

20/Ιn Ω (Vn=100/120V)

80/Ιn Ω(Vn=380/480V)

0/Ιn Ω(Vn=100/120V)

0/Ιn Ω(Vn=380/480V)

40/Ιn Ω(Vn=100/120V)

160/Ιn Ω(Vn=380/480V)

0.5/Ιn Ω(Vn=100/120V)

2/Ιn Ω(Vn=380/480V)

FFail1 Xb1

220/Ιn Ω(Vn=100/120V)

880/Ιn Ω(Vn=380/480V)

25/Ιn Ω(Vn=100/120V)

100/Ιn Ω(Vn=380/480V)

325/Ιn Ω(Vn=100/120V)

1300/Ιn Ω(Vn=380/480V)

1/Ιn Ω(Vn=100/120V)

4/Ιn Ω(Vn=380/480V)

FFail1 TimeDelay 5 s 0 s 100 s 0.1 s

FFail1 DO Timer 0 s 0 s 10 s 0.1 s

FFail2 Status Enabled Disabled, Enabled

FFail2 –Xa2

20/Ιn Ω (Vn=100/120V)

80/Ιn Ω(Vn=380/480V)

0/Ιn Ω(Vn=100/120V)

0/Ιn Ω(Vn=380/480V)

40/Ιn Ω(Vn=100/120V)

160/Ιn Ω(Vn=380/480V)

0.5/Ιn Ω(Vn=100/120V)

2/Ιn Ω(Vn=380/480V)

FFail2 Xb2

220/Ιn Ω(Vn=100/120V)

880/Ιn Ω(Vn=380/480V)

25/Ιn Ω(Vn=100/120V)

100/Ιn Ω(Vn=380/480V)

325/Ιn Ω(Vn=100/120V)

1300/Ιn Ω(Vn=380/480V)

1/Ιn Ω(Vn=100/120V)

4/Ιn Ω(Vn=380/480V)

FFail2 TimeDelay 5 s 0 s 100 s 0.1 s

FFail2 DO Timer 0 s 0 s 10 s 0.1 s

2.10.1 Setting guidelines for field failure protection

Each stage of field failure protection may be selected as ‘Enabled’ or ‘Disabled’,within the “FFail1 Status”, “FFail2 Status” cells. The power factor alarm element maybe selected as Enabled or Disabled within the “FFail Alm Status” cell.

2.10.1.1 Impedance element 1

To quickly detect a loss-of field condition, the diameter of the field failure impedancecharacteristic (“FFail1 Xb1”) should be set as large as possible, without conflictingwith the impedance that might be seen under normal stable conditions or duringstable power swing conditions.

Where a generator is operated with a rotor angle of less than 90° and never at aleading power factor, it is recommended that the diameter of the impedancecharacteristic, “FFail1 Xb1”, is set equal to the generator direct-axis synchronousreactance. The characteristic offset, “FFail1 -Xa1” should be set equal to half thedirect-axis transient reactance (0.5Xd’) in secondary ohms.

“FFail1 Xb1” = Xd

“FFail1 -Xa1” = 0.5 Xd’

where

Xd = Generator direct-axis synchronous reactance in ohms

Xd’ = Generator direct-axis transient reactance in ohms


Page 56/176 MiCOM P342, P343

Where high-speed voltage regulation equipment is used it may be possible to operategenerators at rotor angles up to 120°. In this case, the impedance characteristicdiameter, “FFail1 Xb1”, should be set to 50% of the direct-axis synchronous reactance(0.5Xd) and the offset, “FFail1 -Xa1”, should be set to 75% of the direct axis transientreactance (0.75Xd’).

“FFail1 Xb1” = 0.5 Xd

“FFail1 -Xa1” = 0.75 Xd’

The field failure protection time delay, “FFail1 Time Delay”, should be set to minimisethe risk of operation of the protection function during stable power swings followingsystem disturbances or synchronisation. However, it should be ensured that the timedelay is not so long that stator winding or rotor thermal damage will occur. A typicalstator winding should be able to withstand a current of 2.0 p.u. for the order of 15s.It may also take some time for the impedance seen at the generator terminals toenter the characteristic of the protection. A time delay less than 10s would typicallybe applied. The minimum permissible delay, to avoid problems of false tripping dueto stable power swings with the above impedance settings, would be of the order of0.5s.

The protection reset (delayed drop off) timer, “FFail1 DO Timer”, would typically beset to 0s to give instantaneous reset of the stage. A setting other than 0s can be usedto provide an integrating function for instances when the impedance may cyclicallyenter and exit the characteristic. This can allow detection of pole slipping conditions,for more information see section 2.21. When settings other than 0s are used theprotection pick-up time delay, “FFail1 Time Delay”, should be increased to preventmal-operation during stable power swing conditions.

2.10.1.2 Impedance element 2

The second impedance element can be set to give fast operation when the field failsunder high load conditions. The diameter of the characteristic, “FFail2 Xb2”, shouldbe set to 1 p.u. The characteristic offset, “FFail2 -Xa2”, should be set equal to halfthe direct-axis transient reactance (0.5Xd’).

FFail2 Xb2 = kV2

MVA

FFail2 -Xa2 = 0.5 Xd’

This setting will detect a field failure condition from full load to about 30% load.

The time delay, “FFail2 Time Delay”, can be set to instantaneous, i.e. 0s.

The protection reset (delayed drop off) timer, “FFail2 DO Timer”, would typically beset to 0s to give instantaneous reset of the stage. A setting other than 0s can be usedto provide an integrating function for instances when the impedance may cyclicallyenter and exit the characteristic. This can allow detection of pole slipping conditions,for more information see section 2.21. When settings other than 0s are used theprotection pick-up time delay, “FFail2 Time Delay”, should be increased to preventmaloperation during stable power swing conditions.

2.10.1.3 Power factor element

Salient pole machines can run continuously as induction generators generatingsignificant power and operation under these conditions may not be detectable by animpedance characteristic. The power factor alarm can be used to signal to theoperator that excitation has failed under these conditions.


MiCOM P342, P343 Page 57/176

The angle setting, “FFail Alm Angle”, should be set to greater than any angle that themachine could be operated at in normal running. A typical setting would be 15°,equivalent to a power factor of 0.96 leading. The power factor element time delay,“FFail Alm Delay”, should be set longer than the impedance element time delaysetting (“FFail1 Time Delay”). This is to prevent operation of the alarm element undertransient conditions such as power swinging and to provide discrimination where afield failure condition may not be detected by conventional field failure impedanceelements.

2.11 Negative phase sequence thermal protection

The Negative Phase Sequence (NPS) protection provided by the P340 is a truethermal replica with a definite-time alarm stage. The relay derives the negativephase sequence operating quantity from the following equation:

Ι2 = Ιa + a2 Ιb + aΙc

3 where a = 1.0 ∠120°

Unbalanced loading results in the flow of positive and negative sequence currentcomponents. Load unbalance can arise as a result of single phase loading, non-linear loads (involving power electronics or arc furnaces, etc.), uncleared or repetitiveasymmetric faults, fuse operation, single-pole tripping and reclosing on transmissionsystems, broken overhead line conductors and asymmetric failures of switchingdevices. Any negative phase sequence component of stator current will set up areverse-rotating component of stator flux that passes the rotor at twice synchronousspeed. Such a flux component will induce double frequency eddy currents in therotor, which can cause overheating of the rotor body, main rotor windings, damperwindings etc.

Where a machine has a high continuous negative phase sequence current withstandlevel (Ι2 amp), as in the case of typical salient-pole machines, it would not beessential to enable the NPS protection function. The NPS protection function can,however, offer a better method of responding to an uncleared asymmetric faultremote from the generator bus. As mentioned in section 2.5.1.2, it may be difficult toset the voltage dependant overcurrent protection function to detect a remote fault andco-ordinate with feeder backup protection for a close-up 3-phase fault.

For high levels of negative phase sequence current, eddy current heating can beconsiderably in excess of the heat dissipation rate. Thus, virtually all the heatacquired during the period of unbalance will be retained within the rotor. With thisassumption, the temperature attained within any critical rotor component will bedependent on the duration of the unbalance (t seconds) and the level of NPS current(I2 per unit) and is proportional to I22t. Synchronous generators are assigned a per-unit I22t thermal capacity constant (Kg) to define their short time NPS current withstandability, see column 3 in Table 1. Various rotor components have different short timethermal capacities and the most critical (lowest value of I22t) should form the basis ofthe generator manufacturer’s short time I22t withstand claim.

Many traditional forms of generator NPS thermal protection relays have beendesigned with an extremely inverse (Ι22t) operating time characteristic. Where theoperating time of the characteristic is dependent solely on the instantaneousmagnitude of negative phase sequence current present. This characteristic would beset to match the claimed generator thermal capacity. This is satisfactory whenconsidering the effects of high values of negative phase sequence current.

For intermediate levels of NPS current, the rate of heating is slower. As a result, heatdissipation should be considered.


Page 58/176 MiCOM P342, P343

The basic expression of t = K/Ι2cmr does not cater for the effects of heat dissipation orfor low standing levels of negative phase sequence current. The latter resulting in anincrease in rotor temperature which remains within the machines design limits. Anexisting, tolerable, level of negative phase sequence current (Ι2<Ι2cmr), has the effectof reducing the time to reach the critical temperature level, if the negative phasesequence current level should increase beyond Ι2cmr. The P340 NPS thermal replica isdesigned to overcome these problems by modelling the effects of low standing levelsof negative phase sequence currents.

The temperature rise in critical rotor components is related to the negative phasesequence current (I2 per unit) and to time (t seconds) as follows. This assumes nopreceding negative phase sequence current:

θ°C ∝ I22 (1 - e-t/τ)

where

τ = the thermal time constant, τ = Kg/I2CMR2

Kg is the generator’s per-unit thermal capacity constant in seconds.

I2CMR is the generator’s per-unit continuous maximum I2 rating.

The limiting continuous maximum temperature (θCMR) would be reached according tothe following current-time relationship:

θ°C = θCMR I22 (1 - e-t/τ) = I2CMR2

From the above, the time for which a level of negative phase sequence current inexcess of I2CMR can be maintained is expressed as follows:

t = - (Kg/I2CMR2) loge (1- (I2CMR/I2))

The P340 negative phase sequence element offers a true thermal characteristicaccording to the following formula:

t = - (Ι2>2 k Setting)

( Ι2>2 Current set )2 Loge

1 -

(Ι2>2 Current set)

Ι2

2

Note: All current terms are in per-unit, based on the relay ratedcurrent, Ιn.

When the protected generator sees a reduction in negative phase sequence current,metallic rotor components will decrease in temperature. The relay is provided with aseparate thermal capacity setting (Ι2>2 KRESET), used when there is a reduction inΙ2.

The negative sequence protection element will respond to system phase to earth andphase to phase faults. Therefore, the element must be set to grade with downstreamearth and phase fault protections. To aid grading with downstream devices a definiteminimum operating time for the operating characteristic can be set. The definiteminimum time setting should be set to provide an adequate margin between theoperation of the negative phase sequence thermal protection function and externalprotection. The co-ordination time margin used should be in accordance with theusual practice adopted by the customer for backup protection co-ordination.

For levels of negative phase sequence current that are only slightly in excess of thethermal element pick-up setting, there will be a noticeable deviation between theP340 negative phase sequence thermal protection current-time characteristic and thatof the simple Ι22t characteristic. For this reason, a maximum negative phase


MiCOM P342, P343 Page 59/176

sequence protection trip time setting is provided. This maximum time setting alsolimits the tripping time of the negative phase sequence protection for levels ofunbalance where there may be uncertainty about the machine’s thermal withstand.

A time delayed negative sequence overcurrent alarm stage is provided to give theoperator early warning of an unbalanced condition that may lead to generatortripping. This can allow corrective action to be taken to reduce the unbalance in theload.

The Negative Sequence element uses the current measured at the ΙA, ΙB, ΙC inputs onthe relay.

Thermal state of the machine can be viewed in the “NPS Thermal” cell in the“MEASUREMENTS 3” column. The thermal state can be reset by selecting ‘Yes’ in the“Reset NPS Thermal” cell in “Measurements 3”. Alternatively the thermal state can bereset by energising DDB 389 “Reset Ι2 Thermal” via the relay PSL.

A DDB signal is also available to indicate tripping of the element (DDB 424). Afurther DDB ‘NPS Alarm’ signal is generated from the NPS thermal alarm stage (DDB306). The state of the DDB signal can be programmed to be viewed in the“Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.

!"

#$%

#&

Figure 18: Negative phase sequence thermal characteristic


Page 60/176 MiCOM P342, P343

Setting ranges for the negative phase sequence thermal element are shown in thefollowing table:


Min MaxStep Size

GROUP 1:NPS THERMAL

Ι2>1 Alarm Enabled Disabled, Enabled

Ι2>1 Current Set 0.05 Ιn A 0.03 Ιn A 0.5 Ιn A 0.01 Ιn A

Ι2>1 Time Delay 20 s 2 s 60 s 0.1 s

Ι2>2 Trip Enabled Disabled, Enabled

Ι2>2 Current set 0.1 Ιn A 0.05 Ιn A 0.5 Ιn A 0.01 Ιn A

Ι2>2 k Setting 15 2 40 0.1

Ι2>2 kRESET 15 2 40 0.1

Ι2>2 tMAX 1000 s 500 s 2000 s 10 s

Ι2>2 tMIN 0.25 s 0.25 s 40 s 0.25 s

2.11.1 Setting guidelines for negative phase sequence thermal protection

The alarm and trip stages of the negative phase sequence thermal protection may beselected as ‘Enabled’ or ‘Disabled’, within the “Ι2>1 Alarm” and “Ι2>2 Trip” cellsrespectively.

Synchronous machines will be able to withstand a certain level of negative phasesequence stator current continuously. All synchronous machines will be assigned acontinuous maximum negative phase sequence current (Ι2cmr per-unit) rating by themanufacturer. For various categories of generator, minimum negative phase

sequence current withstand levels have been specified by international standards,such as IEC60034-1 and ANSI C50.13-1977 [1]. The IEC60034-1 figures are givenin Table 1.

Generator typeMaximum Ι2/Ιn for

continuous operation

Maximum (Ι2/Ιn)2t foroperation under fault

conditions, Kg

Salient-pole:

Indirectly cooled 0.08 20

Directly cooled(inner cooled) statorand/or field

0.05 15

Cylindrical rotor synchronous:

Indirectly cooled rotor

Air cooled 0.1 15

Hydrogen cooled 0.1 10

Directly cooled(inner cooled) rotor


MiCOM P342, P343 Page 61/176

Generator typeMaximum Ι2/Ιn for

continuous operation

Maximum (Ι2/Ιn)2t foroperation under fault

conditions, Kg

350 >900 >1250

≤ 350MVA≤ 900MVA≤ 1250MVA≤ 1600MVA

0.08**

0.05

8**55

* For these generators, the value of Ι2/Ιn is calculated as follows:

Ι2

Ιn = 0.8 -

Sn - 350

3 x 104

** For these generators, the value of (Ι2/Ιn)2t is calculated as follows:

Ι2

Ιn

2

t = 8 - 0.00545 (Sn - 350)

where Sn is the rated power in MVA

Table 1: IEC60034-1 Minimum negative sequence current withstand levels.

To obtain correct thermal protection, the relay thermal current setting, “Ι2>2 CurrentSet”, and thermal capacity setting, “Ι2>2 k Setting”, should be set as follows:

Ι2 > 2 Current set = Ι2cmr x

Ιflc

Ιp x Ιn

Ι2 > 2 k Setting = Kg x

Ιflc

Ιp

2

where

Ι2cmr = Generator per unit Ι2 maximum withstand.

Kg = Generator thermal capacity constant(s), see Table 1 for guidance.

Ιflc = Generator primary full-load current (A).

Ιp = CT primary current rating (A).

Ιn = Relay rated current (A).

Unless otherwise specified, the thermal capacity constant setting used when I2 isreducing, “Ι2>2 kRESET”, should be set equal to the main time constant setting,“Ι2>2 k Setting”. A machine manufacturer may be able to advise a specific thermalcapacity constant when I2 is reducing for the protected generator.

The current threshold of the alarm stage, “Ι2>1 Current Set”, should be set below thethermal trip setting, “Ι2>2 Current Set”, to ensure that the alarm operates beforetripping occurs. A typical alarm current setting would be 70% of the trip currentsetting. The alarm stage time setting, “Ι2>1 Time Delay”, must be chosen to preventoperation during system fault clearance and to ensure that unwanted alarms are notgenerated during normal running. A typical setting for this time delay would be 20s.


Page 62/176 MiCOM P342, P343

To aid grading with downstream devices a definite minimum operating time for theoperating characteristic can be set, “Ι2>2 tMIN”. This definite minimum time settingshould be set to provide an adequate margin between the operation of the negativephase sequence thermal protection function and external protection. The co-ordination time margin used should be in accordance with the usual practice adoptedby the customer for back-up protection co-ordination.

A maximum operating time for the negative phase sequence thermal characteristicmay be set, “Ι2>2 tMAX”. This definite time setting can be used to ensure that thethermal rating of the machine is never exceeded.

2.12 Reverse power/over power/low forward power

The standard power protection elements of the P340 relay calculate the three phaseactive power based on the following formula, using the current measured at the Ιa,Ιb, Ιc inputs on the relay.

P = Vala cosφa + Vblb cosφb + Vclc cosφc

Two stages of power protection are provided, these can be independently selected aseither reverse power, over power, low forward power or disabled, operation in eachmode is described in the following sections. The power elements may be selectivelydisabled, via fixed logic, so that they can be inhibited when the protected machinesCB is open, this will prevent mal-operation and nuisance flagging of any stageselected to operate as low forward power.

The P340 relay is connected with the convention that the forward current is thecurrent flowing from the generator to the busbar. This corresponds to positive valuesof the active power flowing in the forward direction. When a generator is operatingin the motoring mode, the machine is consuming active power from the powersystem. The motoring active power therefore flows in the reverse direction. The“Operating Mode” setting for the power protection allows the user to set theoperating mode to either “Generating” or “Motoring”. If the mode is set to“Motoring”, the polarity of the calculated active power is inverted. The operatingmode setting can be useful in applications involving pumped storage generators.

DDB signals are available to indicate starting and tripping of each stage (Starts: DDB595, DDB 596, Trips: DDB 475, 476). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSION TESTS”column in the relay.

Setting ranges for the Power elements are shown in the following table:


Min MaxStep Size

Group 1: Power

Operating Mode Generating Generating, Motoring

Power1 Function Reverse Disabled, Reverse, Low Forward, Over

–P>1 Setting

5 x Ιn W(Vn=100/120V)

20 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

300 x Ιn W(Vn=100/120V)

1200 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

P<1 Setting

5 x Ιn W(Vn=100/120V)

20 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

300 x Ιn W(Vn=100/120V)

1200 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)


MiCOM P342, P343 Page 63/176


Min MaxStep Size

Group 1: Power

P>1 Setting

5 x Ιn W(Vn=100/120V)

20 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

300 x Ιn W(Vn=100/120V)

1200 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

Power1 Time Delay 5 s 0 s 100 s 0.1 s

Power1 DO Timer 0 s 0 s 10 s 0.1 s

P1 Poledead Inh Enabled Enabled, Disabled

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

–P>2 Setting

5 x Ιn W(Vn=100/120V)

20 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

300 x Ιn W(Vn=100/120V)

1200 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

P<2 Setting

5 x Ιn W(Vn=100/120V)

20 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

300 x Ιn W(Vn=100/120V)

1200 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

P>2 Setting

5 x Ιn W(Vn=100/120V)

20 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

300 x Ιn W(Vn=100/120V)

1200 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

Power2 Time Delay 5 s 0 s 100 s 0.1 s



2.12.1 Sensitive power protection function

The minimum standard 3 phase power protection setting (2%Pn for P342/P343) canbe restrictive for some applications. For example for steam turbine generators andsome hydro generators a reverse power setting as low as 0.5%Pn is required. Asensitive setting for low forward power protection may also be required, especially forsteam turbine generators which have relatively low over speed design limits.

If a power setting less than 2% Pn is required then the sensitive power protectionshould be used.

To improve the power protection sensitivity, a sensitive CT input is used. The CT inputis the same as that of the sensitive earth fault and restricted earth fault protectionelements, so the user can only select either sensitive power or SEF/REF in the“Configuration” menu, but not both.

The sensitive power protection measures only A-phase active power, as the abnormalpower condition is a 3-phase phenomenon. Having a separate CT input also meansthat a correctly loaded metering class CT can be used which can provide the requiredangular accuracy for the sensitive power protection function. A compensation anglesetting θC is also be provided to compensate for the angle error introduced by thesystem CT and VT.

The A-phase power is calculated based on the following formula:

PA = ΙA VA cos (φ - θC)


Page 64/176 MiCOM P342, P343

Where φ is the angle of ΙA with respect to VA and θC is the compensation anglesetting.

Therefore, rated single phase power, Pn, for a 1A rated CT and 110V rated VT is

Pn = Ιn x Vn = 1 x 110/√3 = 63.5 W

The minimum setting is 0.3 W = 0.47% Pn

Two stages of sensitive power protection are provided, these can be independentlyselected as either reverse power, over power, low forward power or disabled,operation in each mode is described in the following sections. The power elementsmay be selectively disabled, via fixed logic, so that they can be inhibited when theprotected machine’s CB is open, this will prevent maloperation and nuisance flaggingof any stage selected to operate as low forward power.

The P340 relay is connected with the convention that the forward current is thecurrent flowing from the generator to the busbar. This corresponds to positive valuesof the active power flowing in the forward direction. When a generator is operatingin the motoring mode, the machine is consuming active power from the powersystem. The motoring active power therefore flows in the reverse direction. The“Operating Mode” setting for the sensitive power protection allows the user to set theoperating mode to either “Generating” or “Motoring”. If the mode is set to“Motoring”, the polarity of the calculated active power is inverted. The operatingmode setting can be useful in applications involving pumped storage generators.

Measurement displays of A Phase sensitive active power, reactive power and powerfactor angle “APh Sen Watts, Aph Sen Vars and APh Power Angle” are provided inthe “MEASUREMENTS 3” menu to aid testing and commissioning.

DDB signals are available to indicate starting and tripping of each stage (Starts: DDB643, DDB 644, Trips: DDB 495, 496). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSION TESTS”column in the relay.

Setting ranges for the Sensitive Power elements are shown in the following table:


Min MaxStep Size

Group 1: Sensitive Power

Comp Angle 0° -5° 5° 0.1°

Operating Mode Generating Generating, Motoring

Sen Power1 Func Reverse Disabled, Reverse, Low Forward, Over

Sen –P>1 Setting

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

0.3 x Ιn W(Vn=100/120V)

1.2 x Ιn W(Vn=380/480V)

100 x Ιn W(Vn=100/120V)

400 x Ιn W(Vn=380/480V)

0.1 x Ιn W(Vn=100/120V)

0.4 x Ιn W(Vn=380/480V)

Sen P<1 Setting

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

0.3 x Ιn W(Vn=100/120V)

1.2 x Ιn W(Vn=380/480V)

100 x Ιn W(Vn=100/120V)

400 x Ιn W(Vn=380/480V)

0.1 x Ιn W(Vn=100/120V)

0.4 x Ιn W(Vn=380/480V)

Sen P>1 Setting

50 x Ιn W(Vn=100/120V)

200 x Ιn W(Vn=380/480V)

0.3 x Ιn W(Vn=100/120V)

1.2 x Ιn W(Vn=380/480V)

100 x Ιn W(Vn=100/120V)

400 x Ιn W(Vn=380/480V)

0.1 x Ιn W(Vn=100/120V)

0.4 x Ιn W(Vn=380/480V)

Sen Power1 Delay 5 s 0 s 100 s 0.1 s


MiCOM P342, P343 Page 65/176


Min MaxStep Size

Group 1: Sensitive Power



Sen Power2 Func Low Forward Disabled, Reverse, Low Forward, Over

Sen –P>2 Setting

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

0.3 x Ιn W(Vn=100/120V)

1.2 x Ιn W(Vn=380/480V)

100 x Ιn W(Vn=100/120V)

400 x Ιn W(Vn=380/480V)

0.1 x Ιn W(Vn=100/120V)

0.4 x Ιn W(Vn=380/480V)

Sen P<2 Setting

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

0.3 x Ιn W(Vn=100/120V)

1.2 x Ιn W(Vn=380/480V)

100 x Ιn W(Vn=100/120V)

400 x Ιn W(Vn=380/480V)

0.1 x Ιn W(Vn=100/120V)

0.4 x Ιn W(Vn=380/480V)

Sen P>2 Setting

50 x Ιn W(Vn=100/120V)

200 x Ιn W(Vn=380/480V)

0.3 x Ιn W(Vn=100/120V)

1.2 x Ιn W(Vn=380/480V)

100 x Ιn W(Vn=100/120V)

400 x Ιn W(Vn=380/480V)

0.1 x Ιn W(Vn=100/120V)

0.4 x Ιn W(Vn=380/480V)

Sen Power2 Delay 2 s 0 s 100 s 0.1 s



2.12.2 Low forward power protection function

When the machine is generating and the CB connecting the generator to the systemis tripped, the electrical load on the generator is cut. This could lead to generatorover-speed if the mechanical input power is not reduced quickly. Large turbo-alternators, with low-inertia rotor designs, do not have a high over speed tolerance.Trapped steam in the turbine, downstream of a valve that has just closed, can rapidlylead to over speed. To reduce the risk of over speed damage to such sets, it issometimes chosen to interlock non-urgent tripping of the generator breaker and theexcitation system with a low forward power check. This ensures that the generator setcircuit breaker is opened only when the output power is sufficiently low that overspeeding is unlikely. The delay in electrical tripping, until prime mover input powerhas been removed, may be deemed acceptable for ‘non-urgent’ protection trips; e.g.stator earth fault protection for a high impedance earthed generator. For ‘urgent’trips, e.g. stator current differential protection the low forward power interlock shouldnot be used. With the low probability of ‘urgent’ trips, the risk of over speed andpossible consequences must be accepted.

The low forward power protection can be arranged to interlock ‘non-urgent’protection tripping using the relay scheme logic. It can also be arranged to provide acontact for external interlocking of manual tripping, if desired.

To prevent unwanted relay alarms and flags, a low forward power protection elementcan be disabled when the circuit breaker is opened via ‘poledead’ logic.

The low forward power protection can also be used to provide loss of load protectionwhen a machine is motoring. It can be used for example to protect a machine whichis pumping from becoming unprimed or to stop a motor in the event of a failure inthe mechanical transmission. A typical application would be for pump storagegenerators operating in the motoring mode, where there is a need to prevent themachine becoming unprimed which can cause blade and runner cavitation. Duringmotoring conditions, it is typical for the relay to switch to another setting group with


Page 66/176 MiCOM P342, P343

the low forward power enabled and correctly set and the protection operating modeset to Motoring.

2.12.2.1 Low forward power setting guideline

Each stage of power protection can be selected to operate as a low forward powerstage by selecting the “Power1 Function/Sen Power1 Func” or “Power2 Function/SenPower 2 Func” cell to ‘Low Forward’.

When required for interlocking of non urgent tripping applications, the thresholdsetting of the low forward power protection function, “P<1 Setting/Sen P<1 Setting”or “P<2 Setting/Sen P<2 Setting”, should be less than 50% of the power level thatcould result in a dangerous over speed transient on loss of electrical loading. Thegenerator set manufacturer should be consulted for a rating for the protectedmachine. The operating mode should be set to “Generating” for this application.

When required for loss of load applications, the threshold setting of the low forwardpower protection function, “P<1 Setting/Sen P<1 Setting” or “P<2 Setting/Sen P<2Setting”, is system dependent, however, it is typically set to 10-20% below theminimum load. For example, for a minimum load of 70%Pn, the setting needs to beset at 63%-56%Pn. The operating mode should be set to “Motoring” for thisapplication.

For interlocking non urgent trip applications the time delay associated with the lowforward power protection function, “Power1 TimeDelay/Sen Power1 Delay” or“Power2 TimeDelay/Sen Power2 Delay”, could be set to zero. However, some delayis desirable so that permission for a non-urgent electrical trip is not given in the eventof power fluctuations arising from sudden steam valve/throttle closure. A typical timedelay for this reason is 2s.

For loss of load applications the pick up time delay, “Power1 TimeDelay/Sen Power1Delay” or “Power2 TimeDelay/Sen Power2 Delay”, is application dependent but isnormally set in excess of the time between motor starting and the load beingestablished. Where rated power can not be reached during starting (for examplewhere the motor is started with no load connected) and the required protectionoperating time is less than the time for load to be established then it will be necessaryto inhibit the power protection during this period. This can be done in the PSL usingAND logic and a pulse timer triggered from the motor starting to block the powerprotection for the required time.

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 protection elementcan be disabled when the circuit breaker is open via ‘poledead’ logic. This iscontrolled by setting the power protection inhibit cells, “P1 Poledead Inh” or “P2Poledead Inh”, to ‘Enabled’.

2.12.3 Reverse power protection function

A generator is expected to supply power to the connected system in normaloperation. If the generator prime mover fails, a generator that is connected inparallel with another source of electrical supply will begin to ‘motor’. This reversal ofpower flow due to loss of prime mover can be detected 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 types ofgenerating plant are given in the following table.


MiCOM P342, P343 Page 67/176

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%(Split-shaft)

>50%(Single-shaft)

With some gear-driven sets,damage may arise due to reversetorque on gear teeth.

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

Hydraulic Turbines

0.2 – >2%(Blades out of water)

>2.0%(Blades in water)

Blade and runner cavitation mayoccur with a long period ofmotoring

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

Steam Turbines

0.5% – 3%(Condensing sets)

3% - 6%(Non-condensing sets)

Thermal stress damage may beinflicted on low-pressure turbineblades when steam flow is notavailable to dissipate windagelosses.

Damage may occur rapidly with non-condensing sets or when vacuum is lost withcondensing sets. Reverse power protection may be used as a secondary methodof detection and might only be used to raise an alarm.

Table showing motor 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 (“Power1 DO Timer/Power2 DO Timer”). Thisdelay would need to be set longer than the period for which the reverse power couldfall below the power setting (“P<1 Setting/Sen P<1 Setting”). This setting needs to betaken into account when setting the main trip time delay. It should also be noted thata delay on reset in excess of half the period of any system power swings could resultin operation of the reverse power protection during swings.

Reverse power protection may also be used to interlock the opening of the generatorset circuit breaker for ‘non-urgent’ tripping, as discussed in 2.12.1. Reverse powerinterlocks are preferred over low forward power interlocks by some utilities.

2.12.3.1 Reverse power setting guideline

Each stage of power protection can be selected to operate as a reverse power stageby selecting the “Power1 Function/Sen Power1 Func” or “Power2 Function/SenPower2 Func” cell to ‘Reverse’.


Page 68/176 MiCOM P342, P343

The power threshold setting of the reverse power protection, “-P>1 Setting/Sen -P>1Setting” or “-P>2 Setting/Sen -P>2 Setting”, should be less than 50% of the motoringpower, typical values for the level of reverse power for generators are given inprevious table.

For applications to detect the loss of the prime mover or for applications to provideinterlocking of non urgent trips the reverse power protection operating mode shouldbe set to “Generating”.

The reverse power protection function should be time-delayed to prevent false trips oralarms being given during power system disturbances or following synchronisation.A time delay setting, “Power1 TimeDelay/Sen Power1 Delay” or “Power2TimeDelay/Sen Power2 Delay” 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.

2.12.4 Over power protection

The overpower protection can be used as overload indication, as a back-upprotection for failure of governor and control equipment, and would be set above themaximum power rating of the machine.

2.12.4.1 Over power setting guideline

Each stage of power protection can be selected to operate as an over power stage byselecting the “Power1 Function/Sen Power1 Func” or “Power2 Function/Sen Power2Func” cell to ‘Over’.

The power threshold setting of the over power protection, “P>1 Setting/Sen P>1Setting” or “P>2 Setting/Sen P>2 Setting”, should be set greater than the machinefull load rated power.

A time delay setting, “Power1 TimeDelay/Sen Power1 Delay” or “Power2TimeDelay/Sens Power2 Delay” should be applied.

The operating mode should be set to “Motoring” or “Generating” depending on theoperating mode of the machine.

The delay on reset timer, “Power1 DO Timer” or “Power2 DO Timer”, wouldnormally be set to zero.

2.13 Stator earth fault protection function

Low voltage generators will be solidly earthed, however to limit the damage that canbe caused due to earth faults, it is common for HV generators to be connected toearth via an impedance. This impedance may be fitted on the secondary side of adistribution transformer earthing arrangement. The earthing impedance is generallychosen to limit earth fault current to full load current or less.

There is a limit on the percentage of winding that can be protected by a stator earthfault element. For earth faults close to the generator neutral, the driving voltage willbe low, and hence the value of fault current will be severely reduced. In practice,approximately 95% of the stator winding can be protected. For faults in the last 5%of the winding, the earth fault current is so low that it cannot be detected by this typeof earth fault protection. In most applications this limitation is accepted as thechances of an earth fault occurring in the last 5% of the winding, where the voltage toearth is low, is small.


MiCOM P342, P343 Page 69/176

The percentage of winding covered by the earth fault protection can be calculated asshown below, with reference to Figure 19.

#

/

#/D

D/

E>03

#$

#$1#<<E

Figure 19: Effective coverage of stator earth fault protection

A two stage non-directional earth fault element is provided. The first stage has aninverse time or definite time delay characteristic and can incorporate a reset timedelay to improve detection of intermittent faults. The second stage has a definite timecharacteristic which can be set to 0s to provide instantaneous operation.

Where impedance or distribution transformer earthing is used the second stage ofprotection may be used to detect flashover of the earthing impedance. The secondstage may also be used to provide instantaneous protection where grading withsystem protection is not required. See setting guidelines for more details.

Each stage of protection can be blocked by energising the relevant DDB signal via thePSL (DDB 358, DDB 359). This allows the earth fault protection to be integrated intobusbar protection schemes as shown in section 2.24, or can be used to improvegrading with downstream devices. DDB signals are also available to indicate thestart and trip of each stage of protection, (Starts: DDB 613, DDB 614, Trips: DDB442, DDB 443). 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.

The Stator Earth Fault element is powered from the IN CT input on the relay. Thisinput should be supplied from a CT fitted into the generator earth path so that theelement provides earth fault protection for the generator and back-up protection forsystem faults. Alternatively, the element may be supplied from a CT fitted on thesecondary side of a distribution transformer earthing system.


Page 70/176 MiCOM P342, P343

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


Min MaxStep Size

GROUP 1EARTH FAULT

ΙN>1 Function Disabled

Disabled, DT, IEC S Inverse, IEC VInverse, IEC E Inverse, UK LT Inverse, RI,

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

US ST Inverse, IDG

ΙN>1 Current 0.1 x Ιn A 0.02 x Ιn A 4 x Ιn A 0.01 x Ιn A

ΙN1>1 IDG Ιs 1.5 1 4 0.1

ΙN>1 Time Delay 1 s 0 s 200 s 0.01 s

ΙN>1 TMS 1 0.025 1.2 0.025

ΙN>1 Time Dial 1 0.01 100 0.01

ΙN>1 K(RI) 1 0.1 10 0.05

ΙN>1 IDG Time 1.2 1 2 0.01

ΙN>1 Reset Char DT DT, Inverse N/A

ΙN>1 tRESET 0 s 0 s 100 s 0.01 s

ΙN>2 Function DT Disabled, DT N/A

ΙN>2 Current Set 0.45 x Ιn A 0.02 x Ιn A 10 x Ιn A 0.01 x Ιn A

ΙN>2 Time Delay 0 s 0 s 200 s 0.01 s

For further details regarding the inverse time characteristics refer to the OvercurrentProtection, section 2.4.

2.13.1 IDG curve

The IDG curve is commonly used for time delayed earth fault protection in theSwedish market. This curve is available in stages 1 and 2 of Earth Fault protection.

The IDG curve is represented by the following equation:

t = 5.8 - 1.35 loge

Ι

ΙN > Setting in seconds

where


ΙN>Setting = an adjustable setting which defines the start point of the characteristic

Although the start point of the characteristic is defined by the “ΙN>” setting, theactual relay current threshold is a different setting called “IDG Ιs”. The “IDG Ιs”setting is set as a multiple of “ΙN>”.

An additional setting “IDG Time” is also used to set the minimum operating time athigh levels of fault current.

Figure 20 illustrates how the IDG characteristic is implemented.


MiCOM P342, P343 Page 71/176

0

1

2

3

4

5

6

7

8

9

10

1 10 100

I/IN>

Ope

ratin

g tim

e (s

econ

ds)

IDG Is Setting Range

IDG Time Setting Range

P2242ENa

Figure 20: IDG characteristic

2.13.2 Setting guidelines for stator earth fault potection

The first stage of earth fault protection can be selected by setting “ΙN>1 Function” toany of the inverse or DT settings. The first stage is disabled if “ΙN>1 Function” is setto ‘Disabled’. The second stage of earth fault protection can be selected by setting“ΙN>2 Function” to ‘Enabled’. The second stage is disabled if “ΙN>2 Function” is setto ‘Disabled’.

For a directly connected machine the stator earth fault protection must co-ordinatewith any downstream earth fault protections. The first stage current setting, “ΙN>1Current”, should typically be set to less than 33% of the machine earth faultcontribution or full load current, whichever is lower. The time delay characteristic ofthe element (selected via “ΙN>1 Function” and “ΙN>1 Time Delay”, “ΙN>1 TMS” or“ΙN>1 Time Dial”) should be set to time grade with any downstream earth faultprotection. Where the element is required to protect 95% of the generator winding acurrent setting of 5% of the limited earth fault current should be used.

Where impedance or distribution transformer earthing is used the second stage maybe used to detect flashover of the earthing impedance. In such a case the secondstage current setting, “ΙN>2 Current”, could be set to approximately 150% of thelimited earth fault current and the time delay, “ΙN>2 Time Delay”, would be set to 0s,to provide instantaneous operation.

For a machine connected to the system via a step-up transformer there is no need tograde the stator earth fault element with system earth fault protections. In this casethe first stage should be set to 5% of the limited earth fault current to provideprotection for 95% of the machine winding. The time delay characteristic of the stageshould grade with VT fuses for VT earth faults. A transient generator earth faultcurrent may also occur for a HV earth fault due to transformer inter-windingcapacitance. Correct grading under these conditions can be provided by using adefinite time delay of between 0.5-3s. Experience has shown that it is possible toapply an instantaneous stator earth fault element on a indirectly connected machine ifa current setting of ≥10% of the limited earth fault current is used. Therefore thesecond stage can be set to give this instantaneous protection.


Page 72/176 MiCOM P342, P343

2.14 Residual overvoltage/neutral voltage displacement protection function

On 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 balanced vectorsat 120° to one another. However, when an earth fault occurs on the primary systemthis 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 residualvoltage measuring relay can be used to offer earth fault protection on such a system.Note that this condition causes a rise in the neutral voltage with respect to earthwhich 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 a singlephase VT. This type of protection can be used to provide earth fault protectionirrespective of whether the generator is earthed or not, and irrespective of the form ofearthing and earth fault current level. For faults close to the generator neutral theresulting residual voltage will be small. Therefore, as with stator earth faultprotection, only 95% of the stator winding can be reliably protected.

It should be noted that where residual overvoltage protection is applied to a directlyconnected generator, such a voltage will be generated for an earth fault occurringanywhere on that section of the system and hence the NVD protection must co-ordinate with other earth fault protections.

The neutral voltage displacement protection function of the P340 relay consists of twostages with adjustable time delays.

Two stages are included for the element to account for applications which requireboth alarm and trip stages, for example, an insulated system. It is common in such acase for the system to have been designed to withstand the associated healthy phaseovervoltages for a number of hours following an earth fault. In such applications, analarm is generated soon after the condition is detected, which serves to indicate thepresence of an earth fault on the system. This gives time for system operators tolocate and isolate the fault. The second stage of the protection can issue a trip signalif the fault condition persists.

A dedicated voltage input is provided for this protection function, this may be used tomeasure the residual voltage supplied from either an open delta connected VT or thevoltage measured on the secondary side of a distribution transformer earthconnection, as shown in Figure 21. Alternatively, the residual voltage may be derivedinternally from the three phase to neutral voltage measurements. Where derivedmeasurement is used the 3 phase to neutral voltage must be supplied from either a5-limb or three single phase VTs. 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 whenresidual voltage is required to be derived from the phase to neutral voltagemeasurement.

The residual voltage signal also provides a polarising voltage signal for the sensitivedirectional earth fault protection function.


MiCOM P342, P343 Page 73/176

!

> $&%>'

% $&$

% $)?/*

!"!

/

/)

/

/

!

Figure 21: Alternative relay connections for residual overvoltage/NVD protection

Each stage of protection can be blocked by energising the relevant DDB signal via thePSL (DDB 368, DDB 369), this can be used to improve grading with downstreamdevices. DDB signals are also available to indicate the start and trip of each stage ofprotection, (Starts: DDB 577, DDB 578, Trips: DDB 451, DDB 452). 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 and default settings for this element are shown in the following table:


Min MaxStep Size

GROUP 1RESIDUAL O/V NVD

VN Input Measured Measured, Derived

VN>1 Function DT Disabled, DT, IDMT

VN>1 Voltage Set5V (Vn=100/120V)

20V (Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

80V(Vn=100/120V)

320V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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


Page 74/176 MiCOM P342, P343


Min MaxStep Size

GROUP 1RESIDUAL O/V NVD

VN>2 Voltage Set5V (Vn=100/120V)

20V (Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

80V(Vn=100/120V)

320V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

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


t = K / (M – 1)

where

K = Time Multiplier Setting (“VN>1 TMS”)


M = Measured Residual Voltage/Relay Setting Voltage (“VN>1 Voltage Set”)

2.14.1 Setting guidelines for residual overvoltage/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>1 Function” 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 IDMT curve;“V>1 Time Delay”, “V>2 Time Delay”- for definite time) should be selected inaccordance with normal relay co-ordination procedures to ensure correctdiscrimination for system faults.

The residual overvoltage protection can be set to operate from the voltage measuredat the Vn input VT terminals or the residual voltage derived from the phase-neutralvoltage inputs as selected by “VN Input”.

For a directly connected machine the neutral voltage displacement protection mustco-ordinate with any downstream earth fault protections. To ensure co-ordination thevoltage setting of the neutral voltage displacement protection function should be sethigher than the effective setting of current operated earth fault protection in the sameearth fault zone. The effective voltage setting of a current operated earth faultprotection may be established from the following equations:

Veff = (Ιpoc x Ze) / (1/3 x V1/V2) for an open delta VT

Veff = (Ιpoc x Ze) / (V1/V2) for a single phase star point VT

where

Veff = effective voltage setting of current operated protection

Ιpoc = primary operating current of current operated protection

Ze = earthing impedance

V1/V2 = VT turns ratio


MiCOM P342, P343 Page 75/176

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 overvoltage protection is 5V.

The second stage of protection can be used as an alarm stage on unearthed or veryhigh impedance earthed systems where the system can be operated for anappreciable time under an earth fault condition.

Where the generator is connected to the system via a transformer, co-ordination withsystem earth fault protections is not required. In these applications the NVD voltagesetting should typically be set to 5% of rated voltage. This will provide protection for95% of the stator winding.

2.15 Sensitive earth fault protection function

If a generator is earthed through a 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 suitablysensitive setting range in order to be effective. A separate sensitive earth faultelement is provided within the P340 relay for this purpose, this has a dedicated CTinput allowing very low current setting thresholds to be used.

An alternative use for the sensitive earth fault input is on a multiple earthed systemwhere it is advantageous to apply a directional earth fault relay at the machineterminals. The directional relay, operating for current flowing into the machine, willbe stable for external faults but can operate quickly for generator faults when faultcurrent is fed from the system.

Where several machines are connected in parallel, it is common for only onemachine to be earthed at any time. This prevents the flow of third harmonic currentswhich could overheat the machine. This may be the only earth connection for thispart of the system. Non directional earth fault protection could be applied at theterminals of the unearthed machines in such cases since an unearthed generatorcannot source earth fault current. However, as any of the machines can be earthed,it is prudent to apply directional protection at the terminals of all the machines.There is also a risk that transient spill current can cause operation of a nondirectional, terminal fed, earth fault relay for an external phase fault, hencedirectional elements have an added degree of security. When applied in this way thedirectional earth fault elements will operate for faults on the unearthed machines butnot the earthed machine. Therefore, additional stator earth fault or residualovervoltage/NVD protection should be used to protect the earthed machine. Such ascheme will provide stable, fast, earth fault protection for all machines, no matterwhich generator is earthed.

A single stage definite time sensitive earth fault protection element is provided in theP340 relay, this element can be set to operate with a directional characteristic whenrequired. When directional earth fault protection is required the operating currentshould be derived from either a core balanced CT or the residual connection of 3phase CTs at the terminals of the machine. Direction of the earth fault current for thiselement is determined with reference to the polarising signal, the residual voltage.The polarising signal is taken from the residual overvoltage/NVD protection input orderived from the 3 phase-neutral voltage inputs on the relay.

A polarising voltage threshold is also provided. The element cannot operate unlessvoltage exceeds this threshold. This helps to restrain the element during phase/phasefaults when transient CT saturation produces spill current in the residual connection ofthe phase CTs. No residual voltage will be present during such non earth faultconditions hence the DEF element cannot operate. The element will therefore be


Page 76/176 MiCOM P342, P343

enabled only during genuine earth fault conditions when significant residual voltagewill be present. To prevent the element from mal-operating due to VT fuse failure theelement can be blocked from the VT supervision logic by setting the ISEF Func Link -Block ISEF from VTS to 1. If the ISEF Func Link is set to 0 the SEF element will revertto non directional upon operation of the VTS.

Where Petersen Coil earthing is used, users may wish to use Wattmetric DirectionalEarth Fault protection or an Ιcosφ characteristic. Settings to enable the element tooperate as a wattmetric element are also provided. For insulated earth applications,it is common to use the Ιsinφ characteristic. See the P140 technical guideP14x/EN T/A22, section 2.6 for more details on the application of directional earthfault protection on insulated and Petersen coil systems.

The Sensitive Earth Fault protection can be blocked by energising the relevant DDBsignal via the PSL (DDB 362). This allows the protection to be integrated into busbarprotection schemes as shown in section 2.24, or can be used to improve grading withdownstream devices. DDB signals are also available to indicate the start and trip ofthe protection, (Start: DDB 617, Trips: DDB 447). The state of the DDB signals canbe programmed to be viewed in the “Monitor Bit x” cells of the“COMMISSION TESTS” column in the relay.

Setting ranges for the Sensitive Earth Fault element are shown in the following table:


Min MaxStep Size

GROUP 1SEF/REF PROTECTION

SEF/REF Options SEFSEF, SEF Cos (PHI), SEF Sin (PHI), Wattmetric,

Hi Z REF, Lo Z REF, Lo Z REF + SEF,Lo Z REF + Watt

ΙSEF>1 Function DT Disabled, DT

ΙSEF>1 DirectionalNon-

DirectionalNon-Directional, Directional Fwd,

Directional Rev

ΙSEF>1 Current 0.05 Ιn A 0.005 Ιn A 0.1 Ιn A 0.00025 Ιn A

ΙSEF>1 Delay 1 s 0 s 200 s 0.01 s

ΙSEF> Func Link 1 Bit 0 - Block ΙSEF> from VTS

ΙSEF DIRECTIONAL Sub Heading

ΙSEF> Char Angle 90° –95° 95° 1°

ΙSEF> VNpol Input Measured Measured, Derived

ΙSEF> Vnpol Set

5 V(Vn=100/120V)

20 V(Vn=380/480V)

0.5 V(Vn=100/120V)

2 V(Vn=380/480V)

80 V(Vn=100/120V)

320 V(Vn=380/480V)

0.5 V(Vn=100/120V)

2 V(Vn=380/480V)

WATTMETRIC SEF Sub Heading

PN> Setting

9 x Ιn W(Vn=100/120V)

36 x Ιn W(Vn=380/480V)

0 W

20 x Ιn W(Vn=100/120V)

80 x Ιn W(Vn=380/480V)

0.05 x Ιn W(Vn=100/120V)

0.2 x Ιn W(Vn=380/480V)

For further details regarding the inverse time characteristics refer to the OvercurrentProtection, section 2.4.


MiCOM P342, P343 Page 77/176

2.15.1 Setting guidelines for sensitive earth fault protection

The operating function of the sensitive earth fault protection can be selected by setting“SEF/REF Options” cell. The SEF protection is selected by setting “ΙSEF>1 Function”to ‘Enabled’. To provide sensitive earth fault or sensitive directional earth faultprotection the “SEF/REF Options” cell should be set to ‘SEF’. For SEF cosφ and SEFsinφ earth fault protection “SEF/REF Options” cell should be set to to ‘SEF Cos (PHI) orSEF Sin (PHI)’. The SEF cosφ and SEF sinφ options are not available with lowimpedance REF protection. For wattmetric earth fault protection “SEF/REF Options”cell should be set to ‘Wattmetric’. The other options for “SEF/REF Options” relate torestricted earth fault protection, for more details see section 2.16.

The directionality of the element is selected in the “ΙSEF> Direction” setting. If“ΙSEF> Direction” is set to ‘Directional Fwd’ the element will operate with adirectional characteristic and will operate when current flows in the forward direction,i.e. when current flows into the machine with the relay connected as shown in thestandard relay connection diagram. If “ΙSEF> Direction” is set to ‘Directional Rev’the element will operate with a directional characteristic and will operate whencurrent flows in the opposite direction, i.e. current flow out of the machine into thesystem. If “ΙSEF> Direction” is set to ‘Non-Directional’ the element will operate as asimple overcurrent element. If either of the directional options are chosen additionalcells to select the characteristic angle of the directional characteristic and polarisingvoltage threshold will become visible.

The operating current threshold of the Sensitive Earth Fault protection function,“ΙSEF>1 Current”, should be set to give a primary operating current down to 5% orless of the minimum earth fault current contribution to a generator terminal fault.

The directional element characteristic angle setting, “ΙSEF> Char Angle”, should beset to match as closely as possible the angle of zero sequence source impedancebehind the relaying point. If this impedance is dominated by an earthing resistor, forexample, the angle setting would be set to 0°. On insulated or very high impedanceearthed systems the earth fault current measured by a SDEF element is predominantlycapacitive hence the RCA should be set to –90°.

The polarising voltage threshold setting, “ΙSEF> VNpol Set”, should be chosen to givea sensitivity equivalent to that of the operating current threshold. This current levelcan be translated into a residual voltage as described for the residual overvoltageprotection in section 2.14.

When the element is set as a non directional element the definite time delay setting“ΙSEF>1 Delay” should be set to co-ordinate with downstream devices that mayoperate for external earth faults. For an indirectly connected generator the SEFelement should co-ordinate with the measurement VT fuses, to prevent operation forVT faults. For directional applications when the element is fed from the residualconnection of the phase CTs a short time delay is desirable to ensure stability forexternal earth faults or phase/phase faults. A time delay of 0.5s will be sufficient toprovide stability in the majority of applications. Where a dedicated core balance CTis used for directional applications an instantaneous setting may be used.

2.16 Restricted earth fault protection

Earth faults occurring on a machine winding or terminal may be of limitedmagnitude, either due to the impedance present in the earth path or by thepercentage of stator winding that is involved in the fault. As stated in section 2.13, itis common to apply stator earth fault protection fed from a single CT in the machineearth connection - this can provide time delayed protection for a stator winding or


Page 78/176 MiCOM P342, P343

terminal fault. On larger machines, typically >2MW, where phase CTs can be fittedto both neutral end and terminal ends of the stator winding, phase differentialprotection may be fitted. For small machines, however, only one set of phase CTsmay be available making phase differential protection impractical. For smallergenerators earth fault differential protection can be applied to provide instantaneoustripping for any stator or terminal earth fault. In application the operating zone ofearth fault differential protection is restricted to faults within the boundaries of the CTssupplying the relay, hence this type of element is referred to as restricted earth faultprotection.

When applying differential protection such as REF, some suitable means must beemployed to give the protection stability under external fault conditions, thus ensuringthat relay operation only occurs for faults on the transformer winding/connections.Two methods are commonly used; percentage bias or high impedance. The biasingtechnique operates by measuring the level of through current flowing and altering therelay sensitivity accordingly. The high impedance technique ensures that the relaycircuit is of sufficiently high impedance such that the differential voltage that mayoccur under external fault conditions is less than that required to drive setting currentthrough the relay.

The REF protection in the P340 relays may be configured to operate as either a highimpedance differential or a low impedance biased differential element. The followingsections describe the application of the relay in each mode.

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.

A DDB signals are also available to indicate the tripping of the REF protection, (DDB446). The state of the DDB signals can be programmed to be viewed in the “MonitorBit x” cells of the “COMMISSION TESTS” column in the relay.

The REF settings can be found in the ‘SEF/REF PROT’N’ column and are shownbelow:


Min MaxStep Size

GROUP 1SEF/REF PROT'N

SEF/REF Options SEF SEF, Wattmetric, Hi Z REF, Lo Z REF,Lo Z REF + SEF, Lo Z REF + Watt

REF PROTECTION Sub Heading

ΙREF> k1 20% 0 20% 1%

ΙREF> k2 150% 0 150% 1%

ΙREF> Ιs1 0.2 Ιn A 0.05 Ιn A 1 Ιn A 0.01 Ιn A

ΙREF> Ιs2 1 Ιn A 0.1 Ιn A 1.5 Ιn A 0.01 Ιn A

ΙREF> Ιs 0.2 Ιn A 0.05 Ιn A 1 Ιn A 0.01 Ιn A

Note that CT requirements for REF protection are included in section 4.

2.16.1 Low impedance biased differential REF protection

In a biased differential relay, the through current is measured and used to increasethe setting of the differential element. For heavy through faults, one CT in thescheme can be expected to become more saturated than the other and hence


MiCOM P342, P343 Page 79/176

differential current can be produced. However, biasing will increase the relay settingsuch that the resulting differential current is insufficient to cause operation of therelay.

Figures 22 and 23 show the appropriate relay connections and operatingcharacteristic for the P340 relay applied for biased REF protection, respectively:

!"!

)

Figure 22: Relay connections for biased REF protection

?

?

Figure 23: Biased REF protection operating characteristic


Page 80/176 MiCOM P342, P343

As can be seen in Figure 22, the three line CTs are connected to the three phase CTsin the normal manner. The neutral CT is then connected to the stator earth fault CTinput. These currents are then used internally to derive both a bias and a differentialcurrent quantity for use by the low impedance biased differential REF protection.

The advantage of this method of connection is that the line and neutral CTs are notdifferentially connected and so the neutral CT can also be used to drive the statorearth fault protection. Also, no external equipment such as stabilising resistors ormetrosils are required, unlike the case with high impedance protection.

The formula used by the relay to calculate the required bias quantity is therefore asfollows:

Ιbias = (Highest of Ιa, Ιb or Ιc) + (Ιneutral x Scaling Factor) / 2

The reason for the scaling factor included on the neutral current is explained byreferring to Figure 24:

!"!

&

&

&

& *<<<D

7% *<<D

7

0&'& 2 2 107 #' 1

(&&' 7% *

& *

<<

<<<<5

0' # 71

Figure 24: Neutral scaling for biased REF protection

Where it is required that the neutral CT also drives the stator earth fault protectionelement, it may be a requirement that the neutral CT has a lower ratio than the lineCTs in order to provide better earth fault sensitivity. The relay automatically scalesthe level of neutral current used in the bias calculation by a factor equal to the ratioof the neutral to line CT primary ratings to compensate for any mismatch.


MiCOM P342, P343 Page 81/176

2.16.1.1 Setting guidelines for low impedance biased REF protection

To select low impedance biased REF protection “SEF/REF Option” should be selectedto ‘Lo Z REF’. If REF protection is required to operate alongside sensitive earth faultprotection, “SEF/REF Option” should be selected to ‘Lo Z REF + SEF’ or ‘Lo Z REF +Wattmet’ (if Wattmetric earth fault protection is required).

As can be seen from Figure 23, two bias settings are provided in the REFcharacteristic of the P340. The “ΙREF> k1” level of bias is applied up to throughcurrents of “ΙREF> Ιs2”, which is normally set to the rated current of the machine.“ΙREF> k1” should normally be set to 0% to give optimum sensitivity for internalfaults. However, if any differential spill current is present under normal conditionsdue to CT mismatch, then “ΙREF> k1” may be increased accordingly, to compensate.

“ΙREF> k2” bias is applied for through currents above “ΙREF> Ιs2” and may typicallybe set to 150% to ensure adequate restraint for external faults.

The neutral current scaling factor which automatically compensates for differencesbetween neutral and phase CT ratios relies upon the relay having been programmedwith the correct CT ratios. It must therefore be ensured that these CT ratios areentered into the relay, in the “CT RATIOS” menu, in order for the scheme to operatecorrectly.

The differential current setting “ΙREF> Ιs1” should typically be set to 5% of the limitedearth fault current level.

2.16.2 High impedance restricted earth fault protection

The high impedance principle is best explained by considering a differential schemewhere one CT is saturated for an external fault, as shown in Figure 25.

If the relay circuit is considered to be a very high impedance, the secondary currentproduced by the healthy CT will flow through the saturated CT. If CT magnetisingimpedance of the saturated CT is considered to be negligible, the maximum voltageacross the relay circuit will be equal to the secondary fault current multiplied by theconnected 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 the relayis less than its current setting. As the impedance of the relay input alone is relativelylow, a series connected external resistor is required. The value of this resistor, RST, iscalculated by the formula shown in Figure 25.

An additional non linear resistor, metrosil, may be required to limit the peaksecondary circuit voltage during internal fault conditions.

To ensure that the protection will operate quickly during an internal fault the CT’sused to operate the protection must have a kneepoint voltage of at least 4Vs.


Page 82/176 MiCOM P342, P343

'

#$%$&%'& %%

(& )%

* % $+'

, ' $&&% $

-& * % *

.$

* *

,

,

,!

,"

*

/

/'%/ 0 * ,1

)'2*2$% 0'1

*/ 3

4+&<59

Figure 25: Principle of high impedance differential protection

!"!

F

* )'

7, 7401

7, *

Figure 26: Relay connections for high impedance REF protection


MiCOM P342, P343 Page 83/176

The necessary relay connections for high impedance REF are shown in Figure 26:

As can be seen from Figure 26, the high impedance protection uses an externaldifferential connection between the line CTs and neutral CT. The SEF input is thenconnected to the differential circuit with a stabilising resistor in series.

2.16.2.1 Setting guidelines for high impedance REF protection

From the “Sens E/F Options” cell, ‘Hi Z REF’ must be selected to enable HighImpedance REF protection. The only setting cell then visible is “ΙREF> Ιs”, which maybe programmed with the required differential current setting. This would typically beset to give a primary operating current of either 30% of the minimum earth fault levelfor a resistance earthed system or between 10 and 60% of rated current for a solidlyearthed system.

The primary operating current (Ιop) will be a function of the current transformer ratio,the relay operating current (“ΙREF> Ιs”), the number of current transformers inparallel with a relay element (n) and the magnetising current of each currenttransformer (Ιe) at the stability voltage (Vs). This relationship can be expressed inthree ways:

1. To determine the maximum current transformer magnetising current to achievea specific primary operating current with a particular relay operating current.

Ιe < 1

n x

Ιop

CT ratio - Gen diff REF > Ιs1

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

ΙREF Ιs1 <

Ιop

CT ratio - nΙe

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

Ιop = (CT ratio) x (ΙREF > Ιs1 + nΙe)

In order to achieve the required primary operating current with the currenttransformers that are used, a current setting “ΙREF> Ιs” must be selected for the highimpedance element, as detailed in expression (ii) above. The setting of the stabilisingresistor (RST) must be calculated in the following manner, where the setting is afunction of the required stability voltage setting (VS) and the relay current setting“ΙREF> Ιs”.

RST = Vs

ΙREF > Ιs1 = 0.7 ΙF (RCT + 2RL)

ΙREF > Ιs1

See Figure 25 for reference.

Note: The above equation assumes negligible relay impedance.

The stabilising resistor supplied is continuously adjustable up to its maximumdeclared resistance.


Page 84/176 MiCOM P342, P343

USE OF “METROSIL” NON-LINEAR RESISTORS

Metrosils 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 to withstand3000V 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 current transformersaturation did not occur. This prospective voltage will be a function of maximuminternal fault secondary current, the current transformer ratio, the current transformersecondary winding resistance, the current transformer lead resistance to the commonpoint, the relay lead resistance and the stabilising resistor value.

Vp = 2 2 Vk ( )Vf - Vk

Vf = Ι'f (RCT + 2RL + RST)

where

Vp = peak voltage developed by the CT under internal fault conditions.

Vk = current transformer knee-point voltage.

Vf = maximum voltage that would be produced if CT saturation did notoccur.

Ι‘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, metrosils shouldbe applied. They are connected across the relay circuit and serve the purpose ofshunting the secondary current output of the current transformer from the relay inorder to prevent very high secondary voltages.

Metrosils are externally mounted and take the form of annular discs. Their operatingcharacteristics follow the expression:

V = CΙ 0.25

where

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

C = constant of the non-linear resistor (“metrosil”)

Ι = 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:

Ι(rms) = 0.52

Vs (rms) x 2

C 4


MiCOM P342, P343 Page 85/176

where

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

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:

1. At the relay voltage setting, the non-linear resistor (“metrosil”) current should beas low as possible, but no greater than approximately 30mA rms for 1A currenttransformers and approximately 100mA rms for 5A current transformers.

2. At the maximum secondary current, the non-linear resistor (“metrosil”) shouldlimit the voltage to 1500V rms or 2120V peak for 0.25 second. At higher relayvoltage settings, it is not always possible to limit the fault voltage to 500V rms,so higher fault voltages may have to be tolerated.

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


The Metrosil units with 1 Amp CTs have been designed to comply with the followingrestrictions:

1. At the relay voltage setting, the Metrosil current should less than 30mA rms

2. At the maximum secondary internal fault current the Metrosil unit should limitthe voltage to 1500V rms if possible.

The Metrosil units normally recommended for use with 1Amp CTs are as shown in thefollowing table:

NominalCharacteristic Recommended Metrosil TypeRelay Voltage

SettingC 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 withoutmounting brackets unless otherwise specified by the customer


These Metrosil units have been designed to comply with the following requirements:-

1. At the relay voltage setting, the Metrosil current should less than 100mA rms(the actual maxium currents passed by the units shown below their typedescription).

2. At the maximum secondary internal fault current the Metrosil unit should limitthe voltage to 1500V rms for 0.25secs. At the higher relay settings, it is notpossible to limit the fault voltage to 1500V rms hence higher fault voltages haveto be tolerated (indicated by *, **, ***).

The Metrosil units normally recommended for use with 5 Amp CTs and single polerelays are as shown in the following table:


Page 86/176 MiCOM P342, P343

Recommended METROSIL TypeSecondaryinternal

faultcurrent

Relay Voltage Setting

Amps rms Up to 200V rms 250V rms 275V rms 300V rms

50A600A/S1/S1213C = 540/640

35mA rms

600A/S1/S1214C = 670/800

40mA rms

600A/S1/S1214C =670/800

50mA rms

600A/S1/S1223C = 740/870*

50mA rms

100A600A/S2/P/S1217

C = 470/54070mA rms

600A/S2/P/S1215C = 570/670

75mA rms

600A/S2/P/S1215C = 570/670100mA rms

600A/S2/P/S1196C =620/740*100mA rms

150A600A/S3/P/S1219

C = 430/500100mA rms

600A/S3/P/S1220C = 520/620100mA rms

600A/S3/P/S1221C = 570/670**

100mA rms

600A/S3/P/S1222C =620/740***

100mA rm

Note: *2400V peak **2200V peak ***2600V peak

In some situations single disc assemblies may be acceptable, contact AREVA T&D fordetailed applications.

1. The Metrosil units recommended for use with 5 Amp CTs can also be appliedfor use with triple pole relays and consist of three single pole units mounted onthe same central stud but electrically insulated for each other. To order theseunits please specify "Triple Pole Metrosil Type", followed by the single-pole typereference.

2. Metrosil units for higher relay voltage settings and fault currents can besupplied if required.

For further advice and guidance on selecting METROSILS please contact theApplications department at AREVA T&D.

2.17 100% stator earth fault protection

As stated in sections 2.13 and 2.14, standard residual current or residual overvoltageprotection elements can provide earth fault protection for 95% of the generator statorwinding. Earth faults in the final 5% of the winding will result in such a low faultcurrent or such a small imbalance in voltage that conventional protection cannot berelied upon to detect the fault. In most applications this limitation is accepted due tothe low probability of a fault occurring in the 5% of the stator winding closest to thestar point, where the voltage to earth is lowest. However, for large generators 100%stator earth fault protection is commonly specified to cover all winding earth faults.Faults close to the star point can occur as a consequence of mechanical damagesuch as creepage of the conductors and loosening of bolts.

Most generators will produce third harmonic voltage to some degree due to nonlinearities in the magnetic circuits of the generator design. Under normal operatingconditions the distribution of the third harmonic voltage along the stator windingscorresponds to Figure 27a. It can be seen that the maxima occur at the star point Nand the terminal T. The values increase with generator load. For a stator earth faultat the star point, Figure 27b, the amplitude of the third harmonic in the voltage at theterminals is approximately doubled both when the generator is off load prior the fault(U’TE) and when it is fully loaded (U”TE). The same third harmonic values can bemeasured in the star point voltages U’NE and U”NE for an earth fault at the generatorterminals, Figure 27c.


MiCOM P342, P343 Page 87/176

(

(

)(

* +

*

,--+*

+

+ +

,-

,--

. .

,-+

+

. .

,--+

,-+

.

,-

,--

.

Figure 27: Distribution of the 3rd harmonic component along the stator winding of a large generator, (a) normal operation, (b) statorearth fault at the star point (c), stator earth fault at the terminals

m = relative number of turns

To detect faults in the last 5% of the generator winding, the P343 relay is providedwith a third harmonic undervoltage and overvoltage element. These, together withthe residual overvoltage or stator earth fault protection elements, will provideprotection for faults over the complete winding.

The third harmonic neutral under voltage element is applicable when the neutralvoltage measurement is available at the neutral end of the generator. It is supervisedby a three-phase under voltage element, which inhibits the protection when all thephase-phase voltages at the generator terminal are below the threshold, to preventoperation when the machine is dead. Interlocking may also be required to preventfalse operation during certain conditions. For example, some machines do notproduce substantial third harmonic voltage until they are loaded. In this case, thepower supervision elements (active, reactive and apparent power) could be used todetect load to prevent false tripping under no load conditions. These powerthresholds can be individually enabled and disabled and the setting range is from 2-100%Pn.


Page 88/176 MiCOM P342, P343

For applications where the neutral voltage measurement can only be obtained at thegenerator terminals, from a broken delta VT for example, the under voltagetechnique cannot be applied. Therefore, the third harmonic neutral over voltageelement can be used for this application. The blocking features of the under voltageand power elements are not required for the 3rd harmonic neutral over voltageelement.

Note: The relay can only select 3rd harmonic neutral under voltage or3rd harmonic neutral over voltage, but not both.

The logic diagrams of the two protection schemes are shown in Figure 28.

&

VN 3rd Harmonic <

Vca<

P 3ph <

Q 3ph <

S 3ph <

100% Stator EF Trip

1

Time delay

Note: 3Ph W, 3ph VAR and 3ph VA inhibits can be individually disabled.

100% Stator EF Start

VN 3rd Harmonic < Time delay

Third harmonic neutral under voltage scheme

100% Stator EF Trip

100% Stator EF Start

Third harmonic neutral over voltage scheme

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Figure 28: 100% Stator earth fault protection block diagram

A normal level of third harmonic voltage of 1% is sufficient to ensure that thirdharmonic undervoltage or overvoltage and residual overvoltage protection functionswill overlap hence providing 100% coverage for earth faults on the stator winding. Ingeneral, third harmonic undervoltage protection alone can provide coverage forfaults on 30% of the generator winding.


MiCOM P342, P343 Page 89/176

The 3rd harmonic undervoltage element operates from the same input as the neutralvoltage displacement protection and must be supplied from a VT connected in thegenerator earth connection as shown in Figure 29. The 3rd harmonic overvoltageelement operates from the neutral voltage measurement at the generator terminals,via an open-delta VT, for example as shown in Figure 29.

For applications where parallel machines are directly connected to the busbarsdiscrimination of an earth fault between the machines usually can not be achieved.For applications where machines are connected to the busbars via a delta/startransformer the delta winding blocks the 3rd harmonic currents from other machinesso correct discrimination can be achieved for earth faults.

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Figure 29: Connection for 3rd harmonic undervoltage and overvoltage for 100% stator earth fault protection

DDB signals are available to indicate the start and trip of the protection, (Start: DDB621, Trip: DDB 416). The state of the DDB signals can be programmed to be viewedin the “Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.

Setting ranges for the 100% stator earth fault third harmonic undervoltage protectionelement are shown in the following table:


Page 90/176 MiCOM P342, P343


Min MaxStep Size

Group 1: 100% EF

100% St EF Status EnabledDisabled, VN3H< Enabled,

VN3H> Enabled

100% St EF VN3H<

1V(Vn=100/120V)

4V(Vn=380/480V)

0.3V(Vn=100/120V)

1.2V(Vn=380/480V)

20V(Vn=100/120V)

80V(Vn=380/480V)

0.1V(Vn=100/120V)

0.4V(Vn=380/480V)

VN3H< Delay 5 s 0 s 100 s 0.01 s

V<Inhibit set

80V(Vn=100/120V)

320V(Vn=380/480V)

30V(Vn=100/120V)

120V(Vn=380/480V)

120V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

P<Inhibit Disabled Enabled, Disabled

P<Inhibit set

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

200 x Ιn W(Vn=100/120V)

800 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

Q<Inhibit Disabled Enabled, Disabled

Q<Inhibit set

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

200 x Ιn W(Vn=100/120V)

800 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

S<Inhibit Disabled Enabled, Disabled

S<Inhibit set

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

4 x Ιn W(Vn=100/120V)

16 x Ιn W(Vn=380/480V)

200 x Ιn W(Vn=100/120V)

800 x Ιn W(Vn=380/480V)

0.5 x Ιn W(Vn=100/120V)

2 x Ιn W(Vn=380/480V)

100% St EF VN3H>

1V(Vn=100/120V)

4V(Vn=380/480V)

0.3V(Vn=100/120V)

1.2V(Vn=380/480V)

20V(Vn=100/120V)

80V(Vn=380/480V)

0.1V(Vn=100/120V)

0.4V(Vn=380/480V)

VN3H> Delay 5 s 0 s 100 s 0.01 s

2.17.1 Setting guidelines for 100% stator earth fault protection

The 100% stator earth fault protection element can be selected by setting the“100% St EF Status” cell to ‘Enabled’.

The third harmonic undervoltage threshold, “100% St EF VN3H<”, must be set belowthe level of third harmonic voltage present under normal conditions. This voltage canbe determined by viewing the “VN 3rd Harmonic” cell in the “MEASUREMENTS 3”menu. A typical value for this threshold could be 0.5V.

The third harmonic overrvoltage threshold, “100% St EF VN3H>”, must be set abovethe level of third harmonic voltage present under normal conditions. This voltage canbe determined by viewing the “VN 3rd Harmonic” cell in the “MEASUREMENTS 3”menu. A typical value for this threshold could be 1V.

A time delay for these elements can be set in the “VN3H< Delay and VN3H> Delay”cells.


MiCOM P342, P343 Page 91/176

The terminal voltage interlock threshold, used to prevent operation of the elementwhen the machine is not running, “100% St EF V<Inh”, should typically be set to 80%of machine rated voltage.

The power interlock thresholds, used to prevent operation of the element until there issufficient load current, “P<Inhibit set, Q<Inhibit set, S<Inhibit”, should be enabled ifrequired to prevent operation under no load conditions. One or more of thethresholds can be used as an interlock. They should be set during commissioning byincreasing the load current until the 3rd harmonic undervoltage element is reset andsetting the power thresholds above the measured power values. The power valuescan be determined by viewing the “3 phase Watts, 3 phase VArs, 3 phase VA” cellsin the “MEASUREMENTS 2” menu.

Note: Other earth fault protection (residual overvoltage or currentoperated stator earth fault protection) must also be enabled toprovide coverage for earth faults across the complete statorwinding.

2.18 Overfluxing protection

Overfluxing or overexcitation of a generator, or transformer connected to theterminals of a generator, can occur if the ratio of voltage to frequency exceeds certainlimits. High voltage or low frequency, causing a rise in the V/Hz ratio, will producehigh flux densities in the magnetic core of the machine or transformer. This couldcause the core of the generator or transformer to saturate and stray flux to beinduced in un-laminated components that have not been designed to carry flux. Theresulting eddy currents in solid components (e.g. core bolts and clamps) and end ofcore laminations can cause rapid overheating and damage.

Overfluxing is most likely to occur during machine start up or shut down whilst thegenerator is not connected to the system. Failures in the automatic control of theexcitation system, or errors in the manual control of the machine field circuit, couldallow excessive voltage to be generated. It is also possible for overfluxing to occurduring parallel operation when the generator has been synchronised with the localsupply network. Sudden loss of load could cause an overvoltage condition, in suchcircumstances, if the generator excitation system does not respond correctly.

The P342/343 relays provide a two stage overfluxing element. The elementmeasures the ratio of voltage, (VAB), to frequency, V/Hz, and will operate when thisratio exceeds the setting. One stage can be set to operate with a definite time orinverse time delay, this stage can be used to provide the protection trip output. Theother stage has a definite time delay characteristic and can be used as an alarmstage to indicate unhealthy conditions before damage has occurred to the machine.

DDB signals are also available to indicate the start and trip of the protection, (Start:DDB 636, Trip: DDB 429). A further DDB ‘V/Hz Alarm’ signal is generated from theoverfluxing alarm stage (DDB 308). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSION TESTS”column in the relay.

Setting ranges for the Overfluxing protection element are shown in the followingtable:


Page 92/176 MiCOM P342, P343


Min MaxStep Size

GROUP 1: VOLTS/HZ

V/f Alarm Status Enabled Enabled, Disabled

V/f Alarm Set

2.31 V/Hz(Vn=100/120V)

9.24 V/Hz(Vn=380/480V)

1.5 V/Hz(Vn=100/120V)

6 V/Hz(Vn=380/480V)

3.5 V/Hz(Vn=100/120V)

14 V/Hz(Vn=380/480V)

0.01 V/Hz(Vn=100/120V)

0.04 V/Hz(Vn=380/480V)

V/f Alarm Delay 0 s 0 s 100 s 0.01 s

V/f Trip Func DT Disabled, DT, IDMT

V/f Trip Setting

2.42 V/Hz(Vn=100/120V)

9.24 V/Hz(Vn=380/480V)

1.5 V/Hz(Vn=100/120V)

6 V/Hz(Vn=380/480V)

3.5 V/Hz(Vn=100/120V)

14 V/Hz(Vn=380/480V)

0.01 V/Hz(Vn=100/120V)

0.04 V/Hz(Vn=380/480V)

V/f Trip TMS 1 1 63 1

V/f Trip Delay 1 s 0 s 100 s 0.01 s

The inverse time characteristic has the following formula:

t = 0.8 + 0.18 * TMS

(M - 1)2

Where M = V/f

( V/f Trip Setting )

V = measured voltage

F = measured frequency

2.18.1 Setting guidelines for overfluxing protection

The overfluxing protection element trip stage can be selected by setting the “V/f TripFunc” cell to the required time delay characteristic; ‘DT’ for definite time operation,‘IDMT’, for inverse time operation. The overfluxing protection trip stage is disabled if“V/f Trip Func” is set to ‘Disabled’.

The overfluxing protection alarm stage may be Enabled/Disabled in the “V/f AlarmStatus” cell.

In general, a generator or generator transformer overflux condition will occur if theV/Hz ratio exceeds 1.05p.u. i.e. a 5% overvoltage condition at rated frequency.

The element is set in terms of the actual ratio of voltage to frequency; the overfluxingthreshold setting, “V/f Trip Setting”, can therefore be calculated as shown below:

where

− the VT secondary voltage at rated primary volts is 110V

− the rated frequency is 50Hz

The overfluxing alarm stage threshold setting, “V/f Alarm Set”, can be set lower thanthe trip stage setting to provide an indication that abnormal conditions are presentand alert an operator to adjust system parameters accordingly.


MiCOM P342, P343 Page 93/176

The time delay settings should be chosen to match the withstand characteristics of theprotected generator or generator/transformer. If an inverse time characteristic isselected, the time multiplier setting, “V/f Trip TMS”, should be chosen so theoperating characteristic closely matches the withstand characteristic of the generatoror generator/transformer. If a definite time setting is chosen for the trip stage thetime delay is set in the “V/f Trip Delay” cell. The alarm stage time delay is set in the“V/f Alarm Delay” cell.

Reference should be made to manufacturers withstand characteristics beforeformulating these settings.

2.19 Dead machine/unintentional energisation at standstill protection

Accidental energisation of a generator when the machine is not running can causesevere damage to the machine. If the breaker is closed, when the machine is atstandstill, the generator will begin to act as an induction motor with the surface of therotor core and the rotor winding slot wedges acting as the rotor current conductors.This abnormal current in the rotor can cause arcing between components, e.g. slotwedge to core, and results in rapid overheating and damage.

To provide fast protection for this condition, the P343 relay provides an instantaneousovercurrent element that is gated with a three phase undervoltage detector. Thescheme logic of this function is shown in Figure 30.

The element is enabled when the machine is not running, i.e. not generating anyvoltage, or when the breaker is open. Therefore the element can have a low currentsetting, resulting in high speed operation when required. For the element to operatecorrectly the relay voltage input must be from a machine side VT; busbar VTs cannotbe used.

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Figure 30: Fixed scheme logic for unintentional energisation of standstillprotection

Setting ranges for the Dead Machine/Unintentional Energisation protection elementare shown in the following table:


Page 94/176 MiCOM P342, P343


Min MaxStep Size

GROUP 1DEAD MACHINE

Dead Mach Status Enabled Enabled, Disabled

Dead Mach Ι> 0.1 Ιn A 0.08 Ιn A 4 Ιn A 0.01 Ιn A

Dead Mach V<

80 V(Vn=100/120V)

320V(Vn=380/480V)

10V(Vn=100/120V)

40V(Vn=380/480V)

120V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

Dead Mach tPU 5 s 0 s 10 s 0.1 s

Dead Mach tDO 0 s 0 s 10 s 0.1 s

2.19.1 Setting guidelines for dead machine protection

The dead machine protection element can be selected by setting the“Dead Mach Status” cell to ‘Enabled’.

The overcurrent threshold, “Dead Mach Ι>”, can be set to less than full load currentas the element will not be enabled during normal machine operation. A setting of10% of full load current can typically be used.

The undervoltage threshold, “Dead Mach V<”, should typically be set at 85% of thenominal voltage to ensure that the element is enabled when the machine is notrunning.

The pick-up time delay, “Dead Mach tPU”, which provides a small time delay toprevent initialisation of the element during system faults, should typically be set to 5s,or at least in excess of the protection clearance time for a close up phase to phasefault.

The drop off time delay, “Dead Mach tDO”, ensures that the element remainsinitialised following accidental closure of the circuit breaker, when the undervoltagedetector could reset. A delay of 500ms will ensure that the element can operatewhen required.

2.20 Resistive temperature device (RTD) thermal protection

Prolonged overloading of generators may cause their windings to overheat, resultingin premature ageing of the insulation, or in extreme cases, insulation failure. Wornor unlubricated bearings can also generate localised heating within the bearinghousing. To protect against any general or localised overheating, the P343 relay hasthe ability to accept inputs from up to 10 – 3 wire Type A PT100 resistive temperaturesensing devices (RTD). These are connected as shown in Figure 31 below.


MiCOM P342, P343 Page 95/176

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Figure 31: Connection for RTD thermal probes

Such probes can be strategically placed in areas of the machine which aresusceptible to overheating or heat damage. Where power transformers are locatedclose to the protected machine, certain RTD probes could be assigned to provideovertemperature protection for the transformer(s). This could protect against windinghot spot overheating or overtemperature in the bulk of the insulating oil.

Typically a PT100 RTD probe can measure temperature within the range –40° to+300°C. The resistance of these devices changes with temperature, at 0°C they havea resistance of 100Ω. The temperature at each probe location can be determined bythe relay, and is available for:

• Temperature monitoring, displayed locally, or remotely via the relaycommunications.

• Alarming, should a temperature threshold be exceeded for longer than a set timedelay.

• Tripping, should a temperature threshold be exceeded for longer than a set timedelay.

Should the measured resistance be outside of the permitted range, an RTD failurealarm will be raised, indicating an open or short circuit RTD input. These conditionsare signalled via DDB signals available within the PSL (DDB 310-314) and are alsoshown in the measurements 3 menu.

DDB signals are also available to indicate the alarm and trip of the each RTD,(Alarm: DDB 743-752 Trip: DDB 430-439). The state of the DDB signals can beprogrammed to be viewed in the “Monitor Bit x” cells of the “COMMISSION TESTS”column in the relay.

Note that direct temperature measurement can provide more reliable thermalprotection than devices which use a thermal replica energised from phase current.The latter is susceptible to inaccuracies in time constants used by the replica model,and also inaccuracies due to the variation in ambient temperature.


Page 96/176 MiCOM P342, P343

See the Installation section (P34x/EN IN) of the Operating Guide, forrecommendations on RTD connections and cables.

Setting ranges for the RTD Thermal protection are shown in the following table:


Min MaxStep Size

GROUP 1RTD PROTECTION

Select RTD 0000000000

Bit 0 - Select RTD 1Bit 1 - Select RTD 2Bit 2 - Select RTD 3Bit 3 - Select RTD 4Bit 4 - Select RTD 5Bit 5 - Select RTD 6Bit 6 - Select RTD 7Bit 7 - Select RTD 8Bit 8 - Select RTD 9Bit 9 - Select RTD 10

RTD x Alarm Set 80°C 0°C 200°C 1°C

RTD x Alarm Dly 10s 0 100s 1s

RTD x Trip Set 85°C 0°C 200°C 1°C

RTD x Trip Dly 1s 0 100s 1s

Where x = 1 to 10

2.20.1 Setting guidelines for RTD thermal protection

Each RTD can be enabled by setting the relevant bit in “Select RTD”. For example ifSelect RTD is set to 0000000111, then RTD1, RTD2 and RTD3 would be enabled andthe associated settings would be visible in the menu.

The temperature setting for the alarm stage for each RTD can be set in the“RTD x Alarm Set” cells and the alarm time delay in the “RTD x Alarm Dly” cell.

The temperature setting for the trip stage for each RTD can be set in the“RTD x Trip Set” cells and the trip stage time delay in the “RTD x Trip Dly” cell.

Typical operating temperatures for protected plant are given in the table below.These are provided as a guide, actual figures MUST be obtained from the equipmentmanufacturers:

Parameter Typical Service Temperature Short Term Overloadingat Full Load

Bearingtemperaturegenerators

60 – 80°C, depending on the type ofbearing. 60 – 80°C+

Top oiltemperature oftransformers

80°C (50 – 60°C above ambient).

A temperature gradientfrom windingtemperature is usuallyassumed, such that topoil RTDs can providewinding protection.


MiCOM P342, P343 Page 97/176

Parameter Typical Service Temperature Short Term Overloadingat Full Load

Winding hotspottemperature

98°C for normal ageing ofinsulation. Cyclic overloading mightgive

140°C+ duringemergencies

Table showing typical operating temperatures of plant.

2.21 P342 pole slipping protection

A generator might pole slip, or fall out-of-step with other power system sources, in theevent of failed or abnormally weak excitation or as a result of delayed system faultclearance. This can be further aggravated when there is a weak (high reactance)transmission link between the generator and the rest of the power system.

The process of pole slipping following excitation failure is discussed in section 2.10.The P342 field failure protection function should respond to such situations to give atime delayed trip. The electrical/mechanical power/torque oscillations followingexcitation failure may be relatively gentle. If pole slipping occurs with maximumexcitation (generator emf >2.0 p.u.), the power/torque oscillations and power systemvoltage fluctuations following loss of stability can be much more severe. For largemachines there may be a requirement to provide protection to trip the generatorunder such circumstances, to prevent plant damage or remove the disturbance to thepower system.

Pole slipping protection is frequently requested for relatively small generators runningin parallel with strong public supplies. This might be where a co-generator runs inparallel with the distribution system of a public utility, which may be a relatively strongsource, but where high-speed protection for distribution system faults is not provided.The delayed clearance of system faults may pose a stability threat for theco-generation plant.

With the P342 relay there is no specific pole slipping protection function, but anumber of the protection functions provided can offer a method of ensuring delayedtripping, if appropriately applied.

2.21.1 Reverse power protection

During a pole slipping event the machine will cyclically absorb and export power asthe machine rotor slips with respect to the power system. Therefore, any powerelement selected to operate from reverse power can pick-up during the pole slip.Reverse power protection tripping is usually time delayed and this time delay willprevent the element from tripping during a pole slip. However, each powerprotection stage in the P342 relay has an associated delay on drop off, or reset, timer(“Power1 DO Timer”, “Power2 DO Timer”). This can be used to prevent resetting ofthe reverse power stage during a pole slipping event, leading to eventual tripping ifthe event continues.

2.21.2 System back-up protection function

In a similar manner to the power protection function, the system back-up protectionfunction would operate cyclically with the periodic high levels of stator current thatwould arise during pole slipping. These peaks of current may also be accompaniedby coincident drops in generator terminal voltage, if the generator is near theelectrical centre of swinging. As discussed in section 2.5, the system back-upprotection function is provided with a timer characteristic timer-hold setting, “V DepOC tRESET”, “Z< tRESET”, which can be used to ensure that the protection functionwill respond to cyclic operation during pole slipping. In a similar manner, some


Page 98/176 MiCOM P342, P343

operators of small, unmanned hydro-generators have relied on the integrating actionof induction disc overcurrent protection to ensure disconnection of a persistentlyslipping machine.

2.21.3 Field failure protection function

Slightly faster pole slipping protection might be assured in many applications byappropriately applying the field failure protection function and associated schemelogic timers.

Where the power system source impedance is relatively small in relation to theimpedance of a generator during pole slipping, the electrical centre of slipping islikely to lie within the generator. This would be ‘behind’ the relaying point, asdefined by the location of the voltage transformer. Such a situation is likely to existfor co-generation schemes and might also be the case for some fairly large utilitygeneration schemes connected to a densely interconnected transmission system. Thedynamic impedance of the generator during pole slipping (Xg) should lie between theaverage value of the direct and quadrature axis transient reactance’s (Xd’ and Xq’)and the average value of the direct/quadrature axis synchronous reactance’s (Xd andXq). However neither extreme would actually be reached. During low-slip periods ofa pole slip cycle, the synchronous reactance’s would apply, whereas the transientimpedance’s would apply during periods of relatively high slip.

Figure 32 illustrates how the impedance seen at the generator protection relayingpoint may vary during pole slipping for a relatively small co-generator directlyconnected to a relatively strong distribution power system. It should be noted that thebehaviour of a generator during pole slipping may be further complicated byintervention of an automatic voltage regulator and by the response of any speed-dependent excitation source (e.g. shaft-driven exciter).

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Figure 32: Field failure protection function characteristics (smallco-generator)


MiCOM P342, P343 Page 99/176

It can be seen from the simple analysis of Figure 32 that the field failure protectionfunction may respond to the variation in impedance seen during pole slipping forsome applications. However the impedance characteristic offset might have to bereduced to guarantee response for the theoretical lower range of dynamic generatorimpedance (Xg). The lack of the normally recommended characteristic offset shouldnot pose any problem of unwanted protection function response during the normalrange of operation of a machine (with rotor angles kept below 90°), but a longer triptime delay might be required to prevent unwanted protection response during stablepower swings caused by system disturbances. The most marginal condition to detectis where the generator is fully loaded, with maximum excitation applied. Even if theimpedance characteristic offset is not reduced, impedance element pick up shouldstill occur during part of a slip cycle, when the machine impedance is high and wherethe rotor angle is high. More careful consideration might have to be given to thereset time delay setting (“FFail1 DO Timer”) required in such circumstances.

During pole slipping, any operation of the field failure protection function will becyclic and so it would be necessary to set the reset time delay (“FFail1 DO Timer”) tobe longer than the time for which the impedance seen will cyclically lie outside thefield failure characteristic. A typical delay setting might be 0.6s, to cover slipfrequencies in excess of 2Hz. When the timer “FFail1 DO Timer” is set, the fieldfailure trip time delay (“FFail1 Time Delay”) must be increased to be greater than thesetting of “FFail1 DO Timer”.

Sometimes pole slipping protection must be guaranteed, especially in the case of alarger utility generator connected to a relatively weak transmission system. In suchapplications, and where fast tripping is required, or where the pole slipping responseof field failure protection function is otherwise uncertain, a stand-alone protectionscheme, such as used in the P343 should be used. The delayed detection andtripping offered by the P340 Field Failure protection function should, however, beadequate for many applications.

For further details regarding setting of field failure protection for time delayed poleslipping detection, contact AREVA T&D.

2.22 P343 pole slipping protection

2.22.1 Introduction

Sudden changes or shocks in an electrical power system such as line switchingoperations, large jumps in load or faults may lead to power system oscillations whichappear as regular variations of the currents, voltages and angular separationbetween systems. This phenomenon is referred to as a power swing.

In a recoverable situation, the power swing will decay and finally disappear in a fewseconds. Synchronism will be regained and the power system will recover to stableoperation. In a non-recoverable situation, the power swing becomes so severe thatsynchronism is lost between the generator and system, a condition recognised as out-of-step or pole slipping from the view of a generator. If such a loss of synchronismdoes occur, it is imperative to separate the asynchronous areas from the rest of thesystem before generators are damaged or before a widespread outage can occur.

Pole slipping occurs when the prime mover input power of a generator exceeds theelectrical power absorbed by the system. The condition results from the mismatch inthe operating frequencies of two or more machines. During pole slipping themachine produces alternatively generating and motoring torque of high magnitudeswith corresponding current peaks and voltage dips.


Page 100/176 MiCOM P342, P343

During normal system operation the following events can lead to the generator poleslipping condition.

• The occurrence of an abnormality such as:

A transient system fault.

The failure of the generator governor.

The failure of the generator excitation control (asynchronous running).

Reconnection of an 'islanded' system without synchronisation.

• The transient change in the system requirements of real and reactive powercomponents sets the generator rotor to oscillate around the new equilibrium point.

• If the initial transient disturbance is severe enough and for a sufficiently longduration the rotor swing may exceed the maximum stability limit causing thegenerator to slip poles.

• For a weak system switching transients may also result in pole slipping.

Nowadays, with the advent of EHV systems, large conductor-cooled generators andwith the expansion of the transmission system, system and generator impedanceshave changed considerably. System impedances have decreased while generatorand step-up transformer impedances have increased. This trend has resulted in theimpedance centre during a power swing appearing inside the step-up transformer orinside the generator, which is generally out of the protection zone of conventionalout-of-step relays installed in the system. Therefore, separate relaying should beapplied to protect the machine against pole slipping.

Relays employing impedance-measuring elements for the detection of the poleslipping condition utilise the generator terminal voltage and current signals as inputs.During a generator pole slip the system voltage and current go through slip frequencyvariations of extremely high amplitude. These variations are reflective of thecorresponding apparent changes in the generator terminal impedance. The relay willbe able to detect the condition only after the generator has actually slipped poles.The conventional technique employs measurement of generator terminal impedanceto determine pole slipping conditions. Directional and blinder elements are usedtogether with a mho element to obtain the desired relay characteristics.

2.22.2 Loss of synchronism characteristics

Before any further discussion, it is necessary to have a brief review of the loss ofsynchronism characteristic which is used in the analysis of generator pole slipping.

A common method used to detect a loss of synchronism is to analyse the apparentimpedance as measured at the generator terminals. According to the simplifiedrepresentation of a machine and system shown in Figure 33, the impedancepresented to the relay ZR (installed at point A) under a loss of synchronism(recoverable power swing or pole slipping) condition can be described by equation1:


MiCOM P342, P343 Page 101/176

P1254ENa

Where:

EG = the generator terminal voltage

ZG = the generator impedance

ZT = the impedance of step-up transform

ZS = the impedance of the power system connected to the generation unit

ES = the system voltage

ZR = (ZG + ZT + ZS) n (n - cosδ - j sinδ)

(n - cosδ)2 + sin2 δ - ZG --------------------- Equation 1

Where:

n = EG

ES = magnitude ratio of generator terminal voltage to the system voltage

δ = arg ĖG

ĖS = rotor angle by which generator terminal voltage leads system voltage

Figure 33: Simplified two machine system

The apparent impedance as viewed at the generator terminals (Point A) will vary as afunction of the ratio n and the angular separation δ between the machine and thesystem. With the aid of the R/X impedance diagram, a set of impedance locirepresenting a loss of synchronism along with the system impedances are plotted asshown in Figure 34.


Page 102/176 MiCOM P342, P343

P1255ENa

Figure 34: Apparent impedance loci viewed at the generator terminal (point A)

It has been well proven that the locus of the impedance as measured at the generatorterminals (point A) is either a straight line or circular depending on whether EG andES are of equal or different magnitudes. The impedance locus is a straight line whichis a perpendicular bisector of the total system impedance between G and S when EG/ ES = 1. When EG / ES > 1, the circular locus is located above the bisector with itscentre on the extension of the total impedance line GS. When EG / ES < 1, theimpedance locus is situated below the bisector with its centre on the extension of thetotal impedance line SG.

The diameters and centres of these circles are a function of the voltage ratio EG / ESand the total impedance, as shown in Figure 34. It is not always necessary to go intothe detail of plotting the circular characteristic to identify the loss of synchronism. Inmost cases, it is only necessary to simply draw the perpendicular bisector to the totalimpedance line to locate the point on the system where the swing will traverse whichis sufficiently accurate for relaying purposes.

It should be noted that the angle formed by the intersection of lines SL and GL on lineML is the angle of separation δ between the generator and system. During anunrecoverable power swing, δ oscillates between 0 and 360 degrees according to thepoints L and M on the bisector. There are several points of interest along line LM.The first is the point where the separation reaches 90 degrees. If we draw a circlewhose diameter is the total impedance, line GS, the intersection of the circle and lineLM will be the point where δ=90 degrees. If the swing locus does not go beyond thispoint the system will be able to regain synchronism. However, if the locus reaches120 degrees or more, the system is not likely to recover. When the impedance locusintersects the total impedance, line GS, the generator and system are 180 degree outof phase, which is known as the electrical centre or impedance centre of the system.


MiCOM P342, P343 Page 103/176

As the locus crosses this point and enters the left hand side of the line GS, thegenerator and system will become more in phase. A slip cycle has been completedwhen the locus reaches the point where the swing started.

Note that the following assumptions have been made in this simplified approach:

• EG/ ES is assumed to remain constant during the swing.

• Initial transients and effects of generator saliency are neglected.

• Transient changes in impedance due to a fault or clearance of fault havesubsided.

• Effect of regulator and governor are neglected.

2.22.3 Generator pole slipping characteristics

As noted previously, generator and system impedances have changed in the past fewdecades. In many instances, the electrical centre or impedance centre lies within thegenerator or step-up transformer. Also, for most machine loadings, the equivalentinternal machine voltage will be less than 1.0 per unit and so less than the equivalentsystem voltage. Therefore, the pole slipping characteristics viewed at the generatorterminals will generally follow the loss of synchronism characteristic where the voltageratio EG/ ES < 1 which is below the impedance centre. See the locus EG/ ES < 1 inFigure 34 for example.

In reality the impedance loci as viewed at the generator terminals may be distortedcompared with the ideal loci. The following discussion illustrates the impact on thepole slipping characteristic when other factors are taken into account.

2.22.3.1 What happens if EG / ES has different values less than one (1)?

For a given total impedance, as the voltage ratio decreases below one (1), the circlealso decreases in diameter and the centre moves closer to the origin. Therefore, adecreased internal voltage results in the impedance loci having a smaller diameter.The radius and circular centre calculations using the equation shown in Figure 34shows these trends.

During a fault, if the voltage regulator is out of service the internal machine voltagewill decay and will remain at the resulting lower level after the fault is cleared. If theeffects of the voltage regulator during a fault is included, the impedance locus circlesare larger in diameter but will still be in the generator zone.

2.22.3.2 What happens if different system impedances are applied?

System impedance also plays a part in the determination of the circle diameter andlocation. If the system impedance decreases, the locus decreases in diameter andmoves closer to the origin.

It should be noted that the impedance centre of the system is not a fixed point due tothe variation of system impedance under different operating conditions. Therefore,the impedance loci should be determined at the maximum and minimum systemsimpedances.

2.22.3.3 How to determine the generator reactance during a pole slipping condition?

Since the generator reactance plays a role in the determination of the pole slippingimpedance locus, it is crucial to use proper reactance values when we plot these loci.At zero slip XG is equal to the synchronous reactance (Xd), and at 100% slip XG is

equal to sub-transient reactance (X’’d). The impedance in a typical case has been


Page 104/176 MiCOM P342, P343

shown to be equal to the transient reactance X’d at 50% slip, and to 2X’d with a slipof 0.33%. As most slips are likely to be experienced at low asynchronous speedrunning, perhaps 1%, it is sufficient to take the value XG=2X’d when assessing poleslipping.

2.22.3.4 How to determine the slip rate of pole slipping?

The rate of slip between the generator and power system is a function of theaccelerating torque and inertia of the systems. In general, the slip rate can not beobtained analytically. It is recommended to determine the slip rate by transientstability studies where the angular excursion of the system is plotted versus time.Although the slip rate will not be constant during a pole slipping condition, it isreasonable to assume a constant for the first half slip cycle which is of interest to therelay. For the tandem generator, it is in the range of 250 to 400 degrees/sec. Whilstfor the cross compound units, the average initial slip will be 400 to 800 degrees/sec.

2.22.4 General requirements for pole slipping protection

Having got some ideas about the characteristics of pole slipping, general rules forpole slipping protection could be obtained as listed below:

• On the whole, the pole slipping protection must remain stable under all faultconditions and recoverable power swings other than a genuine non-recoverablepole slipping condition.

• For a particular loss of synchronism condition, if the impedance centre happens tolie in the generator/step-up transformer zone, it is recommended the generatorbe tripped without delay, preferably during the first half slip cycle of a loss ofsynchronism condition. If the centre lies outside of the zone, then the poleslipping relay should not trip immediately, but should allow time for tripping totake place at some other location external to the power station. Only if thisshould fail must the pole slipping protection respond in stage II, i.e. after a pre-setnumber of slips, to isolate the generator.

• In order to reduce the damage to the generator during a pole slip, it must reliablydetect the first and subsequent slips of a synchronous machine within a widerange (slipping frequency 0.1% to 10% of fn).

• The tripping should avoid the point where the generator and the system are 180degrees out-of-phase, when the currents reach the maximum value and subjectthe circuit breaker to a maximum recovery voltage during interruption.

• Since pole slipping is essentially a balanced three-phase phenomenon, only asingle phase element need be implemented in the protection relay.

2.22.5 Lenticular scheme

2.22.5.1 Characteristic

The P343 pole slipping characteristic consists of three parts as shown in the R/Xdiagram of Figure 35. The first part is the lenticular (lens) characteristic. The secondis a straight line referred to as the blinder that bisects the lens and divides theimpedance plane into the left and right halves. The third is a reactance line which isperpendicular to the blinder.

The inclination of the lens and the blinder, θ, is determined by the angle of the totalsystem impedance. The equivalent impedance of the system and the step-uptransformer determines the forward reach of the lens, ZA, whereas the generator’stransient reactance determines the reverse reach ZB. The width of the lens is varied


MiCOM P342, P343 Page 105/176

by the setting of the angle α. A reactance line, perpendicular to the axis of the lens,is used to distinguish whether the impedance centre of the swing is located in thepower system or in the generator. It is set by the value of Zc along the axis of thelens, as shown in Figure 35. The reactance line splits the lens into Zone 1 (below theline) and Zone 2 (above the line).

For the pole slipping protection element the minimum operating current is 2% Ιn andthe minimum voltage is 1 V for 100/120 and 4V for 380/480 V ratings. The poleslipping protection operates from the ΙA and VA current and voltage inputs to therelay.

Reactance Line

R

Lens

Blinder

ZA

ZB

X

θα

ZC

P1256ENa

Figure 35: Pole slipping protection using blinder and lenticular characteristic

2.22.5.2 Generating and motoring modes

When a generator is out of step with the system, the impedance locus is expected totraverse from right to left across the lens and the blinder. However, if the generator isrunning as a motor, as in the pumping mode of a pump storage generator, theimpedance locus is expected to swing from the left to the right. A setting is providedto determine whether the protection operates in a generating mode or in a motoringmode or both.

If the protection is running in the generating mode, the impedance is expected to beat the right hand side of the lens under normal load conditions. During a pole slipthe impedance locus traverses across the right half and the left half of the lens. Theminimum time spent in each half of the lens can be set with timers T1 for the righthand side and T2 for the left hand side. The relay registers a pole slipping cyclewhen the locus finally leaves the lens at the opposite end.

If the protection is running in the motoring mode, the impedance is expected to be atthe left hand side of the lens under normal load conditions. During a pole slip theimpedance locus traverses across the left half and the right half of the lens, againspending at least the time T1 and T2 respectively in each half and leaves the lens atthe opposite end.


Page 106/176 MiCOM P342, P343

2.22.6 Pole slipping protection operation

The pole slipping protection algorithm is executed 4 times per power system cycle toobtain accurate timing of the impedance locus traversing the lens.

2.22.6.1 State machine

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MiCOM P342, P343 Page 107/176

R1

Reactance Line

R

X

R2R3R4

R represents Region

Zone2

Zone1

Blinder

Lens

P1257ENa

Figure 37: Regions and zones definition (generating mode)

Note, that the regions shown in Figure 37 are independent of the reactance linealthough it is shown in the same diagram (zones are independent of the lens and theblinder).

In order to track the impedance locus under a pole slipping condition, a ‘StateMachine’ approach is adopted. There are 4 states ‘Idle’, ‘Start’, ‘Confirm’ and‘Detected’ used to describe the movement of the impedance locus. Each state hasone entrance and one or several exit terminals depending on the state. Exit terminalsfall into two categories: ‘normal exit’ and ‘abnormal exit’. There is only one ‘normalexit’ which leads to the next state when the impedance locus moves into the desiredregion. Unexpected impedance movement will result in a return to the ‘Idle’ State orwill be ignored depending on where the impedance stays.

• Idle: This is the normal state when the measured impedance is the normal loadimpedance. The impedance locus of any pole slip should start from here. In thisstate the ‘normal exit’ is when the measured impedance moves from R1 to R2.Timer 1, which is used to time the duration of the impedance locus remaining inR2, is started when this change is detected.

If the impedance locus moves to R4 and ‘Both’ is selected in the ‘Mode’ setting, a flag(Flag_Mode) indicating the generator operating mode is toggled to indicate‘Motoring’. Note, this does not cause a state transition, Refer to section 2.22.6.4 fordetails about the ‘Flag_Mode’.

In this state impedance locus changes to R3 will be ignored.

• Start: This is the state when the impedance locus stays inside R2. Normal exit istaken only if the impedance has stayed in R2 longer than the T1 time delay andmoves to R3. Three actions are carried out along with this transition: check theoperating status of the reactance line, start Timer 2 and reset Timer 1. Thepurpose of checking the operating status of the reactance line at this point is todecide whether the pole slip belongs to Zone1 or Zone2. A flag (Flag_Zone1) islatched if Zone1 picks up, which is used later on to differentiate whether countersare incremented for pole slips in zone1 or zone2. Theoretically, this flag isgenerated at the point where the impedance locus intersects the blinder, which is


Page 108/176 MiCOM P342, P343

called the electrical centre. Timer2 is used to time the duration of the impedancelocus remaining in R3;

If the impedance moves to R1 or R4 or moves to R3 but stays in R2 less than T1,the state machine will be reset to the ‘Idle’ state. Timer 1 is reset when theimpedance leaves R2 via these abnormal exits. Besides pole slipping, a stablepower swing or fault occurrence could enter this state as well. The state machineis designed to differentiate these conditions.

• Confirm: This state is reached when the impedance has crossed the blinder andarrived at Region3. Further confirmation is required to see if the impedance staysfor at least time T2 and is bound to leave for R4. Otherwise, an abnormal exitwill reset the state machine to the ‘Idle’ state. Actions on abnormal transitioninclude resetting Flag_Zone1 and Timer 2. Note, that as soon as the impedancelocus leaves the lens through the normal exit counters of different zones will beupdated, depending on the Flag_Zone1 and if the pole slip has completed thepre-set slip cycles setting a trip signal is given. If Flag_Zone1 is set then the Zone1 counter (C1) will be incremented. Zone 2 is the backup pole slipping stage andso all pole slips increment the Zone2 counter (C2).

The Reset_Timer and reset Timer 2 are started when the normal transition occurs.The Reset_Timer is started only when the first pole slip is detected and will be reset inits time delay (see Reset_Timer time out actions in the state machine diagram).

• Detected: This is the stage where the impedance locus has to complete it’s fullcycle although the counter is updated in the previous confirm stage. Abnormalmovements of the impedance locus in this stage will be ignored and this state iskept until the impedance moves to R1 indicating completion of a pole slip cycle.If a trip signal has not been given for this pole slip, only the Start_Signals andFlag_Zone1 are reset in preparation for the next pole slip cycle. However, if a tripsignal has been issued, then the Trip_Signals and the counters are both reset.

In general, once the measured impedance has traversed all the ‘States’ in the normalexit sequence, a pole slip is confirmed. For a stable power swing or fault conditionthe measured impedance will not satisfy all the exit transition criteria.

The ‘State Machine’ diagram has been simplified to present an overview of how todetect pole slipping. There are also several supporting protection functions which areexplained in the following sections.


MiCOM P342, P343 Page 109/176

2.22.6.2 Protection functions and logic structure

poleslz_Zone1Pu( )

&

&

&

&

poleslz_BlinderPu()(Generating Mode - Pick-up zone left of blinder;Motoring Mode - Pick-up zone right of blinder)

poleslz_LensPu()

R1

R2

R3

R4

Pole Slipping State Machine

GenuinePole Slipping

& Zone1Count++

Zone2Count++

Zone 1 Trip

Zone 2 Trip

IAi,IAj

VAi, VAj

poleslz_RegionCal

Zone1 Start

Zone2 Start

Flag_Zone1

P1258ENa

Figure 38: Logic structure of pole slipping module

There are several protection functions called in sequence in the pole slippingdetection, as shown in the above diagram, they are

• poleslz_Zone1Pu

• poleslz_LensPu

• poleslz_BlinderPu

• poleslz_RegionCal

Function poleslz_Zone1Pu(), poleslz_LensPu() and Poleslz_BlinderPu() calculatewhether the Reactance Line, Lens and Blinder characteristics have picked uprespectively. At the end of each function, DDBs associated with each characteristicare mapped according to the elements operating status. Outputs frompoleslz_LensPu() and Poleslz_BlinderPu() feed into the poleslz_RegionCal() todetermine in which ‘Region’ the locus is present. After the region and zone havebeen determined the state machine can be evaluated.

For the purpose of discriminating the pole slipping zone, Zone1 or Zone2, it isimportant to check the result of poleslz_Zone1Pu() when the impedance locus leavesthe ‘Start’ state by the ‘normal exit’. A flag is latched if Zone1 picks up, which is usedto identify the pole slipping zone later on.


Page 110/176 MiCOM P342, P343

2.22.6.3 Motoring mode

When the ‘pole slip mode’ setting is set to ‘motoring’ the protection algorithm isswitched to motoring mode. Motoring mode is essentially the same for generatingmode except that the pick-up zone for the blinder is changed from the left hand sideto the right hand side, as shown in Figure 39. This requires changes to the blinderalgorithm in poleslz_BlinderPu().

This automatically changes the region definition on the impedance plane. Forexample, under normal motoring conditions, both the blinder, which picks up fromthe left hand side for motoring, and the lens will not be picked up. Therefore, thepoleslz_RegionCal() will output a region number R1.

R4

Reactance Line

R

X

R3R2R1

R represents Region

Zone2

Zone1

Blinder

Lens

Pick-Up Zone

P1257ENb

Figure 39: Regions and zones definition (motoring mode)

2.22.6.4 Generating and motoring mode

For a pump storage generator, its operation can switch from generating mode tomotoring mode and vice versa. Therefore, a facility is provided for the protection todetect the normal running mode of the machine (generating or motoring) and toperform pole slipping detection in either mode.

This facility is enabled when the ‘pole slip mode’ setting is set to ‘Both’.

Also, when a generator is running at low load, <30% load, due to the presence ofheavy system damping during a fault the generator can slow down and result in amotor like slip (negative slip). To detect pole slips for this condition then the ‘pole slipmode’ should be set to ‘Both’.

In the state machine, a flag called ‘Flag_Mode’ is used to deal with the modechange. During the initialisation, the flag is set to ‘generating’, with the pick up zoneof the blinder on the left-hand side. If the impedance traverses the blinder from R1 toR4 in the ‘Idle’ state, the ‘Flag_Mode’ is toggled to ‘Motoring’. This causes theblinder pick-up zone to change from the left-hand side to right-hand side, thusautomatically redefining the regions numbering on the impedance plane, asdiscussed previously. Subsequent crossing of the blinder from R1 to R4 in the ‘Idle’mode will cause the ‘Flag_Mode’ to toggle, thus tracking the normal running


MiCOM P342, P343 Page 111/176

operation of the pump storage generator, irrespective of whether it is in generating ormotoring mode.

2.22.7 Setting guidelines for pole slipping protection

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Figure 40: Lenticular scheme characteristic

1. Forward reach and reverse reach ZA, ZB.

As noted previously, the best setting for the lens is when the point ZA and ZBcoincide with the system impedance (ZT+ZS) and the generator reactance (XG),see Figure 34. The angle α of the lens corresponds in this case to the angle αbetween the emfs EG and ES at which the impedance enters the lens, seeFigure 34.

As most slips are likely to be experienced at low asynchronous speed running,perhaps 1%, it is sufficient to take the value XG=2X’d when assessing poleslipping, see section 2.22.3.3.

Where the values of ZS and the generator reactance XG vary, ZAand ZB shouldbe set according to the corresponding maximum values.

Large differences between EG and ES, see Figure 34 and sections 2.22.3.1,can cause the loci of impedance circle to becomes smaller and smaller.Therefore, there is the possibility of the circular loci of the pole slip crossing theblinder and lens twice with large ZA and ZB settings producing a long lens.


Page 112/176 MiCOM P342, P343

However, the state machine logic will prevent 2 pole slips from being countedfor this condition and so there is no maximum limit to the ZA and ZB settings.

2. Lens inclination θ

The inclination of the lens should be kept consistent with the system impedanceangle, vector GS in Figure 34.

3. angle α.

The width of the lens is proportional to the angle α. Two factors should beconsidered to determine the proper angle α:

• Under all conditions, the load impedance remains safely outside the lens.

• The tripping point, limited by the left side of the lens for generating shouldbe the point when the angular separation between the system and thegenerator is small. Although CBs are rated to break twice the systemvoltage i.e. when the machines are in anti-phase, it is recommended thatthe trip command is issued at the smallest phase shift possible. For thisreason the angle α should be chosen as small as possible (setting range is

90o to 150o).

The construction of the lens can be seen in Figure 40, ZR is the maximum width ofhalf the lens. The minimum resistive component of the load should be at least 130%of the reach of the lens, ZR, in the transverse direction. ZR can be determined bycalculation as follows:

ZR = (ZA + ZB) /2 x tan (90o - α/2)

For a given minimal load resistance RLmin the minimum permissible setting of α is:

αmin = 180o – 2 x tan-1 (1.54 x RLmin / ( ZA + ZB))

RLmin is then at least 1.3 ZR

Note: The minimum relay setting for α is 90o as this defines the largestsize of the characteristic, a circle.


MiCOM P342, P343 Page 113/176

R4

Reactance Line

R

X

R3R2R1

R represents Region

Zone2

Zone1

Blinder

Lens

Pick-Up Zone

P1256ENb

Figure 41: Pole slipping protection using blinder and lenticular characteristic

4. Reactance setting

The value of Zc

The value of Zc determines the distance of the reactance line from the origin.The reactance line provides a means of discrimination of the pole slippingwithin the generator or power swing within the HV power system. It should beset to encompass the step-up transformer and generator reactance withsufficient margin.

5. Pole slipping counters

Counters are available for both Zone1 and Zone2 to count the number of poleslip cycles before the trip signal is issued. A user-settable reset timer isavailable to reset the counters when the pole slipping condition is cleared byother relays in the system.

6. Timers T1 and T2

During a pole slip the impedance locus traverses across the lens spending atleast time T1 in region 2 and time T2 in region 3, see Figures 37 and 39. Fromsimulation testing it has been proved that pole slips up to 10 Hz can be

detected with an angle α setting of 120o and time settings of 15 ms for T1 andT2. Therefore, it is recommended that T1 and T2 be set to 15 ms.

7. Reset timer

The reset time should be set longer than the maximum expected time for themachine to go through the set number of pole slips for zone1 or zone2 . Thereset time is required to reset the counters for pole slips that are cleared byexternal protection. For example if the Z2 counter is set to operate after 2 poleslips in the power system and after a count of 1 the condition is cleared byother protection in the system the counters will need to be reset to zero.


Page 114/176 MiCOM P342, P343

8. Pole slip mode

When a generator is out of step with the system, the impedance locus isexpected to traverse from right to left across the lens and the blinder. However,if the generator is running as a motor, as in the pumping mode of a pumpstorage generator, the impedance locus is expected to swing from the left to theright. A pole slip mode setting is provided to determine whether the protectionoperates in a ‘generating’ mode or in a ‘motoring’ mode or ‘both’.

For a pump storage generator, its operation can switch from generating modeto motoring mode and vice versa. Therefore, a facility is provided for theprotection to detect the normal running mode of the machine, generating ormotoring and to perform pole slipping detection in either mode. This facility isenabled when the pole slip mode setting is set to ‘Both’.

Also, when a generator is running at low load, <30% load, due to the presenceof heavy system damping during a fault the generator can slow down andresult in a motor like slip (negative slip). To detect pole slips for low load andnormal load conditions then the pole slip mode should be set to ‘Both’.

2.22.7.1 Settings


Min MaxStep Size

GROUP 1 POLE SLIPPING

Pslip Function Enabled Disabled, Enabled

Pole Slip Mode Generating Motoring, Generating, Both

Pslip Za Forward 100/Ιn Ω

0.5/Ιn Ω

(Vn=100/120V)

2/Ιn Ω

(Vn=380/480V)

350/Ιn Ω

(Vn=100/120V)

1400/Ιn Ω

(Vn=380/480V)

0.5/Ιn Ω

(Vn=100/120V)

2/Ιn Ω

(Vn=380/480V)

Pslip Zb Reverse 150/In Ω

0.5/Ιn Ω

(Vn=100/120V)

2/Ιn Ω

(Vn=380/480V)

350/Ιn Ω

(Vn=100/120V)

1400/Ιn Ω

(Vn=380/480V)

0.5/Ιn Ω

(Vn=100/120V)

2/Ιn Ω

(Vn=380/480V)

Lens Angle 120° 90° 150° 1°

PSlip Timer T1 0.015 s 0 s 1 s 0.005 s

PSlip Timer T2 0.015 s 0 s 1 s 0.005 s

Blinder Angle 75° 20° 90° 1°

PSlip Zc 50/In Ω

0.5/Ιn Ω

(Vn=100/120V)

2/Ιn Ω

(Vn=380/480V)

350/Ιn Ω

(Vn=100/120V)

1400/Ιn Ω

(Vn=380/480V)

0.5/Ιn Ω

(Vn=100/120V)

2/Ιn Ω

(Vn=380/480V)

Zone1 Slip Count 1 1 20 1

Zone2 Slip Count 2 1 20 1

PSlip Reset Time 30 s 0 s 100 s 0.01 s


MiCOM P342, P343 Page 115/176

2.22.7.2 DDB output

Apart from the Zone1 and Zone2 start and trip signals, each measuring element alsooutputs its ‘status’ onto the DDB. These signals can be used during commissioningtesting to determine the shape and the accuracy of the characteristics.

DDB Name Description

DDB 497 PSlipz Z1 Trip Pole slipping tripped in Zone1

DDB 498 PSlipz Z2 Trip Pole slipping tripped in Zone2

DDB 645 PSlipz Z1 Start Pole slipping detected in Zone1

DDB 646 PSlipz Z2 Start Pole slipping detected in Zone2

DDB 647 PSlipz LensStart Measured Impedance is within the Lens

DDB 648 Pslipz BlindStrt Impedance lies left hand side of Blinder

DDB 649 PSlipz ReactStrt Impedance lies in Zone 1 distinguished by Reactanceline

2.22.7.3 Pole slipping setting examples

The impedances in the P343 can be set in terms of primary or secondary quantities,however, for simplicity all the impedance values used in the examples are in primaryquantities.

2.22.8 Example calculation

P1259ENa

X1 = 0.2360 MVAXT = 0.15

360 MVAX’d = 0.2518 kV

Figure 42: Example system configuration

Data of the generator and step up transformer:

Base power Pn = 360 MVA

Base voltage Vn = 18000 kV

Min load resistance RLmin = 0.77 Ω

System impedance angle ≥ 80°

Generator impedance 0.25 pu

Transformer impedance 0.15 pu

System impedance 0.2 pu


Page 116/176 MiCOM P342, P343

The location of the pole slipping relay is at the generator terminals. The direction ofZA and Zc is towards the step up transformer and the rest of the system. Thereactance line is required to distinguish between power swings with electrical centreswithin the generator/transformer zone and those outside.

The base impedance is

Zbase = Vn2/Pn = 182/360 = 0.9 Ω

ZA = (XT + X1) Zbase = (0.15+0.2) x 0.9 = 0.315 Ω

ZB = 2X’d x Zbase = 2 x 0.25 x 0.9= 0.45 Ω

Zc is set to 90% of the transformer reactance

Zc = 0.9 x (XT) Zbase = 0.9 x 0.15 x 0.9 = 0.122 Ω

The minimum suitable angle α which defines the lens limit in relation to the minimumload resistance is

αmin = 180° – 2 x tan-1 (1.54 x RLmin / ( ZA + ZB))

αmin = 180° – 2 x tan-1 (1.54 x 0.77 / ( 0.315 + 0.45))

αmin = 65.7o

The minimum setting for α on the relay is 90° so this is the setting used.

T1 and T2 are set to 15 ms and θ is set to the system impedance angle of 80°

2.23 Thermal overload protection

2.23.1 Introduction

Overloads can result in stator temperature rises which exceed the thermal limit of thewinding insulation. Empirical results suggest that the life of insulation isapproximately halved for each 10°C rise in temperature above the rated value.However, the life of insulation is not wholly dependent upon the rise in temperaturebut on the time the insulation is maintained at this elevated temperature. Due to therelatively large heat storage capacity of an electrical machine, infrequent overloads ofshort duration may not damage the machine. However, sustained overloads of a fewpercent may result in premature ageing and failure of insulation.

The physical and electrical complexity of generator construction result in a complexthermal relationship. It is not therefore possible to create an accurate mathematicalmodel of the true thermal characteristics of the machine.

However, if a generator is considered to be a homogeneous body, developing heatinternally at a constant rate and dissipating heat at a rate directly proportional to itstemperature rise, it can be shown that the temperature at any instant is given by:

T = Tmax (1-e-t/τ)

Where

Tmax = final steady state temperature

τ = heating time constant

This assumes a thermal equilibrium in the form:

Heat developed = Heat stored + Heat dissipated


MiCOM P342, P343 Page 117/176

Temperature rise is proportional to the current squared:

T = K ΙR2 (1-e-t/τ)

T = Tmax = K ΙR2 if t = ∞

Where

ΙR = the continuous current level which would produce a temperature Tmax in the generator

For an overload current of ‘Ι’ the temperature is given by:

T = KΙ2 (1-e-t/τ)

For a machine not to exceed Tmax, the rated temperature, then the time ‘t’ for whichthe machine can withstand the current ‘Ι’ can be shown to be given by:

Tmax = K ΙR2 = KΙ2 (1-e-t/τ)

t = τ. Loge (1/(1-(ΙR/Ι)2))

An overload protection element should therefore satisfy the above relationship. Thevalue of ΙR may be the full load current or a percentage of it depending on the design.

As previously stated it is an oversimplification to regard a generator as anhomogeneous body. The temperature rise of different parts or even of various pointsin the same part may be very uneven. However, it is reasonable to consider that thecurrent-time relationship follows an inverse characteristic. A more accuraterepresentation of the thermal state of the machine can be obtained through the useof temperature monitoring devices (RTDs) which target specific areas. Also, for shorttime overloads the application of RTDs and overcurrent protection can provide betterprotection. Note, that the thermal model does not compensate for the effects ofambient temperature change. So if there is an unusually high ambient temperatureor if the machine cooling is blocked RTDs will also provide better protection.

2.23.2 Thermal replica

The P343 relay models the time-current thermal characteristic of a generator byinternally generating a thermal replica of the machine. The thermal overloadprotection can be selectively enabled or disabled. The positive and negativesequence components of the generator current are measured independently and arecombined together to form an equivalent current, Ιeq, which is supplied to the replicacircuit. The heating effect in the thermal replica is produced by Ιeq

2 and thereforetakes into account the heating effect due to both positive and negative sequencecomponents of current.

Unbalanced phase currents will cause additional rotor heating that may not beaccounted for by some thermal protection relays based on the measured current only.Unbalanced loading results in the flow of positive and negative sequence currentcomponents. Load unbalance can arise as a result of single phase loading, non-linear loads (involving power electronics or arc furnaces, etc.), uncleared or repetitiveasymmetric faults, fuse operation, single-pole tripping and reclosing on transmissionsystems, broken overhead line conductors and asymmetric failures of switchingdevices. Any negative phase sequence component of stator current will set up areverse-rotating component of stator flux that passes the rotor at twice synchronousspeed. Such a flux component will induce double frequency eddy currents in therotor, which can cause overheating of the rotor body, main rotor windings, damperwindings etc. This extra heating is not accounted for in the thermal limit curvessupplied by the generator manufacturer as these curves assume positive sequence


Page 118/176 MiCOM P342, P343

currents only that come from a perfectly balanced supply and generator design. TheP340 thermal model may be biased to reflect the additional heating that is caused bynegative sequence current when the machine is running. This biasing is done bycreating an equivalent heating current rather than simply using the phase current.The M factor is a constant that relates negative sequence rotor resistance to positivesequence rotor resistance. If an M factor of 0 is used the unbalance biasing isdisabled and the overload curve will time out against the measured generatorpositive sequence current. Note, the P340 also includes a negative sequenceovercurrent protection function based on Ι2

2t specifically for thermal protection of therotor.

The equivalent current for operation of the overload protection is in accordance withthe following expression:

Ιeq = √(Ι12 + MΙ2

2)

where

Ι1 = positive sequence current

Ι2 = negative sequence current

M = a user settable constant proportional to the thermal capacity of themachine

As previously described, the temperature of a generator will rise exponentially withincreasing current. Similarly, when the current decreases, the temperature alsodecreases in a similar manner. Therefore, in order to achieve close sustainedoverload protection, the P343 relay incorporates a wide range of thermal timeconstants for heating and cooling.

Furthermore, the thermal withstand capability of the generator is affected by heatingin the winding prior to the overload. The thermal replica is designed to take accountthe extremes of zero pre-fault current, known as the ‘cold’ condition and the full ratedpre-fault current, known as the ‘hot’ condition. With no pre-fault current the relay willbe operating on the ‘cold curve’. When a generator is or has been running at fullload prior to an overload the ‘hot curve’ is applicable. Therefore, during normaloperation the relay will be operating between these two limits.

The following equation is used to calculate the trip time for a given current. Note thatthe relay will trip at a value corresponding to 100% of it’s thermal state.

The thermal time characteristic is given by:

t = τ loge (Ιeq2 – ΙP

2)/(Ιeq2 – (Thermal Ι>)2

where

t = time to trip, following application of the overload current, Ι

τ = heating time constant of the protected plant

Ιeq = equivalent current

Thermal Ι> = relay setting current

ΙP = steady state pre-load current before application of the overload

The time to trip varies depending on the load current carried before application of theoverload, i.e. whether the overload was applied from 'hot” or “cold”.


MiCOM P342, P343 Page 119/176

The thermal time constant characteristic may be rewritten as:

exp(–t/τ) = (θ – 1) / (θ – θ p)

where

θ = Ιeq2/(Thermal Ι>)2

and

θp = Ιp2/ (Thermal Ι>)2

where θ is the thermal state and is θp the prefault thermal state.

Note, that the thermal model does not compensate for the effects of ambienttemperature change.

t = τ. Loge (K2-A2/(K2-1))

Where

K = Ιeq/Thermal Ι>

A = ΙP /Thermal Ι>

The Thermal state of the machine can be viewed in the “Thermal Overload” cell inthe “MEASUREMENTS 3” column. The thermal state can be reset by selecting ‘Yes’ inthe “Reset ThermalO/L” cell in “Measurements 3”. Alternatively the thermal state canbe reset by energising DDB 390 “Reset ThermalO/L” via the relay PSL.

A DDB signal “Thermal O/L Trip” is also available to indicate tripping of the element(DDB 499). A further DDB signal “Thermal Alarm” is generated from the thermalalarm stage (DDB 399). The state of the DDB signal can be programmed to beviewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.

Setting ranges for the thermal overload element are shown in the following table:


Min MaxStep Size

GROUP 1:THERMAL OVERLOAD

ΙThermal Enabled Disabled, Enabled

Thermal Ι> 1.2 Ιn A 0.5 Ιn A 2.5 Ιn A 0.01 Ιn A

Thermal Alarm 90% 20% 100% 1%

T-heating 60 mins 1 min 200 mins 1 min

T-cooling 60 mins 1 min 200 mins 1 min

M Factor 0 0 10 1

2.23.3 Setting guidelines

The current setting is calculated as:

Thermal Trip = Permissible continuous loading of the plant item/CT ratio.

The heating thermal time constant should be chosen so that the overload curve isalways below the thermal limits provided by the manufacturer. This will ensure thatthe machine is tripped before the thermal limit is reached. The relay setting,"T-heating", is in minutes.


Page 120/176 MiCOM P342, P343

The cooling thermal time constant should be provided by the manufacturer.However, unless otherwise specified, the cooling time constant, "T-cooling", settingshould be set equal to the main heating time constant setting, T-heating”. Thecooling time constant is applied when the machine is running and the load current isdecreasing. It is therefore practical to assume the cooling time constant is similar tothe heating time constant if information is not available from the manufacturer.When the machine is not turning the machine will normally cool significantly slowerthan when the rotor is turning. The relay setting, "T-cooling", is in minutes.

An alarm can be raised on reaching a thermal state corresponding to a percentageof the trip threshold. A typical setting might be "Thermal Alarm" = 70% of thermalcapacity. The thermal alarm could also be used to prevent restarting of the generatoruntil the alarm level resets. For this application a typical setting may be 20%.

The “M Factor” is used to increase the influence of negative sequence current on thethermal replica protection due to unbalanced currents. If it is required to account forthe heating effect of unbalanced currents then this factor should be set equal to theratio of negative phase sequence rotor resistance to positive sequence rotor resistanceat rated speed. When an exact setting can not be calculated a setting of 3 should beused. This is a typical setting and will suffice for the majority of applications. If an Mfactor of 0 is used the unbalance biasing is disabled and the overload curve will timeout against the measured generator positive sequence current. Note, the extraheating caused by unbalanced phase currents is not accounted for in the thermallimit curves supplied by the generator manufacturer as these curves assume positivesequence currents only that come from a perfectly balanced supply and generatordesign, so the default setting is 0.

2.24 Circuit breaker failure protection

Following inception of a fault one or more main protection devices will operate andissue 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 not beeninterrupted following a set time delay from circuit breaker trip initiation, breakerfailure protection (CBF) will operate.

CBF operation can be used to back-trip 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.

2.24.1 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 breaker opens toisolate the fault. If breaker opening is not detected, ‘CB Fail 1 Timer’ times outand closes an output contact assigned to breaker fail (using the programmablescheme logic). This contact is used to backtrip upstream switchgear, generallytripping all infeeds connected to the same busbar section.


MiCOM P342, P343 Page 121/176

• A re-tripping scheme, plus delayed backtripping. Here, ‘CB Fail 1 Timer’ is usedto route a trip to a second trip circuit of the same circuit breaker. This requiresduplicated circuit breaker trip coils, and is known as re-tripping. Should re-tripping fail to open the circuit breaker, a backtrip may be issued following anadditional time delay. The backtrip uses ‘CB Fail 2 Timer’, which is also started atthe instant of the initial protection element trip.

CBF elements ‘CB Fail 1 Timer’ and ‘CB Fail 2 Timer’ can be configured to operatefor trips triggered by protection elements within the relay or via an external protectiontrip. The latter is acheived by allocating one of the relay opto-isolated inputs to‘External Trip’ using the programmable scheme logic.

2.24.2 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 todefinitely indicate that the breaker has tripped.

• Where a circuit breaker has started to open but has become jammed. This mayresult in continued arcing at the primary contacts, with an additional arcingresistance in the fault current path. Should this resistance severely limit faultcurrent, the initiating protection element may reset. Thus, reset of the elementmay not give a reliable indication that the circuit breaker has opened fully.

For any protection function requiring current to operate, the relay uses operation ofundercurrent elements (Ι<) to detect that the necessary circuit breaker poles havetripped and reset the CB fail timers. However, the undercurrent elements may not bereliable methods of resetting circuit breaker fail in all applications. For example:

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

Resetting of the CBF is possible from a breaker open indication (from the relay’s poledead logic) or from a protection reset. In these cases resetting is only allowedprovided the undercurrent elements have also reset. The resetting options aresummarised in the following table:


Page 122/176 MiCOM P342, P343

Initiation (Menu Selectable) CB Fail Timer Reset Mechanism

Current based protection -(e.g. 50/51/46/21/87..)

The resetting mechanism is fixed.[ΙA< operates] &[ΙB< operates] &[ΙC< operates] &[ΙN< operates]

Sensitive earth fault elementThe resetting mechanism is fixed.[ΙSEF< operates]

Non-current based protection(e.g. 27/59/81/32L..)

Three options are available.The user can select from the followingoptions.[All Ι< and ΙN< elements operate][Protection element reset] AND[All Ι< and ΙN< elements operate]CB open (all 3 poles) AND[All Ι< and ΙN< elements operate]

External protection

Three options are available. The user canselect any or all of the options.[All Ι< and ΙN< elements operate][External trip reset] AND[All Ι< and ΙN< elements operate]CB open (all 3 poles) AND[All Ι< and ΙN<elements operate]

The selection in the relay menu is grouped as follows:


Min MaxStep Size

CB FAIL + Ι<

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

CBF Non Ι Reset CB Open & Ι< Ι< Only, CB Open & Ι<, Prot Reset & Ι<

CBF Ext Reset CB Open & Ι< Ι< Only, CB Open & Ι<, Prot Reset & Ι<

Under Current Sub-Heading

Ι< Current Set 0.1Ιn 0.02Ιn 3.2Ιn 0.01Ιn

ΙN< Current Set 0.1Ιn 0.02Ιn 3.2Ιn 0.01Ιn

ΙSEF< Current 0.02Ιn 0.001Ιn 0.8Ιn 0.00025Ιn

Blocked O/C Sub-Heading

Remove Ι> Start Disabled Enabled, Disabled

Remove ΙN> Start Disabled Enabled, Disabled

Ι< Current Input IA-1, IB-1, IC-1 IA-1, IB-1, IC-1 / IA-2, IB-2, IC-2


MiCOM P342, P343 Page 123/176

The ‘Remove Ι> Start‘ and ‘Remove ΙN> Start‘ settings are used to remove startsissued from the overcurrent and earth elements respectively following a breaker failtime out (DDB 628 Ι> Block Start, DDB 629 ΙN/SEF > Blk Start). The start isremoved when the cell is set to Enabled. This can be used to remove a blockingsignal from an upstream relay to back trip and clear the fault.

2.24.3 Typical settings

2.24.3.1 Breaker fail timer settings

Typical timer settings to use are as follows:

CB Fail Reset Mechanism tBF Time Delay Typical Delay for 2½Cycle Circuit Breaker

Initiating element reset

CB interrupting time +element reset time (max.)+ error in tBF timer +safety margin

50 + 50 + 10 + 50 =160 ms

CB open

CB auxiliary contactsopening/closing time(max) + error in tBFtimer + safety margin

50 + 10 + 50 =110 ms

Undercurrent elements

CB interrupting time+undercurrent element(max.) + safety marginoperating time

50 + 12 + 50 =112 ms

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 2½ cycle circuit breaker. Note thatwhere auxiliary tripping relays are used, an additional 10 – 15 ms must be added toallow for trip relay operation.

2.24.4 Breaker fail undercurrent settings

The phase undercurrent settings (Ι<) must be set less than load current, to ensure thatΙ< operation indicates that the circuit breaker pole is open. A typical setting foroverhead line or cable circuits is 20% Ιn, with 5% Ιn common for generator circuitbreaker CBF.

The sensitive earth fault protection (SEF) and standby earth fault (SBEF) undercurrentelements must be set less than the respective trip setting, typically as follows:

ΙSEF< = (ΙSEF> trip) / 2

ΙN< = (ΙN> trip) / 2

For generator applications the undercurrent elements should be measuring currentfrom CTs on the terminal side of the generator. This is because for an internal faulton the generator after the CB has tripped the generator will still be supplying somefault current which will be seen by undercurrent elements measuring current from CTson the neutral side of the generator. This could thus give false indication of abreaker fail condition.


Page 124/176 MiCOM P342, P343

The voltage dependent overcurrent protection and underimpedance protection usedfor back-up protection of system faults are usually connected to the neutral side CTsso that the generator is in the zone of protection. These protection functions use theIA, IB, IC current inputs in the P343. Therefore, if the IA, IB, IC inputs are connectedto neutral side CTs then the IA-2, IB-2, IC-2 inputs should be selected for theundercurrent elements using the setting ‘I< Current Input - IA-1, IB-1, IC-1/ IA-2,IB-2, IC-2’.

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Figure 43: CB fail logic

2.25 Breaker flashover protection

Prior to generator synchronisation, or just following generator tripping, where theprotected generator could be slipping with respect to a power system, it is possible toestablish at least twice rated phase-neutral voltage across the generator circuitbreaker. An even higher voltage might briefly be established just after generatortripping for prime mover failure, where the pre-failure level of excitation might bemaintained until AVR action takes place. Whilst generator circuit breakers must bedesigned to handle such situations, the probability of breaker interrupter breakdownor breakdown of open terminal switch gear insulators is increased and such failureshave occurred.


MiCOM P342, P343 Page 125/176

This mode of breaker failure is most likely to occur on one phase initially and can bedetected by a neutral current measuring element. If the generator is directlyconnected to the power system, the second stage of stator earth fault protection(“ΙN>2 ...”) could be applied as an instantaneous element by setting the time delay“ΙN>2 TimeDelay” to 0s, to quickly detect the flashover. To prevent loss ofco-ordination this stage must be blocked when the circuit breaker is closed. This canbe programmed by correct configuration of the programmable scheme logic and canbe integrated into the circuit breaker fail logic, as shown in Figure 44.

Where the machine is connected to the system via a step-up transformer a similarscheme can be arranged. The P340 relay standby earth fault protection element canbe connected to measure the transformer HV earth fault current to provide thebreaker flashover protection, via suitable scheme logic. The machine earth faultprotection can be provided by the P340 sensitive earth fault protection element, asshown in Figure 44.

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Page 126/176 MiCOM P342, P343

2.26 Blocked overcurrent protection

Blocked 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, as therelay 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 fast actingovercurrent elements on the incoming feeders to a substation which are thenarranged to be blocked by start contacts from the relays protecting the outgoingfeeders. The fast acting element is thus allowed to trip for a fault condition on thebusbar but is stable for external feeder faults by means of the blocking signal. Thistype of scheme therefore provides much reduced fault clearance times for busbarfaults than would be the case with conventional time graded overcurrent protection.The availability of multiple overcurrent and earth fault stages means that back-uptime graded overcurrent protection is also provided. This is shown in Figures 46aand 46b.

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Figure 46a: Simple busbar blocking scheme (single incomer)


MiCOM P342, P343 Page 127/176

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The P140/P340 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. Eachstage is also capable of being blocked by being programmed to the relevant opto-isolated input.

Note that the P340 relays provide a 50V field supply for powering the opto-inputs.Hence, in the unlikely event of the faulure of this supply, blocking of that relay wouldnot be possible. For this reason, the field supply is supervised and if a failure isdetected, it is possible, via the relays programmable scheme logic, to provide anoutput alarm contact. This contact can then be used to signal an alarm within thesubstation. Alternatively, the relays scheme logic could be arranged to block any ofthe overcurrent/earth fault stages that would operate non-discriminatively due to theblocking signal failure.

For further guidance on the use of blocked overcurrent schemes refer to AREVA T&D.

2.27 Current loop inputs and outputs

2.27.1 Current loop inputs

Four analogue (or current loop) inputs are provided for transducers with ranges of 0-1mA, 0-10mA, 0-20mA or 4-20mA. The analogue inputs can be used for varioustransducers such as vibration monitors, tachometers and pressure transducers.Associated with each input there are two protection stages, one for alarm and one fortrip. Each stage can be individually enabled or disabled and each stage has adefinite time delay setting. The Alarm and Trip stages can be set for operation whenthe input value falls below the Alarm/Trip threshold ‘Under’ or when the input currentis above the input value ‘Over’. The sample interval is nominally 50ms per input.

The relationship between the transducer measuring range and the current inputrange is linear. The maximum and minimum settings correspond to the limits of thecurrent input range. This relationship is shown in Figure 47.


Page 128/176 MiCOM P342, P343

Figure 47 also shows the relationship between the measured current and theanalogue to digital conversion (ADC) count. The hardware design allows for over-ranging, with the maximum ADC count (4095 for a 12-bit ADC) corresponding to1.0836mA for the 0-1mA range, and 22.7556mA for the 0-10mA, 0-20mA and4-20mA ranges. The relay will therefore continue to measure and display valuesbeyond the Maximum setting, within its numbering capability (-9999 to 9999).

Minimum

Maximum

Minimum

Maximum

0mA

0 4095

ADCCount

22.7556mA20mACurrent I/P

0mA

0 4095

ADCCount

22.7556mA20mA

Minimum

Maximum

Current I/P4mA

1.0836mA 0mA

0 4095

ADCCount

22.7556mA

Minimum

Maximum

Current I/P10mA

0-10mA

0-20mA 4-20mA

TransducerValue

TransducerValue

TransducerValue

0mA

0 4095

ADCCount

1mACurrent I/P

0-1mA

TransducerValue

P1417ENa

Figure 47: Relationship between the transducer measuring quantity and the current input range

Note, if the Maximum is set less than the Minimum, the slopes of the graphs will benegative. This is because the mathematical relationship remains the sameirrespective of how Maximum and Minimum are set, e.g., for 0-1mA range,Maximum always corresponds to 1mA and Minimum corresponds to 0mA.

Power-on diagnostics and continuous self-checking are provided for the hardwareassociated with the current loop inputs. When a failure is detected, the protectionassociated with all the current loop inputs is disabled and a single alarm signal (CLCard I/P Fail, DDB 320) is set and an alarm (CL Card I/P Fail) is raised. Amaintenance record with an error code is also recorded with additional details aboutthe type of failure.

For the 4-20mA input range, a current level below 4mA indicates that there is a faultwith the transducer or the wiring. An instantaneous under current alarm element isavailable, with a setting range from 0 to 4mA. This element controls an output signal(CLI1/2/3/4 I< Fail Alm, DDB 326-329) which can be mapped to a user definedalarm if required.

Hysteresis is implemented for each protection element. For ‘Over’ protection, thedrop-off/pick-up ratio is 95%, for ‘Under’ protection, the ratio is 105%.


MiCOM P342, P343 Page 129/176

Each current loop input can be blocked by energising the relevant DDB signal via thePSL, (CL Input 1/2/3/4 Blk, DDB 393-396). If a current loop input is blocked theprotection and alarm stages and 4-20mA undercurrent alarm associated with thatinput are blocked. The blocking signals may be useful for blocking the current loopinputs when the CB is open for example.

DDB signals are available to indicate starting an operation of the alarm and tripstages of the each current loop inputs, (CLI1/2/3/4 Alarm Start: DDB 658-661,CLI1/2/3/4 Trip Start: DDB 662-665, CL Input 1/2/3/4 Alarm: DDB 322-325, CLIInput1/2/3/4 Trip: DDB 508-511). The state of the DDB signals can be programmedto be viewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in therelay.

Setting ranges for the current loop inputs are shown in the following table:

Setting RangeMenu Text Default

Setting Min MaxStep Size

GROUP 1CLIO PROTECTION

CLIO Input 1 Disabled Disabled/Enabled

CLI1 Input Type 4-20mA 0-1mA, 0-10mA, 0-20mA, 4-20mA

CLI1 Input Label CLIO Input 1 16 characters

CLI1 Minimum 0 -9999 9999 0.1

CLI1 Maximum 100 -9999 9999 0.1

CLI1 Alarm Disabled Disabled/Enabled

CLI1 Alarm Fn Over Over/Under

CLI1 Alarm Set 50 Min (CLI1Min, Max)

Max (CLI1Min, Max) 0.1

CLI1 Alarm Delay 1 0 100s 0.1s

CLI1 Trip Disabled Disabled/Enabled

CLI1 Trip Fn Over Over/Under

CLI1 Trip Set 50 Min (CLI1Min, Max)

Max (CLI1Min, Max) 0.1

CLI1 Trip Delay 1 0 100s 0.1s

CLI1 I< Alarm (4-20 mA input only) Disabled Disabled/Enabled

CLI1 I< Alm Set (4-20 mA input only) 3.5 mA 0 4 mA 0.1 mA

Repeat for current loop inputs 2, 3 and 4

2.27.2 Setting guidelines for current loop inputs

For each analogue input, the user can define the following:

• The current input range: 0-1mA, 0-10mA, 0-20mA, 4-20mA

• The Analogue Input function and unit, this is in the form of a 16-character InputLabel


Page 130/176 MiCOM P342, P343

• Analogue Input Minimum Value (setting range from –9999 to 9999)

• Analogue Input Maximum Value (setting range from –9999 to 9999)

• Alarm threshold, range within the Maximum and Minimum set values

• Alarm Function – Over or Under

• Alarm Delay

• Trip Threshold, range within Maximum and Minimum set values

• Trip Function – Over or Under

• Trip delay

Each current loop input can be selected as Enabled or Disabled as can the Alarm andTrip stage of each of the current loop input. The Alarm and Trip stages can be set foroperation when the input value falls below the Alarm/Trip threshold ‘Under’ or whenthe input current is above the input value ‘Over’ depending on the application. Oneof four types of analogue inputs can be selected for transducers with ranges of0-1mA, 0-10mA, 0-20mA or 4-20mA.

The Maximum and Minimum settings allow the user to enter the range of physical orelectrical quantities measured by the transducer. The settings are unit-less; however,the user can enter the transducer function and the unit of the measurement using the16-character user defined CLI Input Label. For example, if the Analogue Input isused to monitor a power measuring transducer, the appropriate text could be “ActivePower(MW)”.

The alarm and trip threshold settings should be set within the range of physical orelectrical quantities defined by the user. The relay will convert the current input valueinto its corresponding transducer measuring value for the protection calculation. Forexample if the CLI Minimum is –1000 and the CLI Maximum is 1000 for a 0-10mAinput, an input current of 10mA is equivalent to a measurement value of 1000, 5mAis 0 and 1mA is –800. If the CLI Minimum is 1000 and the CLI Maximum is -1000for a 0-10mA input, an input current of 10mA is equivalent to a measurement valueof –1000, 5mA is 0 and 1mA is 800. These values are available for display in the‘CLIO Input 1/2/3/4’ cells in the ‘MEASUREMENTS 3’ menu. The top line shows theCLI Input Label and the bottom line shows the measurement value.

2.27.3 Current loop outputs

Four analogue current outputs are provided with ranges of 0-1mA, 0-10mA, 0-20mAor 4-20mA which can alleviate the need for separate transducers. These may beused to feed standard moving coil ammeters for analogue indication of certainmeasured quantities or into a SCADA using an existing analogue RTU.

The CLIO output conversion task runs every 50ms and the refresh interval for theoutput measurements is nominally 50ms. The exceptions are marked with an asteriskin the table of current loop output parameters below. Those exceptionalmeasurements are updated once every second.

The outputs can be assigned to any of the following relay measurements:

• Magnitudes of IA, IB, IC, IN, IN Derived, I Sensitive

• Magnitudes of I1, I2, I0

• IA RMS, IB RMS, IC RMS

• Magnitudes of VAB, VBC, VCA, VAN, VBN, VCN, VN Measured, VN Derived


MiCOM P342, P343 Page 131/176

• Magnitudes of V1, V2 and V0

• VAN RMS, VBN RMS, VCN RMS

• Frequency

• Single Phase Active, reactive and apparent power, single phase power factor

• 3 phase active, reactive and apparent power, single phase power factor

• VN 3rd Harmonic (P343 only)

• Stator thermal state

• Rotor (NPS) thermal state (P342/P343 only)

• RTD temperatures (P342/P343 only)

• Analogue Inputs

The user can set the measuring range for each analogue output. The range limitsare defined by the Maximum and Minimum settings. This allows the user to “zoomin” and monitor a restricted range of the measurements with the desired resolution.For voltage, current and power quantities, these settings can be set in either primaryor secondary quantities, depending on the ‘CLO1/2/3/4 Set Values – Primary /Secondary’ setting associated with each current loop output.

The output current of each analogue output is linearly scaled to its range limits, asdefined by the Maximum and Minimum settings. The relationship is shown in Figure48.

0mA

1mA

Minimum Maximum

0-1mARelay

Measure-ment

CurrentOutput

0mA

10mA

Minimum Maximum

0-10mARelay

Measure-ment

CurrentOutput

0mA

20mA

Minimum Maximum

0-20mARelay

Measure-ment

CurrentOutput

0mA

20mA

Minimum Maximum

4-20mARelay

Measure-ment

CurrentOutput

4mA

P1418ENa

Figure 48: Relationship between the current output and the relay measurement


Page 132/176 MiCOM P342, P343

Note, if the Maximum is set less than the Minimum, the slopes of the graphs will benegative. This is because the mathematical relationship remains the sameirrespective of how Maximum and Minimum are set, e.g., for 0-1mA range,Maximum always corresponds to 1mA and Minimum corresponds to 0mA.

The P340 transducers are of the current output type. This means that the correctvalue of output will be maintained over the load range specified. The range of loadresistance varies a great deal, depending on the design and the value of outputcurrent. Transducers with a full scale output of 10mA will normally feed any load upto a value of 1000Ω (compliance voltage of 10V). This equates to a cable length of15km (approximately) for lightweight cable (1/0.6mm cable). A screened cableearthed at one end only is recommended to reduce interference on the output currentsignal. The table below gives typical cable impedances/km for common cables. Thecompliance voltage dictates the maximum load that can be fed by a transduceroutput. Therefore, the 20mA output will be restricted to a maximum load of 500Ωapproximately.

Cable 1/0.6mm 1/0.85mm 1/1.38mm

CSA (mm2) 0.28 0.57 1.50

R (Ω/km) 65.52 32.65 12.38

The receiving equipment, whether it be a simple moving-coil (DC milli-ammeter)instrument or a remote terminal unit forming part of a SCADA system, can beconnected at any point in the output loop and additional equipment can be installedat a later date (provided the compliance voltage is not exceeded) without any needfor adjustment of the transducer output.

Where the output current range is used for control purposes, it is sometimesworthwhile to fit appropriately rated diodes, or Zener diodes, across the terminals ofeach of the units in the series loop to guard against the possibility of their internalcircuitry becoming open circuit. In this way, a faulty unit in the loop does not causeall the indications to disappear because the constant current nature of the transduceroutput simply raises the voltage and continues to force the correct output signal roundthe loop.

Power-on diagnostics and continuous self-checking are provided for the hardwareassociated with the current loop outputs. When failure is detected, all the currentloop output functions are disabled and a single alarm signal (CL Card O/P Fail,DDB 321) is set and an alarm (CL Card O/P Fail) is raised. A maintenance recordwith an error code is also recorded with additional details about the type of failure.

Setting ranges for the Current Loop Outputs are shown in the following table:


Min MaxStep Size

GROUP 1CLIO PROTECTION

CLIO Output 1 Disabled Enabled, Disabled

CLO1 Output Type 4-20mA 0-1mA, 0-10mA, 0-20mA, 4-20mA

CLO1 Set Values Primary Primary, Secondary

CLO1 Parameter IA Magnitude A list of parameters are shown in thetable below


MiCOM P342, P343 Page 133/176


Min MaxStep Size

CLO1 Minimum 0 Range, step size and unit corresponds tothe selected parameter in the table below

CLO1 Maximum 1.2 In Range, step size and unit corresponds tothe selected parameter in the table below


Current loop output parameters are shown in the following table:

Current LoopOutput

ParameterAbbreviation Units Range Step

DefaultMin

DefaultMax

Current Magnitude IA MagnitudeIB MagnitudeIC MagnitudeIN Measured Mag

A 0 to 16A 0.01A 0A 1.2A

Sensitive CurrentInput Magnitude

I Sen Magnitude A 0 to 2A 0.01A 0A 1.2A

Phase SequenceCurrentComponents

I1 MagnitudeI2 MagnitudeI0 Magnitude

A 0 to 16A 0.01A 0A 1.2A

RMS PhaseCurrents

IA RMS*IB RMS*IC RMS*

A 0 to 16A 0.01A 0A 1.2A

P-P VoltageMagnitude

VAB MagnitudeVBC MagnitudeVCA Magnitude

V 0 to200V

0.1V 0V 140V

P-N voltageMagnitude

VAN MagnitudeVBN MagnitudeVCN Magnitude

V 0 to200V

0.1V 0V 80V

Neutral VoltageMagnitude

VN Measured MagVN Derived Mag

V 0 to200V

0.1V 0V 80V

3rd HarmonicNeutral Voltage

VN 3rd Harmonic V 0 to200V

0.1V 0V 80V

Phase SequenceVoltageComponents

V1 Magnitude*V2 MagnitudeV0 Magnitude

V 0 to200V

0.1V 0V 80V

RMS PhaseVoltages

VAN RMS*VBN RMS*VCN RMS*

V 0 to200V

0.1V 0V 80V

Frequency Frequency Hz 0 to70Hz

0.01Hz 45Hz 65Hz

3 Ph Active Power 3 Phase Watts* W -6000Wto

6000W

1W 0W 300W

3 Ph ReactivePower

3 Phase Vars* Var -6000Varto

6000Var

1Var 0Var 300Var

3 Ph ApparentPower

3 Phase VA* VA 0to

6000VA

1VA 0VA 300VA

3 Ph Power Factor 3Ph Power Factor* - -1 to 1 0.01 0 1


Page 134/176 MiCOM P342, P343

Current LoopOutput


DefaultMin

DefaultMax

Single Phase ActivePower

A Phase Watts*B Phase Watts*C Phase Watts*

W -2000Wto

2000W

1W 0W 100W

Single PhaseReactive Power

A Phase Vars*B Phase Vars*C Phase Vars*

Var -2000Varto

2000Var

1Var 0Var 100Var

Single PhaseApparent Power

A Phase VA*B Phase VA*C Phase VA*

VA 0to

2000VA

1VA 0VA 100VA

Single Phase PowerFactor

APh Power Factor*BPh Power Factor*CPh Power Factor*

-1 to 1 0.01 0 1

3 Phase CurrentDemands

IA Fixed Demand*IB Fixed Demand*IC Fixed Demand*IA Roll Demand*IB Roll Demand*IC Roll Demand*IA Peak Demand*IB Peak Demand*IC Peak Demand*

A 0 to 16A 0.01A 0A 1.2A

3Ph Active PowerDemands

3Ph W FixDemand*3Ph W Roll Dem*3Ph W Peak Dem*

W -6000Wto

6000W

1W 0W 300W

3Ph Reactive PowerDemands

3Ph Vars Fix Dem*3Ph Var Roll Dem*3Ph Var Peak Dem*

Var -6000Varto

6000Var

1Var 0Var 300Var

Rotor ThermalState

NPS Thermal % 0 to 200 0.01 0 120

Stator ThermalState

Thermal Overload % 0 to 200 0.01 0 120

RTD Temperatures RTD 1*RTD 2*RTD 3*RTD 4*RTD 5*RTD 6*RTD 7*RTD 8*RTD 9*RTD 10*

°C -40°Cto

300°C

0.1°C 0°C 200°C

Current LoopInputs

CL Input 1CL Input 2CL Input 3CL input 4

- -9999to

9999

0.1 0 9999

Note 1: For measurements marked with an asterisk, the internal refreshrate is nominally 1s, others are 0.5 power system cycle or less.

Note 2: The polarity of Watts, Vars and power factor is affected by theMeasurements Mode setting.

Note 3: These settings are for nominal 1A and 100/120V versions only.For other nominal versions they need to be multipliedaccordingly.


MiCOM P342, P343 Page 135/176

Note 4: For the P343, the IA/IB/IC Current magnitudes are IA-1Magnitude, IB-1 Magnitude, IC-1 Magnitude.

2.27.4 Setting guidelines for current loop outputs

Each current loop output can be selected as Enabled or Disabled. One of four typesof analogue output can be selected for transducers with ranges of 0-1mA, 0-10mA,0-20mA or 4-20mA. The 4-20mA range is often used so that an output current is stillpresent when the measured value falls to zero. This is to give a fail safe indicationand may be used to distinguish between the analogue transducer output becomingfaulty and the measurement falling to zero.

The Maximum and Minimum settings allow the user to enter the measuring range foreach analogue output. The range, step size and unit corresponding to the selectedparameter is shown in the table above. This allows the user to “zoom in” andmonitor a restricted range of the measurements with the desired resolution. Forvoltage, current and power quantities, these settings can be set in either primary orsecondary quantities, depending on the ‘CLO1/2/3/4 Set Values – Primary /Secondary’ setting associated with each current loop output.

The relationship of the output current to the value of the measurand is of vitalimportance and needs careful consideration. Any receiving equipment must, ofcourse, be used within its rating but, if possible, some kind of standard should beestablished.

One of the objectives must be to have the capability to monitor the voltage over arange of values, so an upper limit must be selected, typically 120%. However, thismay lead to difficulties in scaling an instrument.

The same considerations apply to current transducers outputs and with addedcomplexity to watt transducers outputs, where both the voltage and currenttransformer ratios must be taken into account.

Some of these difficulties do not need to be considered if the transducer is onlyfeeding, for example, a SCADA outstation. Any equipment which can beprogrammed to apply a scaling factor to each input individually can accommodatemost signals. The main consideration will be to ensure that the transducer is capableof providing a signal right up to the full-scale value of the input, that is, it does notsaturate at the highest expected value of the measurand.

3. APPLICATION OF NON-PROTECTION FUNCTIONS

3.1 VT supervision

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 transformer faults,overloading, or faults on the interconnecting wiring to relays. This usually results inone or more VT fuses blowing. Following a failure of the ac voltage input therewould 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, and automaticallyadjust the configuration of protection elements whose stability would otherwise becompromised. 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:


Page 136/176 MiCOM P342, P343

1. Loss of one or two phase voltages

2. Loss of all three phase voltages under load conditions

3. Absence of three phase voltages upon line energisation

The 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(Vn = 100/120V) or 40V (Vn = 380/480V), and Ι2 = 0.05 to 0.5Ιn settable(defaulted to 0.05Ιn).

3.1.1 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, under suchcircumstances, a collapse of the three phase voltages will occur. If this is detectedwithout a corresponding change in any of the phase current signals (which would beindicative of a fault), then a VTS condition will be raised. In practice, the relay detectsthe presence of superimposed current signals, which are changes in the currentapplied to the relay. These signals are generated by comparison of the present valueof the current with that exactly one cycle previously. Under normal load conditions,the value of superimposed current should therefore be zero. Under a fault conditiona superimposed current signal will be generated which will prevent operation of theVTS.

The phase voltage level detectors are fixed and will drop off at 10V(Vn = 100/120V), 40V (Vn = 380/480V) and pick-up at 30V (Vn = 100/120V),120V (Vn = 380/480V).

The sensitivity of the superimposed current elements is fixed at 0.1Ιn.

3.1.2 Absence of three phase voltages upon line energisation

If a VT were inadvertently left isolated prior to line energisation, incorrect operation ofvoltage dependent elements could result. The previous VTS element detected threephase VT failure by absence of all 3 phase voltages with no corresponding change incurrent. On line energisation there will, however, be a change in current (as a resultof load or line charging current for example). An alternative method of detecting 3phase VT failure is therefore required on line energisation.

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 differentiate betweenthese 2 conditions an overcurrent level detector (VTS Ι> Inhibit) is used which willprevent a VTS block from being issued if it operates. This element should be set inexcess of any non-fault based currents on line energisation (load, line chargingcurrent, transformer inrush current if applicable) but below the level of currentproduced by a close up 3 phase fault. If the line is now closed where a 3 phase VTfailure is present the overcurrent detector will not operate and a VTS block will beapplied. Closing onto a three phase fault will result in operation of the overcurrentdetector and prevent a VTS block being applied.


MiCOM P342, P343 Page 137/176

This logic will only be enabled during a live line condition (as indicated by the relayspole dead logic) to prevent operation under dead system conditions i.e. where novoltage will be present and the VTS Ι> Inhibit overcurrent element will not be pickedup.

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Note: The accelerated ind input is not used in the generator protection.

Figure 49: VTS logic

Required to drive the VTS logic are a number of dedicated level detectors as follows:

• ΙA>, ΙB>, ΙC>, these level detectors operate in less than 20ms and their settingsshould be greater than load current. This setting is specified as the VTS currentthreshold. These level detectors pick-up at 100% of setting and drop-off at 95%of setting.

• Ι2>, this level detector operates on negative sequence current and has a usersetting. This level detector picks-up at 100% of setting and drops-off at 95% ofsetting.

• ∆ΙIA>, ∆ΙB>, ∆ΙC>, these level detectors operate on superimposed phasecurrents and have a fixed setting of 10% of nominal. These level detectors aresubject to a count strategy such that 0.5 cycle of operate decisions must haveoccured before operation.

• VA>, VB>, VC>, these level detectors operate on phase voltages and have afixed setting, Pick-up level = 30V (Vn = 100/120V), 120V (Vn = 380/480V),Drop Off level = 10V (Vn = 100/120V), 40V (Vn = 380/480V).

• V2>, this level detector operates on negative sequence voltage, it has a fixedsetting of 10V/40V depending on VT rating (100/120 or 380/480) with pick-up at100% of setting and drop-off at 95% of setting.


Page 138/176 MiCOM P342, P343

3.1.2.1 Inputs

Signal Name Description

ΙA>, ΙB>, ΙC> Phase current levels (Fourier Magnitudes)

Ι2> Ι2 level (Fourier Magnitude).

∆ΙA, ∆ΙB, ∆ΙC Phase current samples (current and one cycleprevious)

VA>, VB>, VC> Phase voltage signals (Fourier Magnitudes)

V2> Negative Sequence voltage (FourierMagnitude)

ALL POLE DEAD Breaker is open for all phases (driven fromauxiliary contact or pole dead logic).

VTS_MANRESET A VTS reset performed via front panel orremotely.

VTS_AUTORESET A setting to allow the VTS to automaticallyreset after this delay.

MCB/VTS OPTO To remotely initiate the VTS blocking via anopto.

Any Voltage Dependent Function

Outputs from any function that utilises thesystem voltage, if any of these elementsoperate before a VTS is detected the VTS isblocked from operation. The outputs includestarts and trips.

Accelerate IndSignal from a fast tripping voltage dependentfunction used to accelerate indications whenthe indicate only option is selected.

Any Pole DeadBreaker is open on one or more than onephases (driven from auxiliary contact or poledead logic).

tVTS The VTS timer setting for latched operation.

3.1.2.2 Outputs

Signal Name Description

VTS Fast Block Used to block voltage dependent functions.

VTS Slow block Used to block the Any Pole dead signal.

VTS Indication Signal used to indicate a VTS operation.


MiCOM P342, P343 Page 139/176

3.1.3 Menu settings

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


Min MaxStep Size

GROUP 1SUPERVISION

VTS Status Blocking Blocking, Indication

VTS Reset Mode Manual Manual, Auto

VTS Time Delay 5s 1s 10s 0.1s

VTS Ι> Inhibit 10Ιn 0.08Ιn 32Ιn 0.01Ιn

VTS Ι2> Inhibit 0.05Ιn 0.05Ιn 0.5Ιn 0.01Ιn

The relay may respond as follows, an operation of any VTS element:

• VTS set to provide alarm indication only (DDB 292 VT Fail Alarm);

• Optional blocking of voltage dependent protection elements (DDB 736 VTS FastBlock, DDB 737 VTS Slow Block);

• Optional conversion of directional SEF elements to non-directional protection(available when set to blocking mode only). These settings are found in thefunction links cell of the relevant protection element columns in the menu.

Time delayed protection elements (Directional SEF, Power, Sensitive Power, FieldFailure) are blocked after the VTS Time Delay on operation of the VTS Slow Block.Fast operating protection elements (Neutral Voltage Displacement, System Backup,Undervoltage, Dead Machine, Pole Slipping) are blocked on operation of the VTSFast Block. Note, the directional SEF and neutral voltage displacement protection areonly blocked by VTS if the neutral voltage input is set to Derived and not Measured.

Other protections can be selectively blocked by customising the PSL, integrating DDB736 VTS Fast Block and DDB 737 VTS Slow Block with the protection function logic.

The VTS Ι> Inhibit or VTS Ι2> Inhibit elements are used to overide a VTS block inevent of a fault occurring on the system which could trigger the VTS logic. Once theVTS block has been established, however, then 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’. Once the signal haslatched then two methods of resetting are available. The first is manually via the frontpanel interface (or remote communications) provided the VTS condition has beenremoved and secondly, when in ‘Auto’ mode, by the restoration of the 3 phasevoltages above the phase level detector settings mentioned 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, dependingon which protection elements are enabled. In this case the VTS indication will begiven prior to the VTS time delay expiring if a trip signal is given.

Where a miniature circuit breaker (MCB) is used to protect the voltage transformer acoutput circuits, it is common to use MCB auxiliary contacts to indicate a three phaseoutput disconnection. As previously described, it is possible for the VTS logic tooperate correctly without this input. However, this facility has been provided for


Page 140/176 MiCOM P342, P343

compatibility with various utilities current practices. Energising an opto-isolated inputassigned to “MCB Open” on the relay will therefore provide the necessary block.

Where directional SEF elements are converted to non-directional protection on VTSoperation, it must be ensured that the current pick-up setting of these elements ishigher than full load current.

3.2 CT supervision

The current transformer supervision feature is used to detect failure of one or more ofthe ac phase current inputs to the relay. Failure of a phase CT or an open circuit ofthe interconnecting wiring can result in incorrect operation of any current operatedelement. Additionally, interruption in the ac current circuits risks dangerous CTsecondary voltages being generated.

3.2.1 The CT supervision feature

The CT supervision feature operates on detection of derived residual current, in theabsence of corresponding derived or measured residual voltage that would normallyaccompany it.

The CT supervision can be set to operate from the residual voltage measured at theVNEUTRAL input or the residual voltage derived from the 3 phase-neutral voltageinputs as selected by the ‘CTS Vn Input’ setting.

The voltage transformer connection used must be able to refer residual voltages fromthe primary to the secondary side. Thus, this element should only be enabled wherethe 3 phase VT is of five limb construction, or comprises three single phase units, andhas the primary star point earthed. A derived residual voltage or a measuredresidual voltage is available.

Operation of the element will produce a time-delayed alarm visible on the LCD andevent record (plus DDB 293: CT Fail Alarm), with an instantaneous block (DDB 738:CTS Block) for inhibition of protection elements. Protection elements operating fromderived quantities, (Neg Seq O/C) are always blocked on operation of the CTsupervision element; other protections can be selectively blocked by customising thePSL, integrating DDB 738: CTS Block with the protection function logic.

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Figure 50: CT supervision function block diagram

The following table shows the relay menu for the CT supervision element, includingthe available setting ranges and factory defaults:


MiCOM P342, P343 Page 141/176


Min MaxStep Size

GROUP 1SUPERVISION

CT Supervision Sub Heading

CTS Status Disabled Enabled/Disabled N/A

CTS VN Input Derived Derived/Measured N/A

CTS VN< Inhibit 10.5/2V For 110/440V respectively

22/88V For 110/440V respectively 0.5/2VFor 110/440V respectively

CTS ΙN> Set 0 0.08 x Ιn 4 x Ιn 0.01 x Ιn

CTS Time Delay 5 0s 10s 1s

3.2.2 Setting the CT supervision element

The residual voltage setting, "CTS Vn< Inhibit" and the residual current setting,"CTS Ιn> 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 Ιn> set" will typically be set below minimumload current. The time-delayed alarm, "CTS Time Delay", is generally set to 5seconds.

Where the magnitude of residual voltage during an earth fault is unpredictable, theelement can be disabled to prevent a protection elements being blocked during faultconditions.

3.3 Circuit breaker state monitoring

An operator at a remote location requires a reliable indication of the state of theswitchgear. Without an indication that each circuit breaker is either open or closed,the operator has insufficient information to decide on switching operations. The relayincorporates circuit breaker state monitoring, giving an indication of the position ofthe circuit breaker, or, if the state is unknown, an alarm is raised.

3.3.1 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, these contacts willbe in opposite states. Should both sets of contacts be open, this would indicate oneof the following conditions:

• Auxiliary contacts/wiring defective

• Circuit Breaker (CB) is defective

• CB is in isolated position

Should both sets of contacts be closed, only one of the following two conditions wouldapply:

• Auxiliary contacts/wiring defective



Page 142/176 MiCOM P342, P343

If any of the above conditions exist, an alarm will be issued after a 5s time delay. Anormally open / normally closed output contact can be assigned to this function viathe 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:

None

52A

52B

Both 52A and 52B

Where ‘None’ is selected no CB status will be available. This will directly affect anyfunction 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 will beavailable in this case but no discrepancy alarm will be available. The above is alsotrue where only a 52B is used. If both 52A and 52B are used then status informationwill be available and in addition a discrepancy alarm will be possible, according tothe following table. 52A and 52B inputs are assigned to relay opto-isolated inputsvia the PSL. The CB State Monitoring logic is shown in Figure 51).

Auxiliary Contact Position

52A 52BCB State Detected Action

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


MiCOM P342, P343 Page 143/176

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Figure 51: CB state monitoring

3.4 Pole dead logic

The Pole Dead Logic can be used to give an indication if one or more phases of theline are dead. It can also be used to selectively block operation of both the underfrequency, under voltage and power elements. The under voltage protection will beblocked by a pole dead condition provided the “Pole Dead Inhibit” setting is enabled.Any of the four under frequency elements can be blocked by setting the relevant “F<function links”. The Power and Senistive Power protection will be blocked by a poledead condition provided the “Pole Dead Inhibit” setting is enabled.

A pole dead condition can be determined by either monitoring the status of the circuitbreaker auxiliary contacts or by measuring the line currents and voltages. The statusof the circuit breaker is provided by the “CB State Monitoring” logic. If a “CB Open”signal (DDB 794) is given the relay will automatically initiate a pole dead conditionregardless of the current and voltage measurement. Similarly if both the line currentand voltage fall below a pre-set threshold the relay will also initiate a pole deadcondition. This is necessary so that a pole dead indication is still given even when anupstream breaker is opened. The under voltage (V<) and under current (Ι<)thresholds have the following, fixed, pickup and drop-off levels:


Page 144/176 MiCOM P342, P343

Settings Range Step Size

V< Pick-up and drop off10V and 30V (100/120V)

40V and 120V (380/480V)Fixed

Ι< Pick-up and drop off 0.05 Ιn and 0.055Ιn Fixed

If one or more poles are dead the relay will indicate which phase is dead and willalso assert the ANY POLE DEAD DDB signal (DDB 758). If all phases were dead theANY POLE DEAD signal would be accompanied by the ALL POLE DEAD DDB signal(DDB 757).

In the event that the VT fails a signal is taken from the VTS logic (DDB 737 – SlowBlock) to block the pole dead indications that would be generated by the undervoltage and undercurrent thresholds. However, the VTS logic will not block the poledead indications if they are initiated by a “CB Open” signal (DDB 754).

The pole dead logic diagram is shown below:

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Figure 52: Pole dead logic

3.5 Circuit breaker condition monitoring

Periodic maintenance of circuit breakers is necessary to ensure that the trip circuit andmechanism operate correctly, and also that the interrupting capability has not beencompromised due to previous fault interruptions. Generally, such maintenance isbased on a fixed time interval, or a fixed number of fault current interruptions. Thesemethods of monitoring circuit breaker condition give a rough guide only and canlead to excessive maintenance.


MiCOM P342, P343 Page 145/176

The P340 relays record various statistics related to each circuit breaker trip operation,allowing a more accurate assessment of the circuit breaker condition to bedetermined. These monitoring features are discussed in the following section.

3.5.1 Circuit breaker condition monitoring features

For each circuit breaker trip operation the relay records statistics as shown in thefollowing table taken from the relay menu. The menu cells shown are counter valuesonly. The Min/Max values in this case show the range of the counter values. Thesecells can not be set:


Min MaxStep Size

CB CONDITION

CB operations3 pole tripping 0 0 10000 1

Total ΙA Broken 0 0 25000Ιn^ 1

Total ΙB Broken 0 0 25000Ιn^ 1

Total ΙC Broken 0 0 25000Ιn^ 1Ιn^

CB operate time 0 0 0.5s 0.001

Reset CB Data No Yes, No

The above counters may be reset to zero, for example, following a maintenanceinspection and overhaul.

The following table, detailing the options available for the CB condition monitoring, istaken from the relay menu. It includes the set up of the current broken facility andthose features which can be set to raise an alarm or CB lockout.


Min MaxStep Size

CB MONITOR SETUP

Broken Ι^ 2 1 2 0.1

Ι^ Maintenance Alarm disabled Alarm disabled, Alarm enabled

Ι^ Maintenance 1000Ιn^ 1Ιn^ 25000Ιn^ 1Ιn^

Ι^ Lockout Alarm disabled Alarm disabled, Alarm enabled

Ι^ Lockout 2000Ιn^ 1Ιn^ 25000Ιn^ 1Ιn^

No CB Ops. Maint. Alarm disabled Alarm disabled, Alarm enabled

No CB Ops. Maint. 10 1 10000 1

No CB Ops. Lock Alarm disabled Alarm disabled, Alarm enabled

No CB Ops. Lock 20 1 10000 1

CB Time Maint. Alarm disabled Alarm disabled, Alarm enabled

CB Time Maint. 0.1s 0.005s 0.5s 0.001s

CB Time Lockout Alarm disabled Alarm disabled, Alarm enabled

CB Time Lockout 0.2s 0.005s 0.5s 0.001s


Page 146/176 MiCOM P342, P343


Min MaxStep Size

Fault Freq. Lock Alarm disabled Alarm disabled, Alarm enabled

Fault Freq. Count 10 1 9999 1

Fault Freq. Time 3600s 0 9999s 1s

The circuit breaker condition monitoring counters will be updated every time the relayissues a trip command. In cases where the breaker is tripped by an externalprotection device it is also possible to update the CB condition monitoring. This isachieved by allocating one of the relays opto-isolated inputs (via the programmablescheme logic) to accept a trigger from an external device. The signal that is mappedto the opto is called ‘Ext Trip 3Ph’, DDB 380.

Note that when in Commissioning test mode the CB condition monitoring counterswill not be updated.

3.5.2 Setting guidelines

3.5.2.1 Setting the Σ Ι^ thresholds

Where overhead lines are prone to frequent faults and are protected by oil circuitbreakers (OCB’s), oil changes account for a large proportion of the life cycle cost ofthe switchgear. Generally, oil changes are performed at a fixed interval of circuitbreaker fault operations. However, this may result in premature maintenance wherefault currents tend to be low, and hence oil degradation is slower than expected. TheΣ Ι^ counter monitors the cumulative severity of the duty placed on the interrupterallowing a more accurate assessment of the circuit breaker condition to be made.

For OCB’s, the dielectric withstand of the oil generally decreases as a function ofΣ Ι2t. This is where ‘Ι’ is the fault current broken, and ‘t’ is the arcing time within theinterrupter tank (not the interrupting time). As the arcing time cannot be determinedaccurately, the relay would normally be set to monitor the sum of the broken currentsquared, by setting ‘Broken Ι^’ = 2.

For other types of circuit breaker, especially those operating on higher voltagesystems, practical evidence suggests that the value of ‘Broken Ι^’ = 2 may beinappropriate. In such applications ‘Broken Ι^’ may be set lower, typically 1.4 or1.5. An alarm in this instance may be indicative of the need for gas/vacuuminterrupter HV pressure testing, for example.

The setting range for ‘Broken Ι^’ is variable between 1.0 and 2.0 in 0.1 steps. It isimperative that any maintenance programme must be fully compliant with theswitchgear manufacturer’s instructions.

3.5.2.2 Setting the number of operations thresholds

Every operation of a circuit breaker results in some degree of wear for itscomponents. Thus, routine maintenance, such as oiling of mechanisms, may bebased upon the number of operations. Suitable setting of the maintenance thresholdwill allow an alarm to be raised, indicating when preventative maintenance is due.Should maintenance not be carried out, the relay can be set to lockout theautoreclose function on reaching a second operations threshold. This preventsfurther reclosure when the circuit breaker has not been maintained to the standarddemanded by the switchgear manufacturer’s maintenance instructions.


MiCOM P342, P343 Page 147/176

Certain circuit breakers, such as oil circuit breakers (OCB’s) can only perform acertain number of fault interruptions before requiring maintenance attention. This isbecause each fault interruption causes carbonising of the oil, degrading its dielectricproperties. The maintenance alarm threshold "No CB Ops Maint" may be set toindicate the requirement for oil sampling for dielectric testing, or for morecomprehensive maintenance. Again, the lockout threshold "No CB Ops Lock" may beset to disable autoreclosure when repeated further fault interruptions could not beguaranteed. This minimises the risk of oil fires or explosion.

3.5.2.3 Setting the operating time thresholds

Slow CB operation is also indicative of the need for mechanism maintenance.Therefore, alarm and lockout thresholds (CB Time Maint/CB Time Lockout) areprovided and are settable in the range of 5 to 500ms. This time is set in relation tothe specified interrupting time of the circuit breaker.

3.5.2.4 Setting the excessive fault frequency thresholds

A circuit breaker may be rated to break fault current a set number of times beforemaintenance is required. However, successive circuit breaker operations in a shortperiod of time may result in the need for increased maintenance. For this reason it ispossible to set a frequent operations counter on the relay which allows the number ofoperations "Fault Freq Count" over a set time period "Fault Freq Time" to bemonitored. A separate alarm and lockout threshold can be set.

3.5.3 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, these contacts willbe in opposite states. Should both sets of contacts be open, this would indicate oneof the following conditions:

• Auxiliary contacts / wiring defective


• CB is in isolated position

Should both sets of contacts be closed, only one of the following two conditions wouldapply:

• Auxiliary contacts / wiring defective



Min MaxStep Size

CB Time Maint 0.1s 0.005s 0.5s 0.001s

CB Time Lockout Alarm disabled Alarm disabled, Alarm enabled

CB Time Lockout 0.2s 0.005s 0.5s 0.001s

Fault Freq Lock Alarm disabled Alarm disabled, Alarm enabled

Fault Freq Count 10 0 9999 1

Fault Freq Time 3600s 0 9999s 1s

The circuit breaker condition monitoring counters will be updated every time the relayissues a trip command. In cases where the breaker is tripped by an externalprotection device it is also possible to update the CB condition monitoring. This is


Page 148/176 MiCOM P342, P343

achieved by allocating one of the relays opto-isolated inputs (via the programmablescheme logic) to accept a trigger from an external device. The signal that is mappedto the opto is called ‘External Trip’.

Note that when in Commissioning test mode the CB condition monitoring counterswill not be updated.

3.6 Trip circuit supervision (TCS)

The trip circuit, in most protective schemes, extends beyond the relay enclosure andpasses through components such as fuses, links, relay contacts, auxiliary switches andother terminal boards. This complex arrangement, coupled with the importance ofthe trip circuit, has led to dedicated schemes for its supervision.

Several trip circuit supervision schemes with various features can be produced withthe P340 range. Although there are no dedicated settings for TCS, in the P340, thefollowing schemes can be produced using the programmable scheme logic (PSL). Auser alarm is used in the PSL to issue an alarm message on the relay front display. Ifnecessary, the user alarm can be re-named using the menu text editor to indicate thatthere is a fault with the trip circuit.

3.6.1 TCS scheme 1

3.6.1.1 Scheme description

P2228ENa

Optional

Figure 53: TCS scheme 1

This scheme provides supervision of the trip coil with the breaker open or closed,however, pre-closing supervision is not provided. This scheme is also incompatiblewith latched trip contacts, as a latched contact will short out the opto for greater thanthe recommended DDO timer setting of 400ms. If breaker status monitoring isrequired a further 1 or 2 opto inputs must be used. Note, a 52a CB auxiliary contactfollows the CB position and a 52b contact is the opposite.

When the breaker is closed, supervision current passes through the opto input,blocking diode and trip coil. When the breaker is open current still flows through theopto input and into the trip coil via the 52b auxiliary contact. Hence, no supervisionof the trip path is provided whilst the breaker is open. Any fault in the trip path willonly be detected on CB closing, after a 400ms delay.

Resistor R1 is an optional resistor that can be fitted to prevent mal-operation of thecircuit breaker if the opto input is inadvertently shorted, by limiting the current to<60mA. The resistor should not be fitted for auxiliary voltage ranges of 30/34 voltsor less, as satisfactory operation can no longer be guaranteed. The table belowshows the appropriate resistor value and voltage setting (OPTO CONFIG menu) forthis scheme.


MiCOM P342, P343 Page 149/176

This TCS scheme will function correctly even without resistor R1, since the opto inputautomatically limits the supervision current to less that 10mA. However, if the opto isaccidentally shorted the circuit breaker may trip.

Auxiliary Voltage (Vx) Resistor R1 (ohms) Opto Voltage Setting withR1 Fitted

24/27 - -

30/34 - -

48/54 1.2k 24/27

110/250 2.5k 48/54

220/250 5.0k 110/125

Note: When R1 is not fitted the opto voltage setting must be set equalto supply voltage of the supervision circuit.

3.6.2 Scheme 1 PSL

Figure 54 shows the scheme logic diagram for the TCS scheme 1. Any of theavailable opto inputs can be used to indicate whether or not the trip circuit is healthy.The delay on drop off timer operates as soon as the opto is energised, but will take400ms to drop off / reset in the event of a trip circuit failure. The 400ms delayprevents a false alarm due to voltage dips caused by faults in other circuits or duringnormal tripping operation when the opto input is shorted by a self-reset trip contact.When the timer is operated the NC (normally closed) output relay opens and the LEDand user alarms are reset.

The 50ms delay on pick-up timer prevents false LED and user alarm indicationsduring the relay power up time, following an auxiliary supply interruption.

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Figure 54: PSL for TCS schemes 1 and 3


Page 150/176 MiCOM P342, P343

3.6.3 TCS scheme 2


Optional

Optional

P2230ENa


Much like scheme 1, this scheme provides supervision of the trip coil with the breakeropen or closed and also does not provide pre-closing supervision. However, usingtwo opto inputs allows the relay to correctly monitor the circuit breaker status sincethey are connected in series with the CB auxiliary contacts. This is achieved byassigning Opto A to the 52a contact and Opto B to the 52b contact. Provided the“Circuit Breaker Status” is set to “52a and 52b” (CB CONTROL column) and opto’s Aand B are connected to CB Aux 3ph (52a) (DDB 381) and CB Aux 3ph (52b) (DDB382) the relay will correctly monitor the status of the breaker. This scheme is alsofully compatible with latched contacts as the supervision current will be maintainedthrough the 52b contact when the trip contact is closed.

When the breaker is closed, supervision current passes through opto input A and thetrip coil. When the breaker is open current flows through opto input B and the tripcoil. As with scheme 1, no supervision of the trip path is provided whilst the breakeris open. Any fault in the trip path will only be detected on CB closing, after a 400msdelay.

As with scheme 1, optional resistors R1 and R2 can be added to prevent tripping ofthe CB if either opto is shorted. The resistor values of R1 and R2 are equal and canbe set the same as R1 in scheme 1.

3.6.4 Scheme 2 PSL

The PSL for this scheme (Figure 56) is practically the same as that of scheme 1. Themain difference being that both opto inputs must be off before a trip circuit fail alarmis given.


MiCOM P342, P343 Page 151/176

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Figure 56: PSL for TCS scheme 2

3.6.5 TCS scheme 3


P2231ENa


Scheme 3 is designed to provide supervision of the trip coil with the breaker open orclosed, but unlike schemes 1 and 2, it also provides pre-closing supervision. Sinceonly one opto input is used, this scheme is not compatible with latched trip contacts.If circuit breaker status monitoring is required a further 1 or 2 opto inputs must beused.

When the breaker is closed, supervision current passes through the opto input,resistor R1 and the trip coil. When the breaker is open current flows through the optoinput, resistors R1 and R2 (in parallel), resistor R3 and the trip coil. Unlike schemes 1and 2, supervision current is maintained through the trip path with the breaker ineither state, thus giving pre-closing supervision.

As with schemes 1 and 2, resistors R1 and R2 are used to prevent false tripping, if theopto-input is accidentally shorted. However, unlike the other two schemes, thisscheme is dependent upon the position and value of these resistors. Removing themwould result in incomplete trip circuit monitoring. The table below shows the resistorvalues and voltage settings required for satisfactory operation.


Page 152/176 MiCOM P342, P343

Auxiliary Voltage(Vx)

Resistor R1 & R2(ohms) Resistor R3 (ohms) Opto Voltage

Setting

24/27 - - -

30/34 - - -

48/54 1.2k 0.6k 24/27

110/250 2.5k 1.2k 48/54

220/250 5.0k 2.5k 110/125

Note: Scheme 3 is not compatible with auxiliary supply voltages of30/34 volts and below.

3.6.6 Scheme 3 PSL

The PSL for scheme 3 is identical to that of scheme 1 (see Figure 53).

3.7 Event & fault records

The 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 power systemcondition, switching sequence etc. When the available space is exhausted, the oldestevent 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 or remotely,via the communications ports.

Local viewing on the LCD is achieved in the menu column entitled ‘VIEW RECORDS’.This column allows viewing of event, fault and maintenance records and is shownbelow:

VIEW RECORDS

LCD Reference Description

Select EventSetting range from 0 to 249. This selects the required eventrecord from the possible 250 that may be stored. A value of0 corresponds to the latest event and so on.

Time & Date Time & Date Stamp for the event given by the internal RealTime Clock

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

Event Value Up to 32 Bit Binary Flag representative of the Event (refer tofollowing sections)

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

The following cells show all the fault flags, protection starts,protection trips, fault location, measurements etc. associatedwith the fault, i.e. the complete fault record.


MiCOM P342, P343 Page 153/176

VIEW RECORDS

LCD Reference Description

Select Maint.Setting range from 0 to 4. This selects the requiredmaintenance record from the possible 5 that may be stored.A value of 0 corresponds to the latest record and so on.

Maint. Text Up to 32 Character description of the occurrence (refer tofollowing sections).

Maint. TypeThese cells are numbers representative of the occurrence.They form a specific error code which should be quoted inany related correspondence to AREVA T&D.

Maint. Data

Reset Indication Either Yes or No. This serves to reset the trip LED indicationsprovided that the relevant protection element has reset.

For extraction from a remote source via communications, refer to SCADACommunications (P34x/EN CT/E33), where the procedure is fully explained.

Note that a full list of all the event types and the meaning of their values is given indocument P34x/EN GC/E33.

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:

3.7.1 Change of state of opto-isolated inputs

If one or more of the opto (logic) inputs has changed state since the last time that theprotection algorithm ran, the new status is logged as an event. When this event isselected to be viewed on the LCD, three applicable cells will become visible as shownbelow:

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, wherethe least significant bit (extreme right) corresponds to opto input 1 etc. The sameinformation is present if the event is extracted and viewed via PC.

3.7.2 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 time thatthe protection algorithm ran, then the new status is logged as an event. When thisevent is selected to be viewed on the LCD, three applicable cells will become visibleas shown below:


Page 154/176 MiCOM P342, P343

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. Thesame information is present if the event is extracted and viewed via PC.

3.7.3 Relay alarm conditions

Any alarm conditions generated by the relays will also be logged as individual events.The following table shows examples of some of the alarm conditions and how theyappear in the event list:

Resulting EventAlarm Condition

Event Text Event Value

Alarm Status 1 (Alarms 1-32) (32 bits)

Setting Group Via OptoInvalid

Setting Grp Invalid ON/OFF Bit position 2 in 32 bit field

Protection Disabled Prot’n Disabled ON/OFF Bit position 3 in 32 bit field

Frequency Out of Range Freq out of Range ON/OFF Bit position 13 in 32 bit field

VTS Alarm VT Fail Alarm ON/OFF Bit position 4 in 32 bit field

CB Trip Fail Protection CB Fail ON/OFF Bit position 6 in 32 bit field


SR User Alarm 1-4 (Self Reset) SR User Alarm 1-4 ON/OFF Bit position 17-31 in 32 bitfield

MR User Alarm 5-16 (ManualReset)

MR User Alarm 5-16ON/OFF

Bit position 16-27 in 32 bitfield


Battery Fail Battery Fail ON/OFF Bit position 0 in 32 bit field

Field Voltage Fail Field V Fail ON/OFF Bit position 1 in 32 bit field

The previous table shows the abbreviated description that is given to the variousalarm conditions and also a corresponding value which displays alarms as bitpositions in a 32 bit field. The bit will be set to 1 if the alarm is ON and 0 if it is OFF.This value is appended to each alarm event in a similar way as for the input andoutput events previously described. It is used by the event extraction software, such asMiCOM S1, to identify the alarm and is therefore invisible if the event is viewed onthe LCD. Either ON or OFF is shown after the description to signify whether theparticular condition has become operated or has reset.

The User Alarms can be operated from an opto input or a control input using the PSL.They can thus be useful to give an alarm led and message on the LCD display andan alarm indication via the communications of an external condition, for example tripcircuit supervision alarm, rotor earth fault alarm. The menu text editor in MiCOM S1can be used to edit the user alarm text to give a more meaningful description on theLCD display.


MiCOM P342, P343 Page 155/176

3.7.4 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 operated elementand an event value. Again, this value is intended for use by the event extractionsoftware, such as MiCOM S1, rather than for the user, and is therefore invisible whenthe event is viewed on the LCD.

3.7.5 General events

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

Nature of Event Displayed Text in EventRecord Displayed Value

Level 1 passwordmodified, either from userinterface, front or rear port

PW1 modified UI, F or R 6, 11, 16 respectively

A complete list of the ‘General Events’ is given in document P34x/EN GC/E33.

3.7.6 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 5 records.These records consist of fault flags, fault measurements etc. Also note that the timestamp given in the fault record itself will be more accurate than the correspondingstamp given in the event record as the event is logged some time after the actual faultrecord is generated.

The fault record is triggered from the ‘Fault REC TRIG’ signal assigned in the defaultprogrammable scheme logic to relay 3, protection trip. Note, the fault measurementsin the fault record are given at the time of the protection start. Also, the fault recorderdoes not stop recording until any start or relay 3 (protection trip) resets in order torecord all the protection flags during the fault.

It is recommended that the triggering contact (relay 3 for example) be ‘self reset’ andnot latching. If a latching contact was chosen the fault record would not begenerated until the contact had fully reset.

3.7.7 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 Maint.’ cell at thebottom of the ‘VIEW RECORDS’ column.

Each entry consists of a self explanatory text string and a ‘Type’ and ‘Data’ cell, whichare explained in the menu extract at the beginning of this section and in further detailin document P34x/EN GC/E33.

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.

3.7.8 Setting changes

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


Page 156/176 MiCOM P342, P343

Type of Setting Change Displayed Text in EventRecord Displayed Value

Control/Support Setting C & S Changed 22

Group 1 Change Group 1 Changed 24

Note: Control/Support settings are communications, measurement,CT/VT ratio settings etc. which are not duplicated within the foursetting groups. When any of these settings are changed, theevent record is created simultaneously. However, changes toprotection or disturbance recorder settings will only generate anevent once the settings have been confirmed at the ‘setting trap’.

3.7.9 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.

3.7.10 Viewing event records via MiCOM S1 support software

When the event records are extracted and viewed on a PC they look slightly differentthan when viewed on the LCD. The following shows an example of how variousevents appear when displayed using MiCOM S1:

- Monday 08 January 2001 18:45:28.633 GMT V<1 Trip A/AB ON

ALSTOM : MiCOM P343

Model Number: P343314B2A0020A

Address: 001 Column: 0F Row: 26

Event Type: Setting event

Event Value: 00000001000000000000000000000000

- Monday 08 January 2001 18:45:28.634 GMT Output Contacts

ALSTOM : MiCOM P343


Address: 001 Column: 00 Row: 21

Event Type: Device output changed state

Event Value: 00000000001100

OFF 0 R1 Trip CB

OFF 1 R2 Trip PrimeMov

ON 2 R3 Any Trip

ON 3 R4 General Alarm

OFF 4 R5 CB Fail

OFF 5 R6 E/F Trip

OFF 6 R7 Volt Trip

OFF 7 R8 Freq Trip

OFF 8 R9 Diff Trip


MiCOM P342, P343 Page 157/176

OFF 9 R10 SysBack Trip

OFF 10 R11 NPS Trip

OFF 11 R12 FFail Trip

OFF 12 R13 Power Trip

OFF 13 R14 V/Hz Trip

- Monday 08 January 2001 18:45:28.633 GMT Voltage Prot Alm ON

ALSTOM : MiCOM P343


Address: 001 Column: 00 Row: 22

Event Type: Alarm event

Event Value: 00001000000000000000000000000000

OFF 0 Battery Fail

OFF 1 Field Volt Fail

OFF 2 SG-opto Invalid

OFF 3 Prot'n Disabled

OFF 4 VT Fail Alarm

OFF 5 CT Fail Alarm

OFF 6 CB Fail Alarm

OFF 7 Ι^ Maint Alarm

OFF 8 Ι^ Lockout Alarm

OFF 9 CB OPs Maint

OFF 10 CB OPs Lockout

OFF 11 CB Op Time Maint

OFF 12 CB Op Time Lock

OFF 13 Fault Freq Lock

OFF 14 CB Status Alarm

OFF 15 Not Used

OFF 16 Not Used

OFF 17 Not Used

OFF 18 NPS Alarm

OFF 19 V/Hz Alarm

OFF 20 Field Fail Alarm

OFF 21 RTD Thermal Alm

OFF 22 RTD Open Cct


Page 158/176 MiCOM P342, P343

OFF 23 RTD short Cct

OFF 24 RTD Data Error

OFF 25 RTD Board Fail

OFF 26 Freq Prot Alm

ON 27 Voltage Prot Alm

OFF 28 User Alarm 1

OFF 29 User Alarm 2

OFF 30 User Alarm 3

OFF 31 User Alarm 4

3.7.11 Event filtering

It is possible to disable the reporting of events from any user interface that supportssetting changes. The settings which control the various types of events are in theRecord Control column. The effect of setting each to disabled is as follows:

Alarm Event

None of the occurrences that produce an alarm will result inan event being generated.The presence of any alarms is still reported by the alarm LEDflashing and the alarm bit being set in the communicationsstatus byte.Alarms can still be read using the Read key on the relay frontpanel.

Relay O/P Event No event will be generated for any change in relay outputstate.

Opto Input Event No event will be generated for any change in logic inputstate.

General Event No General Events will be generated.

Fault Rec Event

No event will be generated for any fault that produces a faultrecord.The fault records can still be viewed by operating the “SelectFault” setting in column 0100.

Maint Rec Event

No event will be generated for any occurrence that producesa maintenance record.The maintenance records can still be viewed by operating the“Select Maint” setting in column 0100.

Protection Event Any operation of protection elements will not be logged as anevent.

Note that some occurrences will result in more than one type of event, e.g. a batteryfailure will produce an alarm event and a maintenance record event.

If the Protection Event setting is Enabled a further set of settings is revealed whichallow the event generation by individual DDB signals to be enabled ‘1’ or disabled‘0’.

As can be seen, the first line gives the description and time stamp for the event, whilstthe additional information that is displayed below may be collapsed via the +/–symbol.


MiCOM P342, P343 Page 159/176

For further information regarding events and their specific meaning, refer todocument P34x/EN GC/E33.

3.8 Disturbance recorder

The integral disturbance recorder has an area of memory specifically set aside forrecord storage. The number of records that may be stored by Courier, MODBUS andDNP3.0 relays is dependent upon the selected recording duration but the relaystypically have the capability of storing a minimum of 20 records, each of 10.5 secondduration. VDEW relays, which have an un-compressed disturbance recorder, canonly store 8 records of typically 1.8 seconds at 50 Hz or 8 records of approximately1.5 seconds duration at 60 Hz. Disturbance records continue to be recorded until theavailable memory is exhausted, at which time the oldest record(s) are overwritten tomake space for the newest one.

The recorder stores actual samples which are taken at a rate of 12 samples per cycle.

Each disturbance record consists of eight analogue data channels and thirty-twodigital data channels. Note that the relevant CT and VT ratios for the analoguechannels are also extracted to enable scaling to primary quantities. Note that if a CTratio is set less than unity, the relay will choose a scaling factor of zero for theappropriate channel.

The ‘DISTURBANCE RECORDER’ menu column is shown below:


Min MaxStep Size

DISTURBANCE 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 VANVAN, VBN, VCN, VCHECK SYNC, ΙA, ΙB,

ΙC, ΙN, ΙN SEF

Analog Channel 2 VBN As above

Analog Channel 3 VCN As above

Analog Channel 4 ΙA As above

Analog Channel 5 ΙB As above

Analog Channel 6 ΙC As above

Analog Channel 7 ΙN As above

Analog Channel 8 ΙN SEF As above

Digital Inputs 1 to32

Relays 1 to 7/14Any of 7 or 14 O/P Contacts

and/or Opto’s 1 to 8/16Any of 8 or 16 Opto Inputs

orInternal Digital Signals

Inputs 1 to 32Trigger No Trigger

No Trigger, Trigger L/H exceptDedicated Trigger H/L Trip Relay

O/P’s which are set to Trigger L/H


Page 160/176 MiCOM P342, P343

Note: The available analogue and digital signals will differ betweenrelay types and models and so the individual courier database inSCADA Communications (P34x/EN CT/E33) should be referredto when determining default settings etc.

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 ‘TriggerPosition’ sets the trigger point as a percentage of the duration. For example, thedefault settings show that the overall recording time is set to 1.5s with the triggerpoint being at 33.3% of this, giving 0.5s pre-fault and 1s post fault recording times.

If a further trigger occurs whilst a recording is taking place, the recorder will ignorethe trigger if the ‘Trigger Mode’ has been set to ‘Single’. However, if this has beenset to ‘Extended’, the post trigger timer will be reset to zero, thereby extending therecording time.

As can be seen from the menu, each of the analogue channels is selectable from theavailable analogue 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 trigger thedisturbance recorder on either a low to high or a high to low transition, via the ‘InputTrigger’ cell. The default trigger settings are that any dedicated trip output contacts(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 fully explainedin SCADA Communications (P34x/EN CT/E33).

3.9 Measurements

The relay produces a variety of both directly measured and calculated power systemquantities. These measurement values are updated on a per second basis and aresummarised below:

Phase Voltages and Currents

Phase to Phase Voltage and Currents

Sequence Voltages and currents

Power and Energy Quantities

Rms. Voltages and Currents

Peak, Fixed and Rolling Demand Values

There are also measured values from the protection functions, which also displayedunder the measurement columns of the menu; these are described in the section onthe relevant protection function.

3.9.1 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.


MiCOM P342, P343 Page 161/176

3.9.2 Sequence voltages and currents

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

3.9.3 Power and energy quantities

Using the measured voltages and currents the relay calculates the apparent, real andreactive power quantities. These are produced on a phase by phase basis togetherwith three-phase values based on the sum of the three individual phase values. Thesigning of the real and reactive power measurements can be controlled using themeasurement mode setting. The four options are defined in the table below:

Measurement Mode Parameter Signing

Export Power +

Import Power –

Lagging Vars +0 (Default)

Leading Vars –

Export Power –

Import Power +

Lagging Vars +1

Leading Vars –

Export Power +

Import Power –

Lagging Vars –2

Leading Vars +

Export Power –

Import Power +

Lagging Vars –3

Leading Vars +

In addition to the measured power quantities the relay calculates the power factor ona 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 total exportedand imported energy. The energy measurements are incremented up to maximumvalues of 1000GWhr or 1000GVARhr at which point they will reset to zero, it is alsopossible to reset these values using the menu or remote interfaces using the ResetDemand cell.

3.9.4 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.

3.9.5 Demand values

The relay produces fixed, rolling and peak demand values, using the Reset Demandmenu cell it is possible to reset these quantities via the User Interface or the remotecommunications.


Page 162/176 MiCOM P342, P343

3.9.5.1 Fixed demand values

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

3.9.5.2 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 the sub-periods.

3.9.5.3 Peak demand values

Peak demand values are produced for each phase current and the real and reactivepower quantities. These display the maximum value of the measured quantity sincethe last reset of the demand values.

3.9.6 Settings

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

Measurement Setup Default Value Options/Limits

Default Display DescriptionDescription/Plant Reference/Frequency/Access Level/3Ph + NCurrent/3Ph Voltage/Power/Date and time

Local Values Primary Primary/Secondary

Remote Values Primary Primary/Secondary

Measurement Ref VA VA/VB/VC/ΙA/ΙB/ΙC

Measurement Mode 0 0 to 3 Step 1

Fix Dem Period 30 minutes 1 to 99 minutes step 1 minute

Roll Sub Period 30 minutes 1 to 99 minutes step 1 minute

Num Sub Periods 1 1 to 15 step 1

Distance Unit* Km Km/miles

Fault Location* Distance Distance/Ohms/% of Line

* Note these settings are available for products with integral fault location.

3.9.6.1 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 the defaultdisplay will revert to that selected by this setting.

3.9.6.2 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.


MiCOM P342, P343 Page 163/176

3.9.6.3 Remote values

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

3.9.6.4 Measurement REF

Using this setting the phase reference for all angular measurements by the relay canbe selected.

3.9.6.5 Measurement mode

This setting is used to control the signing of the real and reactive power quantities; thesigning convention used is defined in section 3.9.3.

3.9.6.6 Fixed demand period

This setting defines the length of the fixed demand window.

3.9.6.7 Rolling sub-period and number of sub-periods

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

3.10 Changing setting groups

The setting groups can be changed either via opto inputs or via a menu selection. Inthe Configuration column if 'Setting Group- select via optos' is selected then optos 1and 2, which are dedicated for setting group selection, can be used to select thesetting group as shown in the table below. If 'Setting Group- select via menu' isselected then in the Configuration column the 'Active Settings - Group1/2/3/4' can beused to select the setting group. If this option is used then opto inputs 1 and 2 can beused for other functions in the programmable scheme logic.

OPTO 1 OPTO 2 Selected Setting Group

0 0 1

1 0 2

0 1 3

1 1 4

Note: Setting groups comprise both Settings and Programmable SchemeLogic. Each is independent per group - not shared as common. Thesettings are generated in the Settings and Records application withinMiCOM S1, or can be applied directly from the relay front panel menu.The programmable scheme logic can only be set using the PSL Editorapplication within MiCOM S1, generating files with extension ".psl". It isessential that where the installation needs application-specific PSL, thatthe appropriate .psl file is downloaded (sent) to the relay, for each andevery setting group that will be used. If the user fails to download therequired .psl file to any setting group that may be brought into service,then factory default PSL will still be resident. This may have severeoperational and safety consequences.


Page 164/176 MiCOM P342, P343

3.11 Control inputs

Menu Text Default Setting Setting Range Step Size

CONTROL INPUTS

Ctrl I/P Status 00000000000000000000000000000000

Control Input 1 No Operation No Operation, Set, Reset

Control Input 2to 32 No Operation No Operation, Set, Reset

The Control Input commands can be found in the ‘Control Input’ menu. In the ‘CtrlΙ/P status’ menu cell there is a 32 bit word which represent the 32 control inputcommands. The status of the 32 control inputs can be read from this 32 bit word.The 32 control inputs can also be set and reset from this cell by setting a 1 to set or 0to reset a particular control input. Alternatively, each of the 32 Control Inputs cancan be set and reset using the individual menu setting cells ‘Control Input 1, 2, 3, etc.The Control Inputs are available through the relay menu as described above and alsovia the rear communications.

In the programmable scheme logic editor 32 Control Input signals, DDB 832-863,which can be set to a logic 1 or On state, as described above, are available toperform control functions defined by the user.

The status of the Control Inputs are held in non-volatile memory (battery backedRAM) such that when the relay is power-cycled, the states are restored upon power-up.

3.12 VT connections

3.12.1 Open delta (vee connected) VT's

The P342/3 relay can be used with vee connected VTs by connecting the VTsecondaries to C19, C20 and C21 input terminals, with the C22 input leftunconnected (see Figures 2 and 17 in document P34x/EN CO/E33).

This type of VT arrangement cannot pass zero-sequence (residual) voltage to therelay, or provide any phase to neutral voltage quantities. Therefore any protectionthat is dependent upon zero sequence voltage measurements should be disabledunless a direct measurement can be made via the measured VN input (C23-C24).Therefore, neutral displacement protection, sensitive directional earth fault protectionand CT supervision should be disabled unless the residual voltage is measureddirectly from the secondary of the earthing transformer or from a broken delta VTwinding on a 5 limb VT.

The under and over voltage protection can be set as phase-to-phase measurementwith vee connected VTs. The underimpedance and the voltage dependentovercurrent use phase-phase voltages anyway, therefore the accuracy should not beaffected. The protection functions which use phase-neutral voltages are the power,the loss of excitation and pole slipping protection; all are for detecting abnormalgenerator operation under 3-phase balanced conditions, therefore the 'neutral' point,although 'floating' will be approximately at the centre of the three phase voltagevectors.

The accuracy of single phase voltage measurements can be impaired when using veeconnected VT’s. The relay attempts to derive the phase to neutral voltages from thephase to phase voltage vectors. If the impedance of the voltage inputs were perfectlymatched the phase to neutral voltage measurements would be correct, provided the


MiCOM P342, P343 Page 165/176

phase to phase voltage vectors were balanced. However, in practice there are smalldifferences in the impedance of the voltage inputs, which can cause small errors inthe phase to neutral voltage measurements. This may give rise to an apparentresidual voltage. This problem also extends to single phase power and impedancemeasurements that are also dependent upon their respective single phase voltages.

The phase to neutral voltage measurement accuracy can be improved by connecting3, well matched, load resistors between the phase voltage inputs (C19, C20, C21)and neutral C22, thus creating a ‘virtual’ neutral point. The load resistor values mustbe chosen so that their power consumption is within the limits of the VT. It isrecommended that 10kΩ ±1% (6W) resistors are used for the 110V (Vn) rated relay,assuming the VT can supply this burden.

3.12.2 VT single point earthing

The P340 range will function correctly with conventional 3 phase VT’s earthed at anyone point on the VT secondary circuit. Typical earthing examples being neutralearthing and yellow phase earthing.

3.13 PSL DATA column

The MiCOM P34x range of relays contains a PSL DATA column that can be used totrack PSL modifications. A total of 12 cells are contained in the PSL DATA column, 3for each setting group. The function for each cell is shown below:

Grp PSL Ref When downloading a PSL to the relay, the user will beprompted to enter which groups the PSL is for and areference ID. The first 32 characters of the reference IDwill be displayed in this cell. The and keys can beused to scroll through 32 characters as only 16 can bedisplayed at any one time.

18 Nov 2002

08:59:32.047

This cell displays the date and time when the PSL wasdown loaded to the relay.

Grp 1 PSL ID- 2062813232

This is a unique number for the PSL that has been entered.Any change in the PSL will result in a different numberbeing displayed.

Note: The above cells are repeated for each setting group.

3.14 Auto reset of trip LED indication

The trip LED can be reset when the flags for the last fault are displayed. The flags aredisplayed automatically after a trip occurs, or can be selected in the fault recordmenu. The reset of trip LED and the fault records is performed by pressing the keyonce the fault record has been read.

Setting “Sys Fn Links” (SYSTEM DATA Column) to logic “1” sets the trip LED toautomatic reset. Resetting will occur when the circuit is reclosed and the “Any PoleDead” signal (DDB 758) has been reset for three seconds. Resetting, however, willbe prevented if the “Any start” signal is active after the breaker closes.


Page 166/176 MiCOM P342, P343

*,F

F7,F

,F

*!&0*10 $$10,'%1

F**7:;F,FF*

G !<

M

Figure 58: Trip LED logic diagram

4. CURRENT TRANSFORMER REQUIREMENTS

The current transformer requirements for each current input will depend on theprotection function with which they are related and whether the line currenttransformers are being shared with other current inputs. Where current transformersare being shared by multiple current inputs, the kneepoint voltage requirementsshould be calculated for each input and the highest calculated value used.

The P342/3 is able to maintain all protection functions in service over a wide rangeof operating frequency due to its frequency tracking system (5-70 Hz).

When the P342/3 protection functions are required to operate accurately at lowfrequency, it will be necessary to use CT’s with larger cores. In effect, the CTrequirements need to be multiplied by fn/f, where f is the minimum requiredoperating frequency and fn is the nominal operating frequency.

4.1 Generator differential function

4.1.1 Biased differential protection

The kneepoint voltage requirements for the current transformers used for the currentinputs of the generator differential function, with settings of Ιs1 = 0.05Ιn, k1 = 0%,Ιs2 = 1.2Ιn, k2 = 150%, and with a boundary condition of through fault current ≤ 10Ιn, is:

Vk ≥ 50Ιn (Rct + 2RL + Rr) with a minimum of 60

Ιn for X/R <120


Ιn for X/R < 40

Where the generator is impedance earthed and the maximum secondary earth faultcurrent is less than Ιn then the CT knee point voltage requirements are:


Ιn for X/R <120

where

Vk = Minimum current transformer kneepoint voltage for through faultstability.


MiCOM P342, P343 Page 167/176

Ιn = Relay rated current.

Rct = Resistance of current transformer secondary winding (Ω).

RL = Resistance of a single lead from relay to current transformer (Ω).

Rr = Resistance of any other protective relays sharing the currenttransformer (Ω).

For Class-X current transformers, the excitation current at the calculated kneepointvoltage requirement should be less than 2.5Ιn (<5% of the maximum perspective faultcurrent 50 Ιn, on which these CT requirements are based). For IEC standardprotection class current transformers, it should be ensured that class 5P are used.

4.1.2 High impedance differential protection

If the generator differential protection function is to be used to implement highimpedance differential protection, then the current transformer requirements will beas follows:

Rs = [1.5 * (Ιf) * (RCT + 2RL)] /ΙS1

VK ≥ 2 * Ιs1 * Rs

where

Rs = Value of stabilising resistor (ohms)

Ιf = Maximum through fault current level (amps)

VK = CT knee point voltage (volts)

ΙS1 = Current setting of differential element (amps)

RCT = Resistance of current transformer secondary winding (ohms)

RL = Resistance of a single lead from relay to current transformer (ohms)

4.2 Voltage dependent overcurrent, field failure and negative phase sequenceprotection functions

When determining the current transformer requirements for an input that suppliesseveral protection functions, it must be ensured that the most onerous condition ismet. This has been taken into account in the formula given below. The formula isequally applicable for current transformers mounted at either the neutral-tail end orterminal end of the generator.

Vk ≥ 20Ιn (Rct + 2RL + Rr)

where







Page 168/176 MiCOM P342, P343

For class-X current transformers, the excitation current at the calculated kneepointvoltage requirement should be less than 1.0Ιn. For IEC standard protection classcurrent transformers, it should be ensured that class 5P are used.

4.3 Sensitive directional earth fault protection function residual current input

4.3.1 Line current transformers

With reference to section 2.15, the sensitive directional earth fault input currenttransformer could be driven by three residually connected line current transformers.

It has been assumed that the sensitive directional earth fault protection function willonly be applied when the stator earth fault current is limited to the stator windingrated current or less. Also assumed is that the maximum X/R ratio for the impedanceto a bus earth fault will be no greater than 10. The required minimum kneepointvoltage will therefore be:

Vk ≥ 6 Ιn (Rct + 2RL + Rr)

where






For class-X current transformers, the excitation current at the calculated kneepointvoltage requirement should be less than 0.3Ιn (<5% of the maximum perspective faultcurrent 20Ιn, on which these CT requirements are based). For IEC standardprotection class current transformers, it should be ensured that class 5P are used.

4.3.2 Core balanced current transformers

Unlike a line current transformer, the rated primary current for a core balancedcurrent transformer may not be equal to the stator winding rated current. This hasbeen taken into account in the formula:

Vk > 6NΙn (Rct + 2RL + Rr)

where


N =Stator earth fault current

Core balanced current transformer rated primary current





MiCOM P342, P343 Page 169/176


Note: N should not be greater than 2. The core balance currenttransformer ratio should be selected accordingly.

4.4 Stator earth fault protection function

The earth fault Ιn current input is used by the stator earth fault protection function.

4.4.1 Non-directional definite time/IDMT earth fault protection

CT requirements for time-delayed earth fault overcurrent elements

VK ≥ Ιcn/2 * (RCT + 2RL + Rrn)

4.4.2 Non-directional instantaneous earth fault protection

CT requirements for instantaneous earth fault overcurrent elements

VK ≥ Ιsn (RCT + 2RL + Rrn)

where

VK = Required CT knee-point voltage (volts),

Ιcn = Maximum prospective secondary earth fault current or 31 times Ι> setting (whichever is lower) (amps),

Ιsn = Earth fault setting (amps),


RL = Resistance of a single lead from relay to current transformer (ohms),

Rrn = Impedance of the relay neutral current input at Ιn (ohms).

4.5 Restricted earth fault protection

4.5.1 Low impedance

VK ≥ 24 * Ιn * (RCT + 2RL) for X/R < 40 and Ιf < 15Ιn

VK ≥ 48 * Ιn * (RCT + 2RL) for X/R < 40, 15Ιn < Ιf < 40Ιn

and 40 <X/R < 120, Ιf < 15Ιn

where

Vk = VA x ALF

Ιn + ALF x Ιn x Rct

VK = Required CT knee point voltage (volts),

Ιn = rated secondary current (amps),

RCT = Resistance of current transformer secondary winding (Ω)

RL = Resistance of a single lead from relay to current transformer (Ω)

Ιf = Maximum through fault current level (amps).


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4.5.2 High impedance

The High Impedance Restricted Earth Fault element shall maintain stability forthrough faults and operate in less than 40ms for internal faults provided the followingequations are met in determining CT requirements and the value of the associatedstabilising resistor:

Rs = [0.7 * (Ιf) * (RCT + 2RL)] /ΙS1

VK ≥ 4 * Ιs1 * Rs

where

Rs = Value of Stabilising resistor (ohms),

Ιf = Maximum through fault current level (amps).

VK = CT knee point voltage (volts),

ΙS1 = Current setting of REF element (amps),


RL = Resistance of a single lead from relay to current transformer (ohms).

4.6 Reverse and low forward power protection functions

For both reverse and low forward power protection function settings greater than 3%Pn, the phase angle errors of suitable protection class current transformers will notresult in any risk of mal-operation or failure to operate. However, for the sensitivepower protection if settings less than 3% are used, it is recommended that the currentinput is driven by a correctly loaded metering class current transformer.

4.6.1 Protection class current transformers

For less sensitive power function settings (>3%Pn), the phase current input of theP340 should be driven by a correctly loaded class 5P protection current transformer.

To correctly load the current transformer, its VA rating should match the VA burden(at rated current) of the external secondary circuit through which it is required to drivecurrent.

4.6.2 Metering class current transformers

For low Power settings (<3%Pn), the Ιn Sensitive current input of the P340 should bedriven by a correctly loaded metering class current transformer. The currenttransformer accuracy class will be dependent on the reverse power and low forwardpower sensitivity required. The table below indicates the metering class currenttransformer required for various power settings below 3%Pn.

To correctly load the current transformer, its VA rating should match the VA burden(at rated current) of the external secondary circuit through which it is required to drivecurrent. Use of the P340 sensitive power phase shift compensation feature will helpin this situation.


MiCOM P342, P343 Page 171/176

Reverse and Low Forward PowerSettings %Pn Metering CT Class

0.5

0.60.1

0.8

1.0

1.2

1.4

0.2

1.6

1.8

2.0

2.2

2.4

2.6

2.8

0.5

3.0 1.0

Sensitive power current transformer requirements

4.7 Converting an IEC185 current transformer standard protection classificationto a kneepoint voltage

The suitability of an IEC standard protection class current transformer can be checkedagainst the kneepoint voltage requirements specified previously.

If, for example, the available current transformers have a 15VA 5P 10 designation,then an estimated kneepoint voltage can be obtained as follows:

Vk = VA x ALF

Ιn + ALF x Ιn x Rct

where

Vk = Required kneepoint voltage

VA = Current transformer rated burden (VA)

ALF = Accuracy limit factor

Ιn = Current transformer secondary rated current (A)

Rct = Resistance of current transformer secondary winding (Ω)

If Rct is not available, then the second term in the above equation can be ignored.

Example: 400/5A, 15VA 5P 10, Rct = 0.2Ω

Vk =15 x 10

5 + 10 x 5 x 0.2

= 40V


Page 172/176 MiCOM P342, P343

4.8 Converting IEC185 current transformer standard protection classification toan ANSI/IEEE standard voltage rating

MiCOM Px40 series protection is compatible with ANSI/IEEE current transformers asspecified in the IEEE C57.13 standard. The applicable class for protection is class"C", which specifies a non air-gapped core. The CT design is identical to IEC class P,or British Standard class X, but the rating is specified differently.

The ANSI/IEEE “C” Class standard voltage rating required will be lower thanan IEC knee point voltage. This is because the ANSI/IEEE voltage rating isdefined in terms of useful output voltage at the terminals of the CT, whereasthe IEC knee point voltage includes the voltage drop across the internalresistance of the CT secondary winding added to the useful output. TheIEC/BS knee point is also typically 5% higher than the ANSI/IEEE knee point.

Therefore

Vc = [ Vk - Internal voltage drop ] / 1.05

= [ Vk - (In . RCT . ALF) ] / 1.05

Where

Vc = “C” Class standard voltage rating

Vk = IEC Knee point voltage required

Ιn = CT rated current = 5A in USA

RCT = CT secondary winding resistance

(for 5A CTs, the typical resistance is 0.002 ohms/secondary turn)

ALF = The CT accuracy limit factor, the rated dynamic current output of a "C" class CT (Kssc) is always 20 x In

The IEC accuracy limit factor is identical to the 20 times secondary current ANSI/IEEErating.

Therefore

Vc = [ Vk - (100 . RCT ) ] / 1.05

5. COMMISSIONING TEST MENU

To help minimise the time required to test MiCOM relays the relay provides severaltest facilities under the ‘COMMISSION TESTS’ menu heading. There are menu cellswhich allow the status of the opto-isolated inputs, output relay contacts, internaldigital data bus (DDB) signals and user-programmable LEDs to be monitored.Additionally there are cells to test the operation of the output contacts and user-programmable LEDs.

The following table shows the relay menu of commissioning tests, including theavailable setting ranges and factory defaults:


MiCOM P342, P343 Page 173/176

Menu Text Default Setting Settings

COMMISSION TESTS

Opto I/P Status - -

Relay O/P Status - -

Test Port Status - -

LED Status - -

Monitor Bit 1 64 (LED 1)




0 to 511

See documentP34x/EN GC/E33 fordetails of digital databus signals





Test Mode DisabledDisabledTest ModeContacts Blocked

Test Pattern All bits set to 0 0 = Not Operated1 = Operated

Contact Test No OperationNo OperationApply TestRemove Test

Test LEDs No Operation No OperationApply Test

Table 37

5.1 Opto I/P status

This menu cell displays the status of the relay’s opto-isolated inputs as a binary string,a ‘1’ indicating an energised opto-isolated input and a ‘0’ a de-energised one. If thecursor is moved along the binary numbers the corresponding label text will bedisplayed for each logic input.

It can be used during commissioning or routine testing to monitor the status of theopto-isolated inputs whilst they are sequentially energised with a suitable dc voltage.

5.2 Relay O/P status

This menu cell displays the status of the digital data bus (DDB) signals that result inenergisation of the output relays as a binary string, a ‘1’ indicating an operated stateand ‘0’ a non-operated state. If the cursor is moved along the binary numbers thecorresponding label text will be displayed for each relay output.

The information displayed can be used during commissioning or routine testing toindicate the status of the output relays when the relay is ‘in service’. Additionally faultfinding for output relay damage can be performed by comparing the status of theoutput contact under investigation with it’s associated bit.


Page 174/176 MiCOM P342, P343

Note: When the ‘Test Mode’ cell is set to ‘Enabled’ this cell willcontinue to indicate which contacts would operate if the relaywas in-service, it does not show the actual status of the outputrelays.

5.3 Test port status

This menu cell displays the status of the eight digital data bus (DDB) signals that havebeen allocated in the ‘Monitor Bit’ cells. If the cursor is moved along the binarynumbers the corresponding DDB signal text string will be displayed for each monitorbit.

By using this cell with suitable monitor bit settings, the state of the DDB signals can bedisplayed as various operating conditions or sequences are applied to the relay.Thus the programmable scheme logic can be tested.

As an alternative to using this cell, the optional monitor/download port test box canbe plugged into the monitor/download port located behind the bottom access cover.Details of the monitor/download port test box can be found in section 5.10 of thisdocument (P34x/EN AP/E33).

5.4 LED status

The ‘LED Status’ cell is an eight bit binary string that indicates which of theuser-programmable LEDs on the relay are illuminated when accessing the relay froma remote location, a ‘1’ indicating a particular LED is lit and a ‘0’ not lit.

5.5 Monitor bits 1 to 8

The eight ‘Monitor Bit’ cells allow the user to select the status of which digital data bussignals can be observed in the ‘Test Port Status’ cell or via the monitor/downloadport.

Each ‘Monitor Bit’ is set by entering the required digital data bus (DDB) signalnumber (0 – 511) from the list of available DDB signals in document P34x/ENGC/E33 of this guide. The pins of the monitor/download port used for monitor bitsare given in the table overleaf. The signal ground is available on pins 18, 19, 22and 25.

Monitor Bit 1 2 3 4 5 6 7 8

Monitor/ Download Port Pin 11 12 15 13 20 21 23 24

Table 38

THE MONITOR/DOWNLOAD PORT DOES NOT HAVE ELECTRICAL ISOLATEDAGAINST INDUCED VOLTAGES ON THE COMMUNICATIONS CHANNEL. ITSHOULD THEREFORE ONLY BE USED FOR LOCAL COMMUNICATIONS.

5.6 Test mode

This menu cell is used to allow secondary injection testing to be performed on therelay without operation of the trip contacts. It also enables a facility to directly test theoutput contacts by applying menu controlled test signals. To select test mode this cellshould be set to ‘Enabled’ which takes the relay out of service causing an alarmcondition to be recorded and the yellow ‘Out of Service’ LED to illuminate. Oncetesting is complete the cell must be set back to ‘Disabled’ to restore the relay back toservice.


MiCOM P342, P343 Page 175/176

WHEN THE ‘TEST MODE’ CELL IS SET TO ‘ENABLED’ THE RELAY SCHEMELOGIC DOES NOT DRIVE THE OUTPUT RELAYS AND HENCE THEPROTECTION WILL NOT TRIP THE ASSOCIATED CIRCUIT BREAKER IF A FAULTOCCURS.

HOWEVER, THE COMMUNICATIONS CHANNELS WITH REMOTE RELAYSREMAIN ACTIVE WHICH, IF SUITABLE PRECAUTIONS ARE NOT TAKEN,COULD LEAD TO THE REMOTE ENDS TRIPPING WHEN CURRENTTRANSFORMERS ARE ISOLATED OR INJECTION TESTS ARE PERFORMED.

5.7 Test pattern

The ‘Test Pattern’ cell is used to select the output relay contacts that will be testedwhen the ‘Contact Test’ cell is set to ‘Apply Test’. The cell has a binary string withone bit for each user-configurable output contact which can be set to ‘1’ to operatethe output under test conditions and ‘0’ to not operate it.

5.8 Contact test

When the ‘Apply Test’ command in this cell is issued the contacts set for operation(set to ‘1’) in the ‘Test Pattern’ cell change state. After the test has been applied thecommand text on the LCD will change to ‘No Operation’ and the contacts will remainin the Test State until reset issuing the ‘Remove Test’ command. The command text onthe LCD will again revert to ‘No Operation’ after the ‘Remove Test’ command hasbeen issued.

Note: When the ‘Test Mode’ cell is set to ‘Enabled’ the ‘Relay O/PStatus’ cell does not show the current status of the output relaysand hence can not be used to confirm operation of the outputrelays. Therefore it will be necessary to monitor the state of eachcontact in turn.

5.9 Test LEDs

When the ‘Apply Test’ command in this cell is issued the eight user-programmableLEDs will illuminate for approximately 2 seconds before they extinguish and thecommand text on the LCD reverts to ‘No Operation’.

5.10 Using a monitor/download port test box

A monitor/download port test box containing 8 LED’s and a switchable audibleindicator is available from AREVA T&D, or one of their regional sales offices. It ishoused in a small plastic box with a 25-pin male D-connector that plugs directly intothe relay’s monitor/download port. There is also a 25-pin female D-connector whichallows other connections to be made to the monitor/download port whilst themonitor/download port test box is in place.

Each LED corresponds to one of the monitor bit pins on the monitor/download portwith ‘Monitor Bit 1’ being on the left hand side when viewing from the front of therelay. The audible indicator can either be selected to sound if a voltage appears anyof the eight monitor pins or remain silent so that indication of state is by LED alone.


Page 176/176 MiCOM P342, P343


MiCOM P342, P343

RELAY DESCRIPTION

P34x/EN HW/F33 Relay Description

MiCOM P342, P343



CONTENT

1. RELAY SYSTEM OVERVIEW 3

1.1 Hardware overview 3

1.1.1 Processor board 3

1.1.2 Input module 3

1.1.3 Power supply module 3

1.1.4 RTD board 3

1.1.5 IRIG-B board 3

1.1.6 Second rear comms board 3

1.2 Software overview 4

1.2.1 Real-time operating system 5

1.2.2 System services software 5

1.2.3 Platform software 5

1.2.4 Protection and control software 5

1.2.5 Disturbance recorder 5

2. HARDWARE MODULES 5

2.1 Processor board 5

2.2 Internal communication buses 6

2.3 Input module 6

2.3.1 Transformer board 6

2.3.2 Input board 6

2.3.3 Universal opto isolated logic inputs 8

2.4 Power supply module (including output relays) 8

2.4.1 Power supply board (including EIA(RS)485 communication interface) 8

2.4.2 Output relay board 9

2.5 RTD board 9

2.6 IRIG-B board 9

2.7 Mechanical layout 10

2.8 Second rear communications board 10

2.9 Current loop input output board (CLIO) 11

3. RELAY SOFTWARE 13

3.1 Real-time operating system 13



3.2 System services software 13

3.3 Platform software 14

3.3.1 Record logging 14

3.3.2 Settings database 14

3.3.3 Database interface 14

3.4 Protection & control software 14

3.4.1 Overview - protection & control scheduling 15

3.4.2 Signal processing 15

3.4.3 Programmable scheme logic 16

3.4.3.1 PSL data 16

3.4.4 Event, fault & maintenance recording 16

3.4.5 Disturbance recorder 17

4. SELF TESTING & DIAGNOSTICS 17

4.1 Start-up self-testing 18

4.1.1 System boot 18

4.1.2 Initialisation software 18

4.1.3 Platform software initialisation & monitoring 18

4.2 Continuous self-testing 19

Figure 1: Relay modules and information flow 4

Figure 2: Main input board 7

Figure 3: Second rear comms port 11

Figure 4: Current loop input output board 12

Figure 5: Relay software structure 13



1. RELAY SYSTEM OVERVIEW

1.1 Hardware overview

The relay hardware is based on a modular design whereby the relay is made up ofan assemblage of several modules which are drawn from a standard range. Somemodules are essential while others are optional depending on the user’srequirements.

The different modules that can be present in the relay are as follows:

1.1.1 Processor board

The processor board performs all calculations for the relay and controls the operationof all other modules within the relay. The processor board also contains and controlsthe user interfaces (LCD, LEDs, keypad and communication interfaces).

1.1.2 Input module

The input module converts the information contained in the analogue and digitalinput signals into a format suitable for processing by the processor board. Thestandard input module consists of two boards: a transformer board to provideelectrical isolation and a main input board which provides analogue to digitalconversion and the isolated digital inputs.

1.1.3 Power supply module

The power supply module provides a power supply to all of the other modules in therelay, at three different voltage levels. The power supply board also provides theEIA(RS)485 electrical connection for the rear communication port. On a secondboard the power supply module contains the relays which provide the outputcontacts.

1.1.4 RTD board

This optional board can be used to process the signals from up to 10 resistancetemperature detectors (RTDs) to measure the winding and ambient temperatures.

1.1.5 IRIG-B board

This board, which is optional, can be used where an IRIG-B signal is available toprovide an accurate time reference for the relay. There is also an option on thisboard to specify a fibre optic rear communication port, for use with IEC60870communication only.

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.

1.1.6 Second rear comms board

The optional second rear port is designed typically for dial-up modem access byprotection engineers/operators, when the main port is reserved for SCADA traffic.Communication is via one of three physical links: K-Bus, EIA(RS)485 or EIA(RS)232.The port supports full local or remote protection and control access by MiCOM S1software.



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Figure 1: Relay modules and information flow

1.2 Software overview

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:



1.2.1 Real-time operating system

The real-time operating system is used to provide a framework for the different partsof the relay’s software to operate within. To this end the software is split into tasks.The real-time operating system is responsible for scheduling the processing of thesetasks such that they are carried out in the time available and in the desired order ofpriority. The operating system is also responsible for the exchange of informationbetween tasks, in the form of messages.

1.2.2 System services software

The system services software provides the low-level control of the relay hardware. Forexample, the system services software controls the boot of the relay’s software fromthe non-volatile flash EPROM memory at power-on, and provides driver software forthe user interface via the LCD and keypad, and via the serial communication ports.The system services software provides an interface layer between the control of therelay’s hardware and the rest of the relay software.

1.2.3 Platform software

The platform software deals with the management of the relay settings, the userinterfaces and logging of event, alarm, fault and maintenance records. All of therelay settings are stored in a database within the relay which provides directcompatibility with Courier communications. For all other interfaces (i.e. the frontpanel keypad and LCD interface, Modbus, IEC60870-5-103 and DNP3.0) 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 & control software.

1.2.4 Protection and control software

The protection and control software performs the calculations for all of the protectionalgorithms of the relay. This includes digital signal processing such as Fourierfiltering and ancillary tasks such as the disturbance recorder. The protection &control software interfaces with the platform software for settings changes andlogging of records, and with the system services software for acquisition of sampledata and access to output relays and digital opto-isolated inputs.

1.2.5 Disturbance recorder

The disturbance recorder software is passed the sampled analogue values and logicsignals from the protection and control software. This software compresses the datato allow a greater number of records to be stored. The platform software interfacesto the disturbance recorder to allow extraction of the stored records.

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 board

The 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, keypadand LEDs.



The processor board is located directly behind the relay’s front panel which allows theLCD and LEDs to be mounted on the processor board along with the front panelcommunication ports. These comprise the 9-pin D-connector for EIA(RS)232 serialcommunications (e.g. using MiCOM S1 and Courier communications) and the 25-pinD-connector relay test port for parallel communication. All serial communication ishandled using a two-channel 85C30 serial communications controller (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 of softwarecode and text together with default settings, 256kB of battery backed-up SRAM for thestorage of disturbance, event, fault and maintenance record data, and 32kB ofE2PROM memory for the storage of configuration data, including the present settingvalues.

2.2 Internal communication buses

The 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. Theribbon cable carries the data and address bus signals in addition to control signalsand all power supply lines. Operation of the bus is driven by the main processorboard which operates as a master while all other modules within the relay are slaves.

The second bus is a serial link which is used exclusively for communicating the digitalsample 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 module

The input module provides the interface between the relay processor board(s) and theanalogue and digital signals coming into the relay. The input module of P342consists of two PDBs; the main input board and the transformer board. This relayprovides four voltage inputs and five current inputs. The P343 input module containsan additional transformer board, providing a total of four voltage inputs and eightcurrent 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 (menu andwiring options) and the voltage inputs can be specified for either 110V or 440Vnominal voltage (order option). The transformers are used both to step-down thecurrents and voltages to levels appropriate to the relay’s electronic circuitry and toprovide effective isolation between the relay and the power system. The connectionarrangements of both the current and voltage transformer secondaries providedifferential input signals to the main input board to reduce noise.

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 board theanalogue signals are passed through an anti-alias filter before being multiplexed into



a single analogue-to-digital converter chip. The A-D converter provides 16-bitresolution and a serial data stream output. The digital input signals are opticallyisolated on this board to prevent excessive voltages on these inputs causing damageto the relay's internal circuitry.

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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 multiplexer andthe accuracy of the A-D converter. The sample rate is maintained at 24 samples percycle of the power waveform by a logic control circuit which which is driven by thefrequency tracking function on the main processor board. The calibration E2PROMholds the calibration coefficients which are used by the processor board to correct forany amplitude or phase error introduced by the transformers and analogue circuitry.

The other function of the input board is to read the state of the signals present on thedigital 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 input signals.The opto-isolators are used with the digital signals for the same reason as thetransformers with the analogue signals; to isolate the relay’s electronics from thepower system environment. A 48V ‘field voltage’ supply is provided at the back ofthe relay for use in driving the digital opto-inputs. The input board provides somehardware filtering of the digital signals to remove unwanted noise before bufferingthe signals for reading on the parallel data bus. Depending on the relay model,more than 8 digital input signals can be accepted by the relay. This is achieved bythe use of an additional opto-board which contains the same provision for 8 isolateddigital inputs as the main input board, but does not contain any of the circuits foranalogue signals which are provided on the main input board.



2.3.3 Universal opto isolated logic inputs

The P340 series relays are fitted with universal opto isolated logic inputs that can beprogrammed for the nominal battery voltage of the circuit of which they are a part.They nominally provide a Logic 1 or On value for Voltages ≥80% of the set lowernominal voltage and a Logic 0 or Off value for the voltages ≤60% of the set highernominal voltage. This lower value eliminates fleeting pickups that may occur duringa battery earth fault, when stray capacitance may present up to 50% of batteryvoltage across an input.

Each input also has a pre-set filter of ½ cycle which renders the input immune toinduced noise on the wiring: although this method is secure it can be slow,particularly for intertripping.

For the P342 and P343 generator protection relays, the protection task is executedfour times per cycle, i.e. after every 6 samples for the sample rate of 24 samples perpower cycle used by the relay. Therefore, the time taken to register a change in thestate of an opto input can vary between a half to three quarters of a cycle. The timeto register the change of state will depend on if the opto input changes state at thestart or end of a protection task cycle with the additional half cycle filtering time.

In the Opto Config menu the nominal battery voltage can be selected for all optoinputs by selecting one of the five standard ratings in the Global Nominal V settings.If Custom is selected then each opto input can individually be set to a nominalvoltage value.


Min MaxStep Size

OPTO CONFIG

Global Nominal V 24-27 24-27, 30-34, 48-54, 110-125, 220-250,Custom

Opto Input 1 24-27 24-27, 30-34, 48-54, 110-125, 220-250

Opto Input 2-32 24-27 24-27, 30-34, 48-54, 110-125, 220-250

2.4 Power supply module (including output relays)

The power supply module contains two PCBs, one for the power supply unit itself andthe other for the output relays. The power supply board also contains the input andoutput hardware for the rear communication port which provides an EIA(RS)485communication interface.

2.4.1 Power supply board (including EIA(RS)485 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 Range

24/48V dc only

48/110V 30/100Vrms

110/250V 100/240Vrms

Table 1: Power supply options



The output from all versions of the power supply module are used to provide isolatedpower supply rails to all of the other modules within the relay. Three voltage levelsare used within the relay, 5.1V for all of the digital circuits, ±16V for the analogueelectronics, e.g. on the input board, and 22V for driving the output relay coils and theRTD board if fitted. All power supply voltages including the 0V earth line aredistributed around the relay via the 64-way ribbon cable. One further voltage level isprovided by the power supply board which is the field voltage of 48V. This is broughtout to terminals on the back of the relay so that it can be used to drive the opticallyisolated digital inputs.

The two other functions provided by the power supply board are the EIA(RS)485communications interface and the watchdog contacts for the relay. The EIA(RS)485interface is used with the relay’s rear communication port to provide communicationusing one of either Courier, Modbus, or IEC60870-5-103, DNP3.0 protocols. TheEIA(RS)485 hardware supports half-duplex communication and provides opticalisolation 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 and onenormally closed which are driven by the main processor board. These are providedto give an indication that the relay is in a healthy state.

2.4.2 Output relay board

There are 2 versions of the output relay board one with seven relays, three normallyopen contacts and four changeover contacts and one with eight relays, six normallyopen contacts and two changeover contacts.

For relay models with suffix A hardware, only the 7 output relay boards wereavailable. For equivalent relay models in suffix B hardware or greater the basenumbers of output contacts, using the 7 output relay boards, is being maintained forcompatibility. The 8 output relay board is only used for new relay models or existingrelay models available in new case sizes or to provide additional output contacts toexisting models for suffix issue B or greater hardware. Note, the model number suffixletter refers to the hardware version.

The relays are driven from the 22V power supply line. The relays’ state is written toor read from using the parallel data bus. Depending on the relay model, more thanseven output contacts may be provided, through the use of up to three extra relayboards. Each additional relay board provides a further seven or eight output relays.

2.5 RTD board

The RTD (Resistance Temperature Detector) board is an order option. It is used tomonitor the temperature readings from up to ten PT100 RTDs which are eachconnected using a 3-wire connection. The board is powered from the 22V power railthat is used to drive the output relays. The RTD board includes two redundantchannels which are connected to high stability resistors to provide reference readings.These are used to check the operation of the RTD board. The temperature data isread by the processor via the parallel data bus, and is used to provide thermalprotection of the generator windings.

2.6 IRIG-B board

The IRIG-B board is an order option which can be fitted to provide an accurate timingreference for the relay. This can be used wherever an IRIG-B signal is available. TheIRIG-B signal is connected to the board via a BNC connector on the back of the relay.The timing information is used to synchronise the relay’s internal real-time clock to an



accuracy of 1ms. The internal clock is then used for the time tagging of the event,fault maintenance and disturbance records.

The IRIG-B board can also be specified with a fibre optic transmitter/receiver whichcan be used for the rear communication port instead of the EIA(RS)485 electricalconnection (IEC60870 only).

2.7 Mechanical layout

The case materials of the relay are constructed from pre-finished steel which has aconductive covering of aluminium and zinc. This provides good earthing at all jointsgiving a low impedance path to earth which is essential for performance in thepresence 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-pinand 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 LCD and12 LEDs mounted on an aluminium backing plate.

2.8 Second rear communications board

For relays with Courier, Modbus, IEC60870-5-103 or DNP3 protocol on the first rearcommunications port there is the hardware option of a second rear communicationsport, which will run the Courier language. This can be used over one of threephysical links: twisted pair K-Bus (non polarity sensitive), twisted pair EIA(RS)485(connection polarity sensitive) or EIA(RS)232.

The second rear comms board and IRIG-B board are mutually exclusive since theyuse the same hardware slot. For this reason two versions of second rear commsboard are available; one with an IRIG-B input and one without. The physical layoutof the second rear comms board is shown in Figure 3.



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2.9 Current loop input output board (CLIO)

The current loop input output (CLIO) board is an order option. The CLIO board ispowered from the 22V power rail that is used to drive the output relays.

Four analogue (or current loop) inputs are provided for transducers with ranges of0-1mA, 0-10mA, 0-20mA or 4-20mA. The input current data is read by theprocessor via the parallel data bus, and is used to provide measurements fromvarious transducers such as vibration monitors, tachometers and pressuretransducers.

For each of the four current loop inputs there are two separate input circuits, 0-1mAand 0-20mA (which is also used for 0-10mA and 4-20mA transducer inputs). Theanti-alias filters have a nominal cut-off frequency (3dB point) of 23Hz to reducepower system interference from the incoming signals.

Four analogue current outputs are provided with ranges of 0-1mA, 0-10mA, 0-20mAor 4-20mA which can alleviate the need for separate transducers. These may beused to feed standard moving coil ammeters for analogue indication of certainmeasured quantities or into a SCADA using an existing analogue RTU.

Each of the four current loop outputs provides one 0 –1mA output, one 0-20mAoutput and one common return. Suitable software scaling of the value written to theboard allows the 0-20mA output to also provide 0-10mA and 4-20mA. Screenedleads are recommended for use on the current loop output circuits.

The refresh interval for the outputs is nominally 50ms. The exceptions are shown insection 2.27.3 of P34x/EN AP/E33. Those exceptional measurements are updatedonce every second.

All external connections to the current loop I/O board are made via the same 15 waylight duty I/O connector SL3.5/15/90F used on the RTD board. Two such connectorsare used, one for the current loop outputs and one for the current loop inputs.



The I/O connectors accommodate wire sizes in the range 1/0.85mm (0.57mm2) to1/1.38mm (1.5mm2) and their multiple conductor equivalents. The use of screenedcable is recommended. The screen terminations should be connected to the caseearth of the relay.

Basic Insulation (300V) is provided between analogue inputs/outputs and earth andbetween analogue inputs and outputs. However, there is no insulation between oneinput and another or one output and another.

Connection IO Blocks Connection

Outputs

Screen channel 1

Screen channel 2

Screen channel 3

Screen channel 4

0-10/0-20/4-20mA channel 10-1mA channel 1Common return channel 1




Inputs

Screen channel 1

Screen channel 2

Screen channel 3

Screen channel 4

0-10/0-20/4-20mA channel 10-1mA channel 1Common channel 1




Figure 4: Current loop input output board



3. RELAY SOFTWARE

The relay software was introduced in the overview of the relay at the start of thissection. 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 software

This section describes in detail the latter two of these, the platform software and theprotection & control software, which between them control the functional behaviour ofthe relay. Figure 5 shows the structure of the relay software.

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3.1 Real-time operating system

The software is split into tasks; the real-time operating system is used to schedule theprocessing of the tasks to ensure that they are processed in the time available and inthe desired order of priority. The operating system is also responsible in part forcontrolling the communication between the software tasks through the use ofoperating system messages.

3.2 System services software

As shown in Figure 5, the system services software provides the interface between therelay’s hardware and the higher-level functionality of the platform software and theprotection & control software. For example, the system services software providesdrivers for items such as the LCD display, the keypad and the remote communicationports, and controls the boot of the processor and downloading of the processor codeinto SRAM from non-volatile flash EPROM at power up.



3.3 Platform software

The 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 maintenance records.

• 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, IEC60870-5-103, DNP 3.0).

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-up SRAMin order to provide a non-volatile log of what has happened. The relay maintainsfour logs: one each for up to 32 alarms, 250 event records, 5 fault records and 5maintenance records. The logs are maintained such that the oldest record isoverwritten with the newest record. The logging function can be initiated from theprotection software or the platform software.

The logging function can be initiated from the protection software or the platformsoftware is responsible for logging of a maintenance record in the event of a relayfailure. This includes errors that have been detected by the platform software itself orerror that are detected by either the system services or the protection softwarefunctions. See also the section on supervision and diagnostics later in this section.

3.3.2 Settings database

The settings database contains all of the settings and data for the relay, including theprotection, disturbance recorder and control & support settings. The settings aremaintained in non-volatile E2PROM memory. The platform software’s managementof the settings database includes the responsibility of ensuring that only one userinterface modifies the settings of the database at any one time. This feature isemployed to avoid confusion between different parts of the software during a settingchange. For changes to protection settings and disturbance recorder settings, theplatform software operates a ‘scratchpad’ in SRAM memory. This allows a number ofsetting changes to be made in any order but applied to the protection elements,disturbance recorder and saved in the database in E2PROM, at the same time (seealso section P34x/EN IT/E33 on the user interface). If a setting change affects theprotection & 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 databaseof settings and measurements must be accessible from all of the relay’s userinterfaces to allow read and modify operations. The platform software presents thedata in the appropriate format for each user interface.

3.4 Protection & control software

The protection and control software task is responsible for processing all of theprotection elements and measurement functions of the relay. To achieve this it has tocommunicate with both the system services software and the platform software as wellas organise its own operations. The protection software has the highest priority of



any of the software tasks in the relay in order to provide the fastest possible protectionresponse. The protection & control software has a supervisor task which controls thestart-up of the task and deals with the exchange of messages between the task andthe 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 P342 andP343 generator protection relays, the protection task is executed four times per cycle,i.e. after every 6 samples for the sample rate of 24 samples per power cycle used bythe relay. However, the protection elements are split into groups so that differentelements are processed each time, with every element being processed at least onceper cycle. The protection and control software is suspended again when all of itsprocessing on a set of samples is complete. This allows operations by other softwaretasks 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 a changein the state of one of the inputs must be maintained over at least half a cycle before itis 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 by detectinga change in the measured signal’s phase angle. The calculated value of thefrequency is used to modify the sample rate being used by the input module so as toachieve a constant sample rate of 24 samples per cycle of the power waveform. Thevalue 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, it calculatesthe Fourier components for the analogue signals. The Fourier components arecalculated using a one-cycle, 24-sample Discrete Fourier Transform (DFT). The DFTis always calculated using the last cycle of samples from the 2-cycle buffer, i.e. themost recent data is used. The DFT used in this way extracts the power frequencyfundamental component from the signal and produces the magnitude and phaseangle of the fundamental in rectangular component format. The DFT provides anaccurate measurement of the fundamental frequency component, and effectivefiltering of harmonic frequencies and noise. This performance is achieved inconjunction with the relay input module which provides hardware anti-alias filteringto attenuate frequencies above the half sample rate, and frequency tracking tomaintain a sample rate of 24 samples per cycle. The Fourier components of theinput current and voltage signals are stored in memory so that they can be accessedby all of the protection elements’ algorithms. The samples from the input module arealso used in an unprocessed form by the disturbance recorder for waveformrecording and to calculate true rms values of current, voltage and power for meteringpurposes.



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, e.g.protection starts and trips, and the outputs of the fixed protection scheme logic. Thefixed scheme logic provides the relay’s standard protection schemes. The PSL itselfconsists of software logic gates and timers. The logic gates can be programmed toperform a range of different logic functions and can accept any number of inputs.The timers are used either to create a programmable delay, and/or to condition thelogic outputs, e.g. to create a pulse of fixed duration on the output regardless of thelength of the pulse on the input. The outputs of the PSL are the LEDs on the frontpanel of the relay and the output contacts at the rear.

The execution of the PSL logic is event driven; the logic is processed whenever any ofits 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 PSL logicthat is affected by the particular input change that has occurred is processed. Thisreduces 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 the PSLinput 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.

3.4.3.1 PSL data

In the PSL editor in MiCOM S1 when a PSL file is downloaded to the relay the usercan specify the group to download the file and a 32 character PSL referencedescription. This PSL reference is shown in the ‘Grp1/2/3/4 PSL Ref’ cell in the ‘PSLDATA’ menu in the relay. The download date and time and file checksum for eachgroups PSL file is also shown in the ‘PSL DATA’ menu in cells ‘Date/Time’ and ‘Grp1/2/3/4 PSL ID’. The PSL data can be used to indicate if a PSL has been changedand thus be useful in providing information for version control of PSL files.

The default PSL Reference description is “Default PSL” followed by the model numbere.g. “Default PSL P34x??????0yy0?” where x refers to the model e.g. 1, 2, 3 and yyrefers to the software version e.g. 05. This is the same for all protection settinggroups (since the default PSL is the same for all groups). Since the LCD display(bottom line) only has space for 16 characters the display must be scrolled to see all32 characters of the PSL Reference description.

The default date and time is the date and time when the defaults were loaded fromflash into EEPROM.

NOTE: The PSL DATA column information is only supported by Courierand Modbus, but not DNP3 or IEC60870-5-103.

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 & controltask sends a message to the supervisor task to indicate that an event is available tobe processed and writes the event data to a fast buffer in SRAM which is controlled bythe supervisor task. When the supervisor task receives either an event or fault record



message, it instructs the platform software to create the appropriate log in batterybacked-up SRAM. The operation of the record logging to battery backed-up SRAM isslower than the supervisor’s buffer. This means that the protection software is notdelayed waiting for the records to be logged by the platform software. However, inthe rare case when a large number of records to be logged are created in a shortperiod of time, it is possible that some will be lost if the supervisor’s buffer is fullbefore the platform software is able to create a new log in battery backed-up SRAM.If this occurs then an event is logged to indicate this 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 be triggeredby a fatal error in the relay in which case it may not be possible to successfully store amaintenance record, depending on the nature of the problem. See also the sectionon self supervision & diagnostics later in this section.

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 it receivesinto the required length disturbance record. It attempts to limit the demands it placeson memory space by saving the analogue data in compressed format wheneverpossible. This is done by detecting changes in the analogue input signals andcompressing the recording of the waveform when it is in a steady-state condition.The compressed disturbance records can be decompressed by MiCOM S1 which canalso store the data in COMTRADE format, thus allowing the use of other packages toview the recorded data.

4. SELF TESTING & DIAGNOSTICS

The relay includes a number of self-monitoring functions to check the operation of itshardware and software when it is in service. These are included so that if an error orfault occurs within the relay’s hardware or software, the relay is able to detect andreport the problem and attempt to resolve it by performing a re-boot. This involvesthe relay being out of service for a short period of time which is indicated by the‘Healthy’ LED on the front of the relay being extinguished and the watchdog contactat the rear operating. If the restart fails to resolve the problem, then the relay willtake itself permanently out of service. Again this will be indicated by the LED andwatchdog contact.

If a problem is detected by the self-monitoring functions, the relay attempts to store amaintenance record in battery backed-up SRAM to allow the nature of the problem tobe notified to the user.

The self-monitoring is implemented in two stages: firstly a thorough diagnostic checkwhich is performed when the relay is booted-up, e.g. at power-on, and secondly acontinuous self-checking operation which checks the operation of the relay’s criticalfunctions whilst it is in service.



4.1 Start-up self-testing

The 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 signalled bythe ‘Healthy’ LED on the front of the relay which will illuminate when the relay haspassed all of the tests and entered operation. If the testing detects a problem, therelay 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 execution bythe processor. When the copy 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 that noerrors have occurred in the transfer of data from flash EPROM to SRAM. The entrypoint of the software code in SRAM is then called which is the relay initialisation code.

4.1.2 Initialisation software

The initialisation process includes the operations of initialising the processor registersand interrupts, starting the watchdog timers (used by the hardware to determinewhether the software is still running), starting the real-time operating system andcreating and starting the supervisor task. In the course of the initialisation process therelay checks:

• the status of the battery.

• the integrity of the battery backed-up SRAM that is used to store event, fault anddisturbance records.

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

• the operation of the LCD controller.

• the watchdog operation.

At the conclusion of the initialisation software the supervisor task begins the processof 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-B, RTDand CLIO board if fitted. The final test that is made concerns the input and output ofdata; the presence and healthy condition of the input board is checked and theanalogue data 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-testing

When the relay is in service, it continually checks the operation of the critical parts ofits hardware and software. The checking is carried out by the system servicessoftware (see section on relay software earlier in this section) and the results reportedto the platform software. The functions that are checked are as follows:

• the flash EPROM containing all program code and language text is verified by achecksum.

• the code and constant data held in SRAM is checked against the correspondingdata in flash EPROM to check for data corruption.

• the SRAM containing all data other than the code and constant data is verifiedwith a checksum.

• the E2PROM containing setting values is verified by a checksum, whenever itsdata is accessed.

• the battery status.

• the level of the field voltage.

• the integrity of the digital signal I/O data from the opto-isolated inputs and therelay contacts, is checked by the data acquisition function every time it is executed.The operation of the analogue data acquisition system is continuously checked bythe acquisition function every time it is executed, by means of sampling thereference voltage on a spare multiplexed channel.

• the operation of the RTD board is checked by reading the temperature indicatedby the reference resistors on the two spare RTD channels.

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

• The correct operation of the CLIO board is checked, where it is fitted.

In the unlikely event that one of the checks detects an error within the relay’ssubsystems, the platform software is notified and it will attempt to log a maintenancerecord in battery backed-up SRAM. If the problem is with the battery status, the RTDboard, CLIO board or the IRIG-B board, the relay will continue in operation.However, for problems detected in any other area the relay will initiate a shutdownand re-boot. This will result in a period of up to 5 seconds when the protection isunavailable, but the complete restart of the relay including all initialisations shouldclear most problems that could occur. As described above, an integral part of thestart-up procedure is a thorough diagnostic self-check. If this detects the sameproblem that caused the relay to restart, i.e. the restart has not cleared the problem,then the relay will take itself permanently out of service. This is indicated by the‘Healthy’ LED on the front of the relay, which will extinguish, and the watchdogcontact which will operate.




MiCOM P342, P343

TECHNICAL DATA

P34x/EN TD/F33 Technical Data

MiCOM P342, P343



CONTENT

1. RATINGS 7

1.1 Currents 7

1.2 Voltages 7

1.3 Auxiliary voltage 7

1.4 Frequency 8

1.5 ‘Universal’ logic inputs (P340 range) 8

1.6 Output relay contacts 8

1.7 Field voltage 9

1.8 Loop through connections 9

1.9 Wiring requirements 9

2. BURDENS 10

2.1 Current circuit 10

2.2 Voltage circuit 10

2.3 Auxiliary supply 10

2.4 Optically-isolated inputs 10

3. ACCURACY 10

3.1 Reference conditions 10

3.2 Influencing quantities 11

4. HIGH VOLTAGE WITHSTAND 12

4.1 Dielectric withstand 12

4.2 Impulse 12

4.3 Insulation resistance 12

4.4 ANSI dielectric withstand 12

5. ELECTRICAL ENVIRONMENT 12

5.1 Performance criteria 12

5.1.1 Class A 13

5.1.2 Class B 13

5.1.3 Class C 13

5.2 Auxiliary supply tests, dc interruption, etc. 13

5.2.1 DC voltage interruptions 13

5.2.2 DC voltage fluctuations 13



5.3 AC voltage dips and short interruptions 14

5.3.1 AC voltage short interruptions 14

5.3.2 AC voltage dips 14

5.4 High frequency disturbance 14

5.5 Fast transients 15

5.6 Conducted/radiated emissions 15

5.6.1 Conducted emissions 15

5.6.2 Radiated emissions 15

5.7 Conducted/radiated immunity 15

5.7.1 Conducted immunity 15

5.7.2 Radiated immunity 15

5.7.3 Radiated immunity from digital radio telephones 15

5.8 Electrostatic discharge 16

5.9 Surge immunity 16

5.10 Power frequency magnetic field 16

5.11 Power frequency interference 16

5.12 Surge withstand capability (SWC) 17

5.13 Radiated immunity 17

6. ATMOSPHERIC ENVIRONMENT 17

6.1 Temperature 17

6.2 Humidity 17

6.3 Enclosure protection 17

7. MECHANICAL ENVIRONMENT 18

7.1 Performance criteria 18

7.1.1 Severity classes 18

7.1.2 Vibration (sinusoidal) 18

7.1.3 Shock and bump 19

7.1.4 Seismic 19

8. EC EMC COMPLIANCE 19

9. EC LVD COMPLIANCE 19

10. PROTECTION FUNCTIONS 20

10.1 Generator differential protection (87G) P343 20

10.1.1 Setting ranges 20



10.1.2 Accuracy 20

10.2 2-Stage non-directional overcurrent (50/51) 20

10.2.1 Reset characteristics 22

10.2.2 RI curve 22

10.2.3 Accuracy 23

10.3 Restricted earth fault (low impedance) 26

10.3.1 Accuracy 26

10.4 2-Stage non-directional earth fault (50N/51N) 26


10.4.2 Time delay settings 26

10.4.2.1 Accuracy 27

10.4.3 IDG curve 27

10.5 Neutral displacement/residual overvoltage (59N) 28


10.5.2 Time delay settings 28

10.5.3 Accuracy 29

10.6 Sensitive directional earth fault (67N) 29

10.6.1 SEF accuracy 29

10.6.2 Wattmetric SEF accuracy 29

10.6.3 Polarising quantities accuracy 30

10.7 100% Stator earth fault P343 30

10.7.1 Accuracy 31

10.8 Voltage dependent overcurrent (51V) 31

10.8.1 Accuracy 32

10.9 Transient overreach and overshoot 32

10.9.1 Accuracy 32

10.10 Under impedance (21) 32

10.10.1 Accuracy 32

10.11 Under voltage (27) 33

10.11.1 Level settings 33

10.11.2 Under voltage protection time delay characteristics 33

10.11.3 Accuracy 33

10.12 Over voltage (59) 34

10.12.1 Level settings 34



10.12.2 Over voltage protection time delay characteristics 34

10.12.3 Accuracy 34

10.13 Under frequency (81U) 35

10.13.1 Accuracy 35

10.14 Over frequency (81O) 35

10.14.1 Accuracy 35

10.15 Reverse power/low forward power/over power (32R /32L /32O) 35

10.15.1 Accuracy 36

10.16 Sensitive reverse power/low forward power/over power (32R /32L /32O)36

10.16.1 Accuracy 37

10.17 Field failure (40) 37

10.17.1 Accuracy 38

10.18 Negative phase sequence thermal (46) 38

10.18.1 Accuracy 38

10.19 Volts/Hz (24) 38

10.19.1 Accuracy 39

10.20 Unintentional energisation at standstill (dead machine) P343 39

10.20.1 Accuracy 39

10.21 Resistive temperature detectors 39

10.21.1 Accuracy 39

10.22 Pole slipping (78) P343 40

10.22.1 Accuracy 40

10.22.2 Hysteresis 41

10.23 Thermal overload (49) 41

10.23.1 Accuracy 42

11. SUPERVISORY FUNCTIONS 42

11.1 Voltage transformer supervision 42

11.1.1 Accuracy 42

11.2 Current transformer supervision 42

11.2.1 Accuracy 43

12. PROGRAMMABLE SCHEME LOGIC 43

12.1 Level settings 43

12.2 Accuracy 43



13. MEASUREMENTS AND RECORDING FACILITIES 43

13.1 Measurements 43

13.2 IRIG-B and real time clock 44

13.2.1 Features 44

13.2.2 Performance 44

13.3 Current loop input and outputs (CLIO) 44

13.3.1 Accuracy 47


14. DISTURBANCE RECORDS 48

14.1 Level settings 48

14.2 Accuracy 48

15. PLANT SUPERVISION 48

15.1 CB state monitoring control and condition monitoring 48

15.1.1 CB monitor settings 48

15.1.2 CB control settings 48

15.1.3 Accuracy 48

15.2 CB fail and backtrip breaker fail 49

15.2.1 Timer settings 49

15.2.2 Timer accuracy 49

15.2.3 Undercurrent settings 49

15.2.4 Undercurrent accuracy 49

16. INPUT AND OUTPUT SETTING RANGES 49

16.1 CT and VT ratio settings 49

17. BATTERY LIFE 50

18. FREQUENCY RESPONSE 50

19. LOCAL AND REMOTE COMMUNICATIONS 51

19.1 Front Port 51

19.2 Rear Port 51


19.3 Second rear communications port 52



Figure 1: IEC inverse time curves 24

Figure 2: American inverse time curves 25

Figure 3: IDG characteristic 28

Figure 4: Hysteresis of the pole slipping characteristic 41

Figure 5: Frequency response 50



1. RATINGS

1.1 Currents

In = 1A or 5A ac rms.

Separate terminals are provided for the 1A and 5A windings, with the neutral input ofeach winding sharing one terminal.

CT Type Operating Range

Standard 0 to 16 Ιn

Sensitive 0 to 2 Ιn

Duration Withstand

Continuous rating 4 Ιn

10 minutes 4.5 Ιn

5 minutes 5 Ιn

3 minutes 6 Ιn

2 minutes 7 Ιn

10 seconds 30 Ιn

1 second 100 Ιn

1.2 Voltages

Maximum rated voltage relate to earth 300Vdc or 300Vrms.

Nominal Voltage Vn Short Term Above Vn (Operating Range)

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

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

Duration Withstand(Vn = 100/120V)

Withstand(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 dcRange

Operative acRange

24 – 48V dc 19 to 65V -

48 – 110V dc (30 – 100V ac rms) ** 37 to 150V 24 to 110V

110 – 240V dc (100 – 240V ac rms) ** 87 to 300V 80 to 265V

** rated for ac or dc operation.



1.4 Frequency

The nominal frequency (Fn) is dual rated at 50 – 60Hz, the operate range is5Hz – 70Hz.

1.5 ‘Universal’ logic inputs (P340 range)

The P340 series relays are fitted with universal opto isolated logic inputs that can beprogrammed for the nominal battery voltage of the circuit of which they are a part.They nominally provide a Logic 1 or On value for Voltages ≥80% of the set lowernominal voltage and a Logic 0 or Off value for the voltages ≤60% of the set highernominal voltage. This lower value eliminates fleeting pickups that may occur duringa battery earth fault, when stray capacitance may present up to 50% of batteryvoltage across an input. Each input also has a pre-set filter of ½ cycle which rendersthe input immune to induced noise on the wiring.

In the Opto Config menu the nominal battery voltage can be selected for all optoinputs by selecting one of the five standard ratings in the Global Nominal V settings.If Custom is selected then each opto input can individually be set to a nominalvoltage value.


Min MaxStep Size

OPTO CONFIG

Global Nominal V 24-27 24-27, 30-34, 48-54, 110-125, 220-250,Custom

Opto Input 1 24-27 24-27, 30-34, 48-54, 110-125, 220-250

Opto Input 2-32 24-27 24-27, 30-34, 48-54, 110-125, 220-250

Battery Voltage (V dc) Logical “off” (V dc) Logical “on” (V dc)

24/27 <16.2 >19.2

30/34 <20.4 >24

48/54 <32.4 >38.4

110/125 <75 >88

220/250 <150 >176

All the logic inputs are independent and isolated. Relay type P342 has a basenumber of opto inputs of 8 in the 40TE case and 16 in the 60TE case. Relay typeP343 has a base number of opto inputs of 16 in the 60TE case and 24 in the 80TEcase. One optional opto input board or one output relay relay board can be addedto each relay model to increase the number of opto inputs by 8 or relay contacts by8.

1.6 Output relay contacts

There are 2 versions of the output relay board one with seven relays, three normallyopen contacts and four changeover contacts and one with eight relays, six normallyopen contacts and two changeover contacts.



For relay models with suffix A hardware, only the 7 output relay boards wereavailable. For equivalent relay models in suffix B hardware or greater the basenumbers of output contacts, using the 7 output relay boards, is being maintained forcompatibility. The 8 output relay board is only used for new relay models or existingrelay models available in new case sizes or to provide additional output contacts toexisting models for suffix issue B or greater hardware. Note, the model number suffixletter refers to the hardware version.

Relay type P342 has a base number of relay contacts of 7 in the 40TE case and 16 inthe 60TE case. Relay type P343 has a base number of relay output contacts of 14 inthe 60TE case and 24 in the 80TE case. One optional output relay board or oneopto input board can be added to each relay model to increase the number of relaycontacts by 8 or opto inputs by 8.

Make & Carry 30A for 3s

Carry 250A for 30ms10A continuous

Break

dc: 50W resistivedc: 62.5W inductive (L/R = 50ms)ac: 2500VA resistive (P.F. =1)ac: 2500VA inductive (P.F. =0.7)

ac: 1250VA inductive (P.F. = 0.5)

Maxima: 10A and 300V

Loaded Contact: 10,000 operation minimum

Unloaded Contact: 100,000 operations minimum

Watchdog Contact

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

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, P34x/EN O/E33).



2. BURDENS

2.1 Current circuit

CT burden (At Nominal Current)

Phase <0.15 VA

Earth <0.2VA

2.2 Voltage circuit

Reference Voltage (Vn)

Vn = 100 – 120V <0.06VA rms at 110V

Vn = 380 – 480V <0.06VA rms at 440V

2.3 Auxiliary supply

Case Size Minimum*

Size 8 /40TE 11W or 24 VA



* no output contacts or optos energised

Each additional energised opto input 0.09W (24/27, 30/34, 48/54 V)

Each additional energised opto input 0.12W (110/125 V)

Each additional energised opto input 0.19W (220/250 V)

Each additional energised output relay 0.13W

2.4 Optically-isolated inputs

Peak current of opto inputs when energised is 3.5 mA (0-300V).

Maximum input voltage 300 V dc (any setting).

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 accuracy isvalid over the full setting range.

3.1 Reference conditions

Quantity Reference Conditions Test Tolerance

General

Ambient temperature 20 °C ±2°C

Atmospheric pressure 86kPa to 106kPa –

Relative humidity 45 to 75 % –

Input energising quantity



Quantity Reference Conditions Test Tolerance

General

Current Ιn ±5%

Voltage Vn ±5%

Frequency 50 or 60Hz ±0.5%

Auxiliary supply DC 48V or 110VAC 63.5V or 110V ±5%

Settings Reference value

Time multiplier setting 1.0

Time dial 7

Phase angle 0°

3.2 Influencing quantities

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

Quantity Operative Range (Typical Only)

Environmental

Temperature –25°C to +55°C

Mechanical (Vibration, Shock,Bump, Seismic)

According toIEC 60255-21-1:198IEC 60255-21-2:1988IEC 60255-21-3:1995

Quantity Operative range

Electrical

Frequency 5 Hz to 70 Hz

Harmonics (single) 5% over the range 2nd to 17th

Auxiliary 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.fn

Point on wave of fault waveform 0 to 360°

DC offset of fault waveform No offset to fully offset

Phase angle –90° to + 90°

Magnetising inrush No operation with OC elements set to 35%of peak anticipated inrush level.



4. HIGH VOLTAGE WITHSTAND

4.1 Dielectric withstand

IEC60255-5:1997

2.0kVrms for one minute between all terminals and case earth.

2.0kVrms for one minute between all terminals of each independent circuit groupedtogether, and all other terminals. This includes the output contacts and loop throughconnections D17/D18 and F17/F18.

1.5kVrms for one minute across dedicated normally open contacts of output relays.

1.0kVrms for 1 minute across normally open contacts of changeover and watchdogoutput relays.

1.0kVrms for 1 minute for all D-type connections between line and ground.

4.2 Impulse

IEC60255-5:1997

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

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

Independent circuits with the terminals of each independent circuit connectedtogether.

Terminals of the same circuit except normally open metallic contacts.

4.3 Insulation resistance

IEC60255-5:1997

The insulation resistance is greater than 100 MΩ at 500Vdc.

4.4 ANSI dielectric withstand

ANSI/IEEE C37.90. (1989) (Reaff. 1994)

1kV rms. for 1 minute across open contacts of the watchdog contacts.

1kV rms. for 1 minute across open contacts of changeover output contacts.

1.5kV rms. for 1 minute across normally open output contacts.

5. ELECTRICAL ENVIRONMENT

5.1 Performance criteria

The following three classes of performance criteria are used within sections 5.2 to5.13 (where applicable) to specify the performance of the MiCOM relay whensubjected to the electrical interference. The performance criteria are based on theperformance criteria specified in EN 50082-2:1995.



5.1.1 Class A

During the testing the relay will not maloperate, upon completion of the testing therelay will function as specified. A maloperation will include a transient operation ofthe output contacts, operation of the watchdog contacts, reset of any of the relaysmicroprocessors or an alarm indication.

The relay communications and IRIG-B signal must continue uncorrupted via thecommunications ports and IRIG-B port respectively during the test, however relaycommunications and the IRIG-B signal may be momentarily interrupted during thetests, provided that they recover with no external intervention.

5.1.2 Class B

During the testing the relay will not maloperate, upon completion of the testing therelay will function as specified. A maloperation will include a transient operation ofthe output contacts, operation of the watchdog contacts, reset of any of the relaysmicroprocessors or an alarm indication. A transitory operation of the output LEDs isacceptable provided no permanent false indications are recorded.

The relay communications and IRIG-B signal must continue uncorrupted via thecommunications ports and IRIG-B port respectively during the test, however relaycommunications and the IRIG-B signal may be momentarily interrupted during thetests, provided that they recover with no external intervention.

5.1.3 Class C

The relay will power down and power up again in a controlled manner within 5seconds. The output relays are permitted to change state during the test as long asthey reset once the relay powers up.

Communications to relay may be suspended during the testing as long ascommunication recovers with no external intervention after the testing.

5.2 Auxiliary supply tests, dc interruption, etc.

5.2.1 DC voltage interruptions

IEC 60255-11:1979.

DC Auxiliary Supply Interruptions 2, 5, 10, 20ms.

Performance criteria - Class A.

DC Auxiliary Supply Interruptions 50, 100, 200ms, 40s.

Performance criteria - Class C.

5.2.2 DC voltage fluctuations

IEC 60255-11:1979.

AC 100Hz ripple superimposed on DC max. and min. auxiliary supply at 12% ofhighest rated DC.




5.3 AC voltage dips and short interruptions

5.3.1 AC voltage short interruptions

IEC 61000-4-11:1994.

AC Auxiliary Supply Interruptions 2, 5, 10, 20ms.


AC Auxiliary Supply Interruptions 50, 100, 200ms, 1s, 40s.


5.3.2 AC voltage dips

IEC 61000-4-11:1994

AC Auxiliary Supply 100% Voltage Dips 2, 5, 10, 20ms.

Performance criteria –Class A.

AC Auxiliary Supply 100% Voltage Dips 50, 100, 200ms, 1s, 40s.










5.4 High frequency disturbance

IEC 60255-22-1:1988 Class III.

1MHz burst disturbance test.

2.5kV common mode.

Power supply, field voltage, CTs, VTs, opto inputs, output contacts, IRIG-B andterminal block communications connections.

1kV differential mode.

Power supply, field voltage, CTs, VTs, opto inputs and output contacts.

Performance criteria Class A.



5.5 Fast transients

IEC 60255-22-4:1992 (EN 61000-4-4:1995), Class III and Class IV.

2kV 5kHz (Class III) and 4kV 2.5kHz (Class IV) direct coupling.

Power supply, field voltage, opto inputs, output contacts, CTs, VTs.

2kV 5kHz (Class III) and 4kV 2.5kHz (Class IV) capacitive clamp.

IRIG-B and terminal block communications connections.


5.6 Conducted/radiated emissions

5.6.1 Conducted emissions

EN 55011:1998 Class A, EN 55022:1994 Class A.

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

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

5.6.2 Radiated emissions

EN 55011:1998 Class A, EN 55022:1994 Class A.

30 - 230MHz, 40dBµV/m at 10m measurement distance.230 - 1000MHz, 47dBµV/m at 10m measurement distance.

5.7 Conducted/radiated immunity

5.7.1 Conducted immunity

EN 61000-4-6:1996 Level 3.

10V emf @ 1kHz 80% am, 150kHz to 80MHz. Spot tests at 27MHz, 68MHz.


5.7.2 Radiated immunity

IEC 60255-22-3:1989 Class III (EN 61000-4-3: 1997 Level 3).

10 V/m 80MHz - 1GHz @ 1kHz 80% am.

Spot tests at 80MHz, 160MHz, 450MHz, 900MHz.


5.7.3 Radiated immunity from digital radio telephones

ENV 50204:1995

10 V/m 900MHz ± 5 MHz and 1.89GHz ±5MHz, 200Hz rep. Freq., 50% duty cyclepulse modulated.




5.8 Electrostatic discharge

IEC 60255-22-2:1996 Class 3 & Class 4.

Class 4: 15kV air discharge.Class 3: 6kV contact discharge.Tests carried out both with and without cover fitted.


5.9 Surge immunity

IEC 61000-4-5:1995 Level 4.

4kV common mode 12Ω source impedance, 2kV differential mode 2Ω sourceimpedance.

Power supply, field voltage, VTs.

The CT inputs are immune to all levels of common mode surge as per IEC 61000-4-5: 1995 Level 4. Total immunity to differential surges to Level 4 can be achieved byadding a time delay of at least 20ms. Note, routing the CT wires as a pair reducesthe likelihood of a differential surge.

4kV common mode 42Ω source impedance, 2kV differential mode 42Ω sourceimpedance.

Opto inputs, output contacts.

4kV common mode 2Ω source impedance applied to cable screen.

Terminal block communications connections and IRIG-B.

Performance criteria Class A under reference conditions.

5.10 Power frequency magnetic field

IEC 61000-4-8:1994 Level 5.

100A/m field applied continuously in all planes for the EUT in a quiescent state andtripping state

1000A/m field applied for 3s in all planes for the EUT in a quiescent state andtripping state


5.11 Power frequency interference

NGTS* 2.13 Issue 3 April 1998, section 5.5.6.9.

500V rms. common mode.250V rms. differential mode.

Voltage applied to all non-mains frequency inputs. Permanently connectedcommunications circuits tested to Class 3 (100-1000m) test level 50mV


* National Grid Technical Specification



5.12 Surge withstand capability (SWC)

ANSI/IEEE C37.90.1 (1990) (Reaff. 1994)

Oscillatory SWC Test.2.5kV – 3kV, 1 - 1.5MHz - common and differential mode – applied to all circuitsexcept for IRIG-B and terminal block communications, which are tested commonmode only via the cable screen.

Fast Transient SWC Tests

4 - 5kV crest voltage - common and differential mode - applied to all circuits exceptfor IRIG-B and terminal block communications, which are tested common mode onlyvia the cable screen.

Performance criteria Class A

5.13 Radiated immunity

ANSI/IEEE C37.90.2 1995

35 V/m 25MHz - 1GHz no modulation applied to all sides.

35 V/m 25MHz - 1GHz, 100% pulse modulated, front only.


6. ATMOSPHERIC ENVIRONMENT

6.1 Temperature

IEC 60068-2-1:1990/A2:1994 - Cold

IEC 60068-2-2:1974/A2:1994 - Dry heat

IEC 60255-6:1988.

Operating Temperature Range °C

(Time Period in Hours)

Storage Temperature Range °C

(Time Period in Hours)

ColdTemperature

Dry HeatTemperature

ColdTemperature

Dry HeatTemperature

-25 (96) 55 (96) -25 (96) 70 (96)

6.2 Humidity

IEC 60068-2-3:1969

Damp heat, steady state, 40° C ± 2° C and 93% relative humidity (RH) +2% -3%,duration 56 days.

IEC 60068-2-30:1980.

Damp heat cyclic, six (12 + 12 hour cycles) of 55°C ±2°C 93% ±3% RH and 25°C±3°C 93% ±3% RH.

6.3 Enclosure protection

IEC 60529:1989.

IP52 Category 2.



IP5x – Protected against dust, limited ingress permitted.

IPx2 – Protected against vertically falling drops of water with the product in 4 fixedpositions of 15° tilt with a flow rate of 3mm/minute for 2.5 minutes.

7. MECHANICAL ENVIRONMENT

7.1 Performance criteria

The following two classes of performance criteria are used within sections to (whereapplicable) to specify the performance of the MiCOM relay when subjected tomechanical testing.

7.1.1 Severity classes

The following table details the Class and Typical Applications of the vibration, shockbump and seismic tests detailed previously

Class Typical Application

1Measuring relays and protection equipment for normal use inpower plants, substations and industrial plants and for normaltransportation conditions

2

Measuring relays and protection equipment for which a very highsecurity margin is required or where the vibration (shock andbump) (seismic shock) levels are very high, e.g. shipboardapplication and for severe transportation conditions.

7.1.2 Vibration (sinusoidal)

IEC 60255-21-1:1988

Cross over frequency - 58 to 60 Hz

Vibration response

SeverityClass

Peak DisplacementBelow Cross OverFrequency (mm)

Peak AccelerationAbove Cross Over

Frequency (gn)

Number ofSweeps inEach Axis

FrequencyRange (Hz)

2 0.075 1 1 10 – 150

Vibration endurance

SeverityClass

Peak Acceleration(gn)

Number of Sweepsin Each Axis

Frequency Range(Hz)

2 2.0 20 10 – 150



7.1.3 Shock and bump

IEC 60255-21-2:1988

IEC 60255-21-2:1988

Type ofTest

SeverityClass

Peak Acceleration( gn)

Duration ofPulse ( ms )

Number of Pulsesin Each Direction

ShockResponse 2 10 11 3

Shockwithstand 1 15 11 3

Bump 1 10 16 1000

7.1.4 Seismic

IEC 60255-21-3:1993

Cross over frequency - 8 to 9Hz

x = horizontal axis, y = vertical axis

Peak DisplacementBelow Cross OverFrequency (mm)

Peak AccelerationAbove Cross

Over Frequency(gn)

SeverityClass

x y x y

Number ofSweep Cyclesin Each Axis

FrequencyRange(Hz)

2 7.5 3.5 2.0 1.0 1 1- 35

8. EC EMC COMPLIANCE

Compliance to the European Community Directive 89/336/EEC amended by93/68/EEC is claimed via the Technical Construction File route.

The Competent Body has issued a Technical Certificate and a Declaration ofConformity has been completed.

The following Generic Standards used to establish conformity:

EN 50081-2:1994

EN 50082-2:1995.

9. EC LVD COMPLIANCE

Compliance with European Community Directive on Low Voltage 73/23/EEC isdemonstrated by reference to generic safety standards:

EN 61010-1:1993/A2: 1995

EN 60950:1992/A11 1997



10. PROTECTION FUNCTIONS

10.1 Generator differential protection (87G) P343

10.1.1 Setting ranges

Settings Range

Mode Percentage Bias/High Impedance/InterturnStep Size

Ιs1 0.05 Ιn – 0.5 Ιn 0.01Ιn

k1 0 – 20% 5%

Ιs2 1 Ιn – 5 Ιn 0.1Ιn

k2 20 – 150% 10%

Interturn Ιs_A 0.05 Ιn – 2 Ιn 0.01Ιn

Interturn Ιs_B 0.05 Ιn – 2 Ιn 0.01Ιn

Interturn Ιs_C 0.05 Ιn – 2 Ιn 0.01Ιn

Interturn time delay 0 to 100s 0.01s

10.1.2 Accuracy

Pick-up Formula ±5%

Drop-off 95% of setting ±5%

Operating time <30ms for currents applied at 4x pickup level or greater

Repeatability <7.5%

Disengagement time <40ms

10.2 2-Stage non-directional overcurrent (50/51)


1st Stage

Ι>1 0.08 - 4 Ιn 0.01 Ιn

CharacteristicDT, SI(IEC), VI(IEC), EI(IEC), LTI(IEC), UKRectifier, RI, MI(IEEE), VI(IEEE), EI(IEEE),

Inv(US), STI(US)

DT 0 to 100s 0.01s

TMS (IEC/UK) 0.025 to 1.2 0.025

Ι>1 Time Dial 1 0.01 100 0.01

K(RI) 0.1 - 10 0.05

tRESET(IEC/UK) 0 to 100s 0.01s

2nd Stage

Ι>2 0.08 – 10 Ιn 0.01 Ιn

DT 0 to 100s 0.01s

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 x

K

(Ι/Ιs) α - 1 + L

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

t = TD x

K

(Ι/Ιs) α - 1 + L

where

t = operation time

K = constant


ΙS = 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

IDMT characteristics

IDMT Curve Description Standard KConstant

αConstant

LConstant

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

Rectifier UK 45900 5.6 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 0.16758 0.02 0.11858

The IEC extremely inverse curve becomes definite time at currents greater than 20 xsetting. The IEC standard, very and long time inverse curves become definite time atcurrents greater than 30 x setting.



Time multiplier settings for IEC/UK curves


TMS 0.025 to 1.2 0.025

Time dial settings for IEEE/US curves


TD 0.01 to 100 0.01

10.2.1 Reset characteristics

For all IEC/UK curves, the reset characteristic is definite time only.

For all IEEE/US curves, the reset characteristic can be selected as either inverse curveor definite time.

The definite time can be set (as defined in IEC) to zero. Range 0 to 100 seconds insteps of 0.01 seconds.

The Inverse Reset characteristics are dependent upon the selected IEEE/US IDMTcurve as shown in the table below.

All inverse reset curves conform to the following formula:

tRESET = TD x S

(1 - M2) in seconds

where


S = Constant

M = Ι / Ιs

Curve Description Standard S Constant

Moderately Inverse IEEE 4.85

Very Inverse IEEE 21.6

Extremely Inverse IEEE 29.1

Inverse US 5.95

Short Time Inverse US 2.261

10.2.2 RI curve

The RI curve (electromechanical) has been included in the first stage characteristicsetting options for Phase Overcurrent and Earth Fault protections. The curve isrepresented by the following equation:

t = K x

1

0.339 - 0.236/M

in seconds

With K adjustable from 0.1 to 10 in steps of 0.05

M = Ι / Ιs



10.2.3 Accuracy

Pick-up Setting ±5%

Drop-off 0.95 x Setting ±5%

Minimum trip level of IDMT elements 1.05 x Setting ±5%

IDMT characteristic shape ±5% or 40ms whichever is greater(under reference conditions)*

IEEE reset ±5% or 50ms whichever is greater

DT operation ±2% or 50ms whichever is greater

DT reset ±5%

Directional boundary accuracy (RCA ±90°) ±2° hysteresis 2°

Characteristic UK curves IEC 60255-3 – 1998

US curves IEEE C37.112 – 1996



!

"#!

$%

&'"(

Figure 1: IEC inverse time curves



) """!

' """!

* """#!

+ $

, $-

./

)

'

,

*

+

&*"(

Figure 2: American inverse time curves



10.3 Restricted earth fault (low impedance)


K1 0% to 20% 1 % (minimum)

K2 0% to 150% 1 % (minimum)

Ιs1 0.05 Ιn to Ιn 0.01 Ιn

Ιs2 0.1 Ιn to 1.5 Ιn 0.1 Ιn

10.3.1 Accuracy

Pick-up Setting formula ±5%

Drop-off 0.80 (or better) of calculated differential current

Low impedance operating time <60ms

High impedance pick-up Setting ±5%

High impedance operating time <30ms

10.4 2-Stage non-directional earth fault (50N/51N)



1st Stage

ΙN>1 0.02 – 4.0 Ιn 0.01 Ιn

ΙN>1 IDG Ιs 1 – 4 0.1

2nd Stage

ΙN>2 0.02 – 10 Ιn 0.01 Ιn

10.4.2 Time delay settings


1st Stage

CharacteristicDT, SI(IEC), VI(IEC), EI(IEC), LTI(IEC), RI,

MI(IEEE), VI(IEEE), EI(IEEE), Inv(US), STI(US),IDG

DT 0 to 200s 0.01 Ιn

TMS (IEC/UK) 0.025 to 1.2 0.025

K (RI) 0.1 to 10 0.05

IDG Time 1 to 2 0.01

TD (IEEE/US) 0.01 to 100 0.01

tRESET(IEC/UK) 0 to 100s 0.01s

2nd Stage

DT 0 to 200s 0.01s



The earth fault elements are followed by an independently selectable time delay.These time delays have an extended range of 0 to 200s, but are otherwise identicalto those of the phase overcurrent definite time delay. The reset time delay is thesame as the phase overcurrent reset time.

10.4.2.1 Accuracy



Minimum trip level of IDMT elements 1.05 x Setting ±5%

IDMT characteristic shape ±5% or 40ms whichever is greater(under reference conditions)*

IEEE reset ±5% or 40ms whichever is greater


DT reset ±5%

Repeatability 2.5%

10.4.3 IDG curve

The IDG curve is commonly used for time delayed earth fault protection in theSwedish market. This curve is available in stage 1 of the Earth Fault protection.

The IDG curve is represented by the following equation:

t = 5.8 - 1.35 loge

Ι

ΙN > Setting in seconds

where


ΙN>Setting = an adjustable setting which defines the start point of the characteristic

Although the start point of the characteristic is defined by the “ΙN>” setting, theactual relay current threshold is a different setting called “IDG Ιs”. The “IDG Ιs”setting is set as a multiple of “ΙN>”.

An additional setting “IDG Time” is also used to set the minimum operating time athigh levels of fault current.

Figure 3 illustrates how the IDG characteristic is implemented.



0

1

2

3

4

5

6

7

8

9

10

1 10 100

I/IN>

Ope

ratin

g tim

e (s

econ

ds)

IDG Is Setting Range

IDG Time Setting Range

P2242ENa

Figure 3: IDG characteristic

10.5 Neutral displacement/residual overvoltage (59N)


Name Range Step Size

VN>1 (Vn 100/120V) 1 – 80V 1V

VN>2 (Vn 100/120V) 1 – 80V 1V

VN>1 (Vn 380/480V) 4 – 320V 4V

VN>2 (Vn 380/480V) 4 – 320V 4V

10.5.2 Time delay settings

The inverse characteristic for VN>1 shall be given by the following formula :

t = K

(M - 1)

where

K = Time multiplier setting

t = operating time in seconds

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

Range Step Size

TMS setting (K) 0.5 – 100s 0.5

DT reset setting 0 – 100s 0.01s



10.5.3 Accuracy

For DT Start Setting ±5%Pick-up

For IDMT Start 1.05 x Setting ±5%


IDMT characteristic shape ±5% or 60ms whichever is greater

DT operation ±2% or 20ms whichever is greaterInstantaneous operation <55ms

Reset <35ms

Repeatability <5%

10.6 Sensitive directional earth fault (67N)


Directionality Non directional/Directional Fwd/DirectionalRev

ΙSEF>1 0.005 to 0.1 Ιn 0.00025 Ιn

ΙSEF>Vnpol0.5 to 80V (Vn=100/120V)2 to 320V (Vn =380/480V)

0.5V2V

ΙSEF> Char Angle –95° to 95° 1°

DT 0 to 200s 0.01s

0 - 20W (Ιn=1A, Vn=100/120V) 0.05W

0 - 100W (Ιn=5A, Vn=100/120V) 0.25W

0 - 80W (Ιn=1A, Vn=380/480V) 0.20WPN>

0 - 400W (Ιn=5A, Vn=380/480V) 1W

10.6.1 SEF accuracy




DT reset ±5%

Repeatability 5%

10.6.2 Wattmetric SEF accuracy

For P=0W ΙSEF> ±5%Pick-up

For P>0W P> ±5%

For P=0W (0.95 x ΙSEF>) ±5%Drop-off

For P>0W 0.9 x P> ±5%

Boundary accuracy ±5% with 1° hysteresis

Repeatability 5%



10.6.3 Polarising quantities accuracy

Operating boundary pick-up ±2°of RCA ±90°

Hysteresis <3°

ΙSEF>Vnpol Pick-up Setting ±10%

ΙSEF>Vnpol Drop-off 0.9 x Setting or 0.7V (whichever is greater) ±10%

10.7 100% Stator earth fault P343


VN3H< 0.3 – 20V (Vn=100/120V)1.2 – 80V (Vn /440V)

0.1V0.4V

V< Inhibit 30 – 120V (Vn=100/120V)120 – 480V (Vn=380/440V)

1V4V

P< Inhibit

4W – 200W (Ιn=1A, Vn=100/120V)

16W – 800W (Ιn=1A, Vn=380/480V)

20W – 1000W (Ιn=5A, Vn=100/120V)

80W – 4000W (Ιn=5A, Vn=380/480V)

Equivalent Range in %Pn 2% - 105%

0.5W

2.0W

2.5W

10.0W

0.3%

Q< Inhibit

4Var – 200Var (Ιn=1A, Vn=100/120V)

16Var – 800Var (Ιn=1A, Vn=380/480V)

20Var – 1000Var (Ιn=5A, Vn=100/120V)

80Var – 4000Var (Ιn=5A, Vn=380/480V)


0.5Var

2.0Var

2.5Var

10.0Var

0.3%

S< Inhibit

4VA – 200VA (Ιn=1A, Vn=100/120V)

16VA – 800VA (Ιn=1A, Vn=380/480V)

20VA – 1000VA (Ιn=5A, Vn=100/120V)

80VA – 4000VA (Ιn=5A, Vn=380/480V)


0.5VA

2.0VA

2.5VA

10.0VA

0.3%

VN3H>0.3V – 20V (Vn=100/120V)

1.2V – 80V (Vn=380/480V)

0.1V

0.4V

DT 0 – 100s 0.01s



10.7.1 Accuracy

VN3H</VN3H> Setting ±5%Pick-up

V/P/Q/S<Ιnh Setting ±0.5%

VN3H<

VN3H>

105% of Pick-up ±5%

95% of Pick-up ±5%Drop-off

V/P/Q/S<Ιnh 95% of Pick-up ±0.5%

Operating time ±0.5% or 50ms whichever is greater

Repeatability <0.5%

Disengagement / reset time <50ms

10.8 Voltage dependent overcurrent (51V)


Operating mode Voltage controlled/voltage restrained

Current threshold Ι>set 0.8 – 4 Ιn 0.01 Ιn

CharacteristicDT, SI(IEC), VI(IEC), EI(IEC), LTI(IEC),

UK Rectifier, RI, M I(IEEE), VI(IEEE),EI(IEEE), Inv(US), STI(US)

Voltage threshold V<1 5 – 120V (Vn = 100/120V)20 – 440V (Vn = 380/480V)

1V4V

Voltage threshold V<2 5 – 120V (Vn = 100/120V)20 – 440V (Vn = 380/480V)

1V4V

K factor 0.1 – 1.00 0.05

DT 0 –100s 0.01s

TMS 0.025 – 1.2 0.025

TD (IEEE/US) 0.01 to 100 0.01

K(RI) 0.1 - 10 0.05

tRESET 0 – 100s 0.01s

The reset time inverse time characteristics for IEEE/US curves are the same as thephase overcurrent.



10.8.1 Accuracy

VCO threshold Setting ±5%Pick-up

Overcurrent formula ±5%

VCO threshold 1.05 x Setting ±5%Drop-off

Overcurrent 0.95 x formula ±5%

Operating time <50ms

Repeatability <2.5%

IDMT operation ±5% or 40ms whichever is greater

Definite time operation ±5% or 50ms whichever is greater

tRESET ±5% or 50ms whichever is greater

10.9 Transient overreach and overshoot

10.9.1 Accuracy

Additional tolerance due toincreasing X/R ratios ±5% over the X/R ratio of 1 to 90

Overshoot of overcurrent elements <40ms

Disengagement time <60ms (65ms SEF)

10.10 Under impedance (21)


Z<1&

Z<2

2 - 120 Ω (Vn=100/120V, Ιn=1A)0.4 - 24 Ω (Vn=100/120V, Ιn=5A)8 - 480 Ω (Vn=380/440V, Ιn=1A)1.6 - 96 Ω (Vn=380/440V, Ιn=5A)

0.5W0.1W2W

0.4W

DT 0 - 100s 0.01s

10.10.1 Accuracy


Drop-off 105% of setting ±5%

Operating time ±2% or 50ms whichever is greater

Repeatability <5%


tRESET ±5%

Instantaneous operating time <50ms



10.11 Under voltage (27)

10.11.1 Level settings


V<1 & V<2

(Vn = 100/120V)10 – 120V 1V

V<1 & V<2

(Vn = 380/480V)40 – 480V 4V

10.11.2 Under voltage protection time delay characteristics

Under voltage measuring elements are followed by an independently selectable timedelay.

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 operation of auser defined logic (optical isolated) input.

The inverse characteristic shall be given by the following formula :

t = K

(1 - M)

where


t = operating time in seconds


Range Step Size

DT setting 0 – 100s 0.01s

TMS Setting (K) 0.5 – 100 0.5

Definite time and TMS setting ranges.

10.11.3 Accuracy






Reset <75ms

Repeatability <1%



10.12 Over voltage (59)

10.12.1 Level settings


V>1 & V>2

(Vn = 100/120V)60 – 185V 1V

V>1 & V>2

(Vn = 380/480V)240 – 740V 4V

10.12.2 Over voltage protection time delay characteristics

Over voltage measuring elements are followed by an independently selectable timedelay.

The first elements 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 operation of auser defined logic (optical isolated) input.

The inverse characteristics are given by the following formula:

t = K

(M - 1)

where


T = Operating time in seconds


Range Step Size

DT setting 0 – 100s 0.01s

TMS Setting (K) 0.5 – 100s 0.5

Definite time and TMS setting ranges

10.12.3 Accuracy






Reset <75ms



10.13 Under frequency (81U)


f (for all stages) 45 – 65 Hz 0.01 Hz

t (for all stages) 0 – 100s 0.01s

10.13.1 Accuracy

Pick-up Setting ±0.01Hz

Drop-off (Setting + 0.025Hz) ±0.01Hz

DT operation ±2% or 50ms whichever is greater*

* The operating will also include a time for the relay to frequency track (20Hz/second)

10.14 Over frequency (81O)


f (for all stages) 45 – 68 Hz 0.01 Hz

t (for all stages) 0 – 100s 0.01s

10.14.1 Accuracy

Pick-up Setting ±0.01Hz

Drop-off (Setting - 0.025Hz) ±0.01Hz

DT operation ±2% or 50ms whichever is greater*

* The operating will also include a time for the relay to frequency track 20Hz/second)

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


Stage 1 Enable/disable

Operating Mode Generating/Motoring

Mode Reverse/low forward/over

–P> (reverse power)

4W – 300W (Ιn=1A, Vn=100/120V)

16W – 1200W (Ιn=1A, Vn=380/480V)

20W – 1500W (Ιn=5A, Vn=100/120V)

80W – 6000W (Ιn=5A, Vn=380/480V)


0.5W2W

2.5W6W

0.3%

P< (low forward power)

4W – 300W (Ιn=1A, Vn=100/120V)

16W – 1200W (Ιn=1A, Vn=380/480V)

20W – 1500W (Ιn=5A, Vn=100/120V)

80W – 6000W (Ιn=5A, Vn=380/480V)


0.5W2W

2.5W6W

0.3%




P> (over power)

4W – 300W (Ιn=1A, Vn=100/120V)

16W – 1200W (Ιn=1A, Vn=380/480V)

20W – 1500W (Ιn=5A, Vn=100/120V)

80W – 6000W (Ιn=5A, Vn=380/480V)


0.5W2W

2.5W6W

0.3%

DT 0 – 100s 0.01s

DO Timer 0 – 100s 0.01s

Stage 2 Same as Stage 1

10.15.1 Accuracy


Reverse/Over Power 0.95 of setting ±10%Drop-off

Low forward Power 1.05 of setting ±10%

Pick-up (angle variation) Expected pick-up angle ±1 degree

Drop-off (angle variation) Expected drop-off angle ±2.5 degree


Repeatability <5%


tRESET ±5%


10.16 Sensitive reverse power/low forward power/over power (32R /32L /32O)


Stage 1 Enable/Disable

Operating Mode Generating/Motoring

Mode Reverse/low forward/over

–P> (reverse power)

0.3W – 100W (Ιn=1A, Vn=100/120V)

1.2W – 400W (Ιn=1A, Vn=380/480V)

1.5W – 500W (Ιn=5A, Vn=100/120V)

6.0W – 2000W (Ιn=5A, Vn=380/480V)

Equivalent range in %Pn 0.5% – 157%

0.1W

0.4W

0.5W

2.0W

0.2%

P< (low forward power

0.3W – 100W (Ιn=1A, Vn=100/120V)

1.2W – 400W (Ιn=1A, Vn=380/480V)

1.5W – 500W (Ιn=5A, Vn=100/120V)

6.0W – 2000W (Ιn=5A, Vn=380/480V)


0.1W

0.4W

0.5W

2.0W

0.2%




P> (over power)

0.3W – 100W (Ιn=1A, Vn=100/120V)

1.2W – 400W (Ιn=1A, Vn=380/480V)

1.5W – 500W (Ιn=5A, Vn=100/120V)

6.0W – 2000W (Ιn=5A, Vn=380/480V)


0.1W

0.4W

0.5W

2.0W

0.2%

DT 0 – 100s 0.01s

DO Timer 0 – 100s 0.01s

Compensation angle θC -5° – 5° 0.1°

Stage 2 Same as Stage 1

10.16.1 Accuracy


Reverse/Over Power 0.9 of setting ±10%Drop-off

Low forward Power 1.1 of setting ±10%

Pick-up (angle variation) Expected pick-up angle ±2 degree

Drop-off (angle variation) Expected drop-off angle ±2.5 degree


Repeatability <5%


tRESET ±5%


10.17 Field failure (40)


Mho offset (-Xa1, -Xa2)

0 – 40 Ω (Ιn=1A, Vn=100/120V)0 – 8 Ω (Ιn=5A, Vn=100/120V)

0 - 160 Ω (Ιn=1A, Vn=380/480V)0 – 32 Ω (Ιn=5A, Vn=380/480V)

0.5Ω0.1Ω

2ý0.4Ω

Diameter (Xb1, Xb2)

25 – 325 Ω (Ιn=1A, Vn=100/120V)5 – 65 Ω (Ιn=5A, Vn=100/120V)

100 – 1300 Ω (Ιn=1A, Vn=380/480V)20 – 260 Ω (Ιn=5A, Vn=380/480V)

0.5Ω0.1Ω

2ý0.4Ω

Ffail Alarm angle 15º – 75º 1º

Ffail Alarm delay 0 – 100s 0.01s

Ffail 1 & 2 time delay 0 – 100s 0.01s

Ffail 1& 2 drop off timer 0 – 100s 0.01s



10.17.1 Accuracy

mho characteristic Characteristic shape ±5%Pick-up

linear characteristic Characteristic shape ±10%

mho characteristic 105% of setting ±5%Drop-off

linear characteristic 105% of setting ±10%

Operating time ±2% or 50ms whichever isgreater

Repeatability <1%

Disengagementtime <50ms

10.18 Negative phase sequence thermal (46)


Ι2>1 alarm 0.03 – 0.5 Ιn 0.01 Ιn

Ι2>1 time delay 2 – 60s 0.1s

Ι2>2 trip 0.05 – 0.5 Ιn 0.01 Ιn

Ι2>2 K 2 – 40s 0.1s

Ι2>2 Kreset 2 – 40s 0.1s

Ι2>2 tmax 500 – 2000s 10s

Ι2>2 tmin 0 – 100 0.01s

10.18.1 Accuracy

Pick-up Formula ±5%

Drop-off 95% of Pick-up ±5%


Repeatability <5%


10.19 Volts/Hz (24)


V/f trip 1.5 – 3.5V/Hz (Vn=100/120V)6.0 – 14V/Hz (Vn=380/480V)

0.01 V/Hz0.04 V/Hz

V/f alarm 1.5 – 3.5V/Hz (Vn=100/120V)6.0 – 14V/Hz (Vn=380/480V)

0.01 V/Hz0.04 V/Hz

V/f Trip TMS 1 – 63 1

V/f Trip Delay 0 – 100s 0.01s

V/f Alarm Delay 0 – 100s 0.01s

Note: V/Hz setting refers to secondary voltage and the nominalfrequency.



10.19.1 Accuracy


Drop-off 95% of Pick-up ±5%

IDMT operating time ±5% or 60ms whichever is greater

Definite time ±2% or 30ms whichever is greater

Repeatability <1%

10.20 Unintentional energisation at standstill (dead machine) P343


Dead Mach Ι> 0.08 to 4 Ιn 0.1 Ιn

Dead Mach V< 10 to 120V (Vn=100/120V)40 to 480V (Vn=380/480V)

0.01V0.04V

Dead Mach tPU 0 to 10s 0.1s

Dead Mach tDO 0 to 10s 0.1s

10.20.1 Accuracy

Ι> Setting ±5%Pick-up

V< Setting ±5%

Ι> 95% of setting ±5%Drop-off

V< 105% of setting ±5%


Repeatability 2.5% or 10ms whichever is greater

10.21 Resistive temperature detectors

Setting Min Max Step

RTD# alarm temperature 0°C 200°C 1°C

RTD# trip temperature 0°C 200°C 1°C

RTD Alarm delay 0 s 100 s 1s

RTD Trip delay 0 s 100 s 1s

10.21.1 Accuracy

Pick up Setting ±1°C

Drop off (Setting - 1°C)

Operating time ±2% or <1100ms



10.22 Pole slipping (78) P343


ZA (Lens Forward Reach)

0.5 - 350Ω (Ιn=1A, Vn=100/120V)

0.1 - 70Ω (Ιn=5A, Vn=100/120V)

2 - 1400Ω (Ιn=1A, Vn=380/480V)

0.4 - 280Ω (Ιn=5A, Vn=380/480V)

0.5Ω

0.1Ω

2Ω

0.4Ω

ZB (Lens Reverse reach)

0.5 - 350Ω (Ιn=1A, Vn=100/120V)

0.1 - 70Ω (Ιn=5A, Vn=100/120V)

2 - 1400Ω (Ιn=1A, Vn=380/480V)

0.4 - 280Ω (Ιn=5A, Vn=380/480V)

0.5Ω

0.1Ω

2Ω

0.4Ω

Lens Angle (α) 90° - 150° 1°

Timer T1 0 - 1s 0.01s

Timer T2 0 - 1s 0.01s

Blinder Angle (θ) 20° - 90° 1°

Zc (Reactance line)

0.5 - 350Ω (Ιn=1A, Vn=100/120V)

0.1 - 70Ω (Ιn=5A, Vn=100/120V)

2 - 1400Ω (Ιn=1A, Vn=380/480V)

0.4 - 280Ω (Ιn=5A, Vn=380/480V)

0.5Ω

0.1Ω

2Ω

0.4Ω

Zone1 Slip Count 1- 20 1

Zone2 Slip Count 1- 20 1

Reset Time 0 -100s 0.01s

10.22.1 Accuracy

Lens characteristic Setting ±5%

Blinder ±1°Pick-up

Reactance line Setting ±5%

Lens DO characteristic Lens angle adjusted by -5°, forward andreverse reach (ZA+ZB) + 5%

Lens DO Lens DO characteristic ±5%

Blinder DOcharacteristic Blinder displaced by (ZA+ZB)/2 x tan 87.5°

Drop-off

Blinder DO Blinder DO characteristic ±1°

Repeatability <2.5%

T1, T2 and Reset Timer ±2% or 10ms whichever is greater



10.22.2 Hysteresis

Hysteresis is applied to the lenticular characteristic and to the blinder as soon as theypick up individually. Hysteresis is not required for the reactance line as Zone 1 orZone 2 is determined at a single point when the locus traverses the blinder.

For the lens, the hysteresis consists of an angle of 5° subtracted from the α setting toincrease the lens size and an increment of 5% applied to ZA and ZB to extend thereach.

Hysteresis for the blinder is dependant on the mode of operation. For generatingmode, the blinder is adjusted to the right, for motoring mode, the blinder is adjustedto the left, with a distance which is equivalent to an angle separation of 175°. This isshown in Figure 4. This distance is equivalent to (ZA + ZB) / 2*tan87.5°.

For both characteristics the hysteresis is reset when the impedance locus leaves thelens.

0

*)1

2

3

//

4!

5

4!

&,"(

Figure 4: Hysteresis of the pole slipping characteristic

10.23 Thermal overload (49)


Thermal I> 0.5 - 2.5 Ιn 0.01 Ιn

Thermal Alarm 20 -100% 1%

T-heating 1 - 200 minutes 1 minute

T-cooling 1 - 200 minutes 1 minute

M Factor 0 - 10 1



10.23.1 Accuracy

Pick-up Thermal alarm Calculated trip time ±5%

Thermal overload Calculated trip time ±5%

Cooling time accuracy ±5% of theoretical

Repeatability <2.5%

11. SUPERVISORY FUNCTIONS

11.1 Voltage transformer supervision


Negative phase sequencevoltage threshold (V2) 10V (100/120V) 40V (380/480V) Fixed

Phase overvoltageP.U. 30V, D.O. 10V (100/120V)

P.U.120V, D.O.40V (380/480V)Fixed

Superimposed current 0.1 Ιn Fixed

VTS Ι2> Inhibit 0.05 Ιn to 0.5 Ιn 0.01 Ιn

VTS Ι> Inhibit 0.08 Ιn to 32 Ιn 0.01 Ιn

VTS Time Delay 1.0 – 10s 0.1s

11.1.1 Accuracy

Fast block operation <25ms

Fast block reset <30ms

Time delay Setting ±2% or 20ms whichever is greater

11.2 Current transformer supervision

The ΙN and VN thresholds take the same values as set for the directional earth faultelement.


VN < 0.5 - 22V (Vn = 100/120V)2 - 88V (Vn = 380 / 440V)

0.5V2V

ΙN> 0.08Ιn - 4Ιn 0.01Ιn

Time delay t 0 - 10s 1s

CTS Time Delay 0 - 10s 1s



11.2.1 Accuracy

ΙN> Setting ±5%Pick-up

VN < Setting ±5%

ΙN> 0.9 x Setting ±5%Drop-off

VN < (1.05 x Setting) ±5% or 1V whichever is greater

Time delay operation Setting ±2% or 20ms whichever is greater

CTS block operation < 1 cycle

CTS reset < 35ms

12. PROGRAMMABLE SCHEME LOGIC

12.1 Level settings


Time delay t 0-14400000ms (4 hrs) 1ms

12.2 Accuracy

Output conditioner timer Setting ±2% or 50ms whichever is greater

Dwell conditioner timer Setting ±2% or 50ms whichever is greater

Pulse conditioner timer Setting ±2% or 50ms whichever is greater

13. MEASUREMENTS AND RECORDING FACILITIES

13.1 Measurements

Accuracy under reference conditions.

Measurand Range Accuracy

Current 0.05 to 3 Ιn ±1.0% of reading

Voltage 0.05 to 2 Vn ±1.0% of reading

Power (W)0.2 to 2 Vn0.05 to 3 Ιn

±5% of reading at unitypower factor

Reactive Power (VArs)0.2 to 2 Vn0.05 to 3 Ιn

±5% of reading at zeropower factor

Apparent Power (VA)0.2 to 2 Vn0.05 to 3 Ιn ±5% of reading

Energy (Wh)0.2 to 2 Vn0.2 to 3 Ιn


Energy (Varh)0.2 to 2 Vn0.2 to 3 Ιn


Phase accuracy 0° to 360° ±0.5°



Measurand Range Accuracy

Frequency 5 to 70Hz ±0.025Hz

13.2 IRIG-B and real time clock

13.2.1 Features

Real time 24 hour clock settable in hours, minutes and seconds

Calendar settable from January 1994 to December 2092

Clock and calendar maintained via battery after loss of auxiliary supply

Internal clock synchronisation using IRIG-B

Interface for IRIG-B signal is BNC

13.2.2 Performance

Year 2000 Compliant

Real time clock accuracy < ±1 second / day

Modulation ratio 1/3 or 1/6

Input signal peak-peak amplitude 200 mV to 20 V

Input impedance at 1000 Hz 6000 Ω

External clock synchronisation Conforms to IRIG standard 200-98, formatB12X

13.3 Current loop input and outputs (CLIO)

Current loop inputs


CLI1 Input Type 0-1mA, 0-10mA, 0-20mA, 4-20mA

CLI1 Minimum -9999 to +9999 0.1

CLI1 Maximum -9999 to +9999 0.1

CLI1 Alarm Fn Over/Under

CLI1 Alarm Set CLI1 Minimum - CLI1 Maximum

CLI1 Alarm Delay 0-100s 0.1s

CLI1 Trip Fn Over/Under

CLI1 Trip Set CLI1 Minimum - CLI1 Maximum

CLI1 Trip Delay 0-100s 0.1s

CLI1 I< Alm Set(4-20 mA input only) 0-4mA 0.1mA

Stage 2/3/4 Same as stage 1




Current loop outputs


CLO1 Output Type 0-1mA, 0-10mA, 0-20mA, 4-20mA

CLO1 Set Values Primary/Secondary

CLO1 Parameter A list of parameters are shown in the tablebelow

CLO1 Minimum Range, step size and unit corresponds to theselected parameter in the table below

CLO1 Maximum Range, step size and unit corresponds to theselected parameter in the table below

Repeat for current loop outputs 2, 3 and 4

Current loop output parameters are shown in the following table:

Current LoopOutput


DefaultMin

DefaultMax

Current Magnitude IA MagnitudeIB MagnitudeIC MagnitudeIN Measured Mag

A 0 to 16A 0.01A 0A 1.2A

Sensitive CurrentInput Magnitude

I Sen Magnitude A 0 to 2A 0.01A 0A 1.2A

Phase SequenceCurrentComponents

I1 MagnitudeI2 MagnitudeI0 Magnitude

A 0 to 16A 0.01A 0A 1.2A

RMS Phase Currents IA RMS*IB RMS*IC RMS*

A 0 to 16A 0.01A 0A 1.2A

P-P VoltageMagnitude

VAB MagnitudeVBC MagnitudeVCA Magnitude

V 0 to 200V 0.1V 0V 140V

P-N voltageMagnitude

VAN MagnitudeVBN MagnitudeVCN Magnitude

V 0 to 200V 0.1V 0V 80V

Neutral VoltageMagnitude

VN Measured MagVN Derived Mag

V 0 to 200V 0.1V 0V 80V

3rd HarmonicNeutral Voltage

VN 3rd Harmonic V 0 to 200V 0.1V 0V 80V

Phase SequenceVoltageComponents

V1 Magnitude*V2 MagnitudeV0 Magnitude

V 0 to 200V 0.1V 0V 80V

RMS Phase Voltages VAN RMS*VBN RMS*VCN RMS*

V 0 to 200V 0.1V 0V 80V

Frequency Frequency Hz 0 to 70Hz 0.01Hz 45Hz 65Hz

3 Ph Active Power 3 Phase Watts* W -6000Wto

6000W

1W 0W 300W

3 Ph Reactive Power 3 Phase Vars* Var -6000Varto

6000Var

1Var 0Var 300Var



Current LoopOutput


DefaultMin

DefaultMax

3 Ph ApparentPower

3 Phase VA* VA 0to

6000VA

1VA 0VA 300VA

3 Ph Power Factor 3Ph Power Factor* - -1 to 1 0.01 0 1

Single Phase ActivePower

A Phase Watts*B Phase Watts*C Phase Watts*

W -2000Wto

2000W

1W 0W 100W

Single PhaseReactive Power

A Phase Vars*B Phase Vars*C Phase Vars*

Var -2000Varto

2000Var

1Var 0Var 100Var

Single PhaseApparent Power

A Phase VA*B Phase VA*C Phase VA*

VA 0to

2000VA

1VA 0VA 100VA

Single Phase PowerFactor

APh Power Factor*BPh Power Factor*CPh Power Factor*

-1 to 1 0.01 0 1

3 Phase CurrentDemands

IA Fixed Demand*IB Fixed Demand*IC Fixed Demand*IA Roll Demand*IB Roll Demand*IC Roll Demand*IA Peak Demand*IB Peak Demand*IC Peak Demand*

A 0 to 16A 0.01A 0A 1.2A

3Ph Active PowerDemands

3Ph W Fix Demand*3Ph W Roll Dem*3Ph W Peak Dem*

W -6000Wto

6000W

1W 0W 300W

3Ph Reactive PowerDemands

3Ph Vars Fix Dem*3Ph Var Roll Dem*3Ph Var Peak Dem*

Var -6000Varto

6000Var

1Var 0Var 300Var

Rotor Thermal State NPS Thermal % 0 to 200 0.01 0 120

Stator ThermalState

Thermal Overload % 0 to 200 0.01 0 120

RTD Temperatures RTD 1*RTD 2*RTD 3*RTD 4*RTD 5*RTD 6*RTD 7*RTD 8*RTD 9*RTD 10*

°C -40°Cto

300°C

0.1°C 0°C 200°C

Current Loop Inputs CL Input 1CL Input 2CL Input 3CL input 4

- -9999to

9999

0.1 0 9999

Note 1: For measurements marked with an asterisk, the internal refreshrate is nominally 1s, others are 0.5 power system cycle or less.

Note 2: The polarity of Watts, Vars and power factor is affected by theMeasurements Mode setting.



Note 3: These settings are for nominal 1A and 100/120V versions only.For other nominal versions they need to be multipliedaccordingly.

Note 4: For the P343, the IA/IB/IC Current magnitudes are IA-1Magnitude, IB-1 Magnitude, IC-1 Magnitude.

13.3.1 Accuracy

Current loop input accuracy ±1% of full scale

Under setting +1% of full scaleCurrent loop inputdrop-off threshold Over setting -1% of full scale

Current loop input sampling interval 50ms

Current loop input instantaneousoperating time < 250ms

Current loop input DT operating time ±2% setting or 200ms whichever is thegreater

Current loop output conversion interval 50ms

Current loop output latency

<1.07s or <70ms depending on theCLIO output parameter’s internalrefresh rate – (1s or 0.5 cycle, see tableabove)

Current loop output accuracy ±0.5% of full scale

Repeatability <5%

With the current loop input set to instantaneous operation, two consecutiveacquisitions of data are required for an operate decision to be made.

13.3.2 Other specifications

Current loop input load resistance 0-1mA <4kΩ

Current loop input load resistance 0-10mA/0-20mA/4-20mA <300Ω

Isolation between common input channels Zero

Isolation between input channels and case earth/other circuits 2kV rms for1 minute

0-1mA/0-10mA 10VCurrent loop output compliance voltage

0-20mA/4-20mA 8.8V

Current loop output open circuit voltage <25V

Isolation between common output channels Zero

Isolation between output channels and case earth/other circuits 2kV rms for1 minute



14. DISTURBANCE RECORDS

14.1 Level settings


Duration 0.1 – 10.5s 10ms

Trigger position 0 – 100% 0.1%

8 analogue channels, 32 digital channels, single or extended trigger modes

14.2 Accuracy

Magnitude and relative phases ±5% of applied quantities

Duration ±2%

Trigger position ±2% (minimum trigger 100ms)

15. PLANT SUPERVISION

15.1 CB state monitoring control and condition monitoring

15.1.1 CB monitor settings

Setting Range Step

Broken Ι^ (mult) 1 – 2 0.1

Ι^ Maintenance 1 – 25000 (x (CT ratio^mult)) A 1 (x (CT ratio^mult)) A

Ι^ Lockout 1 – 25000 (x (CT ratio^mult)) A 1 (x (CT ratio^mult)) A

No CB Ops maintenance 1 – 10000 1

No CB Ops lockout 1 – 10000 1

CB time maintenance 0.005 – 0.5s 0.001s

CB time lockout 0.005 – 0.5s 0.001s

Fault frequency count 0 – 9999 1

Fault frequency time 0 – 9999 1

15.1.2 CB control settings

Setting Range Step

Man close RstDly 0.01 – 600s 0.01s

15.1.3 Accuracy

Timers ±2% or 20ms whichever is greater

Broken current accuracy ±5%



15.2 CB fail and backtrip breaker fail

15.2.1 Timer settings

Setting Range Step

CB fail 1 timer 0 – 10s 0.01s

CB fail 2 timer 0 – 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 device is notapplicable)

15.2.2 Timer accuracy

Timers ±2% or 40ms whichever is greater

Reset time <30ms

15.2.3 Undercurrent settings


Phase Ι< 0.02 - 3.2 Ιn 0.01 Ιn

Earth ΙN< 0.02 - 3.2 Ιn 0.01 Ιn

Sensitive Earth ΙSEF< 0.001 - 0.8 Ιn 0.0005 Ιn

15.2.4 Undercurrent accuracy

Pick-up ±10% or 25mA whichever is the greater

Operating time <12ms (Typical <10ms)

Reset <15ms (Typical <10ms)

16. INPUT AND OUTPUT SETTING RANGES

16.1 CT and VT ratio settings

The primary and secondary rating can be independently set for each set of CT or VTinputs, for example the earth fault CT ratio can be different to that used for the phasecurrents.

Primary Range Secondary Range

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

Voltage transformer 100V to 1000 kVstep size 1V

80 to 140V (Vn = 100/120V)320 to 560V (Vn = 380/480V)



17. BATTERY LIFE

Battery life (assuming relay energised for 90% of time) > 10 years

1/2 AA size 3.6 V lithium thionyl chloride battery (SAFT advanced battery referenceLS14250)

18. FREQUENCY RESPONSE

With the exception of the RMS measurements all other measurements and protectionfunctions are based on the Fourier derived fundamental component. Thefundamental component is extracted by using a 24 sample Discrete FourierTransform (DFT). This gives good harmonic rejection for frequencies up to the 23rd

harmonic. The 23rd is the first predominant harmonic that is not attenuated by theFourier filter and this is known as an ‘Alias’. However, the Alias is attenuated byapproximately 85% by an additional, analogue, ‘anti-aliasing’ filter (low pass filter).The combined affect of the anti-aliasing and Fourier filters is shown below:

0

0.2

0.4

0.6

0.8

1

1.2

0 5 10 15 20 25Harmonic

Ma

gn

itu

de (

per

un

it)

Combined response of fourierand anti-aliasing filters

Anti-aliasing filter response

Power frequency (eg 50/60 Hz)

P1124ENa

Figure 5: Frequency response

For power frequencies that are not equal to the selected rated frequency theharmonics would not be attenuated to zero amplitude. For small deviations of ±1Hz,this is not a problem but to allow for larger deviations, an improvement is obtainedby the addition of frequency tracking.

With frequency tracking the sampling rate of the analogue / digital conversion isautomatically adjusted to match the applied signal. In the absence of a suitablesignal to amplitude track, the sample rate defaults to the selected rated frequency(Fn). In the presence of a signal within the tracking range (5 to 70Hz), the relay willlock on to the signal and the measured frequency will coincide with the powerfrequency as labelled in the diagram above. The resulting outputs for harmonics upto the 23rd will be zero.



19. LOCAL AND REMOTE COMMUNICATIONS

The following claims for Local & Remote Communications are applicable to the P34xrange of generator relays.

19.1 Front Port

Setting

Protocol Courier

Message format IEC 60870-5 FT1.2

Baud rate 19 200 bits/s

19.2 Rear Port

Rear Port Settings Setting Options Setting Available For:

Physical links EIA(RS)485 or Fibre opticEIA(RS)485 only

IEC 60870-5-CS103only Courier, Modbusand DNP3.0

Remote address 0 - 255 (step 1) IEC 60870-5-CS103and Courier

Modbus address 1 - 247 (step 1) Modbus only

DNP3.0 address 1 - 65519 (step 1) DNP3.0 only

Baud rate 9600 or 19200 bits/s IEC 60870-5-CS103only

9600/19200/38400bits/s

Modbus only

64,000 bits/s Courier

1200/2400/4800/9600/19200/38400 bits/s

DNP3.0

Inactivity timer 1 - 30 minutes (step 1) Not DNP3.0

Parity “Odd”, “Even” or “None” Modbus or DNP3.0

Measurement period 1 - 60 minutes (step 1) IEC only

Time sync Enabled / Disabled DNP3.0

19.2.1 Performance

Front and rear ports conforming to Courier communication protocol Compliant

Rear ports conforming to Modbus communication protocol Compliant

Rear ports conforming to IEC 60870-5-CS103 communicationprotocol Compliant

Rear ports conforming to DNP3.0 communication protocol Compliant



19.3 Second rear communications port

Setting Setting Options Setting Available For:

RP2 Port Config EIA(RS)232, EIA(RS)485or kbus

RP2 Comms Mode IEC60870 FT1.2, 11bitframe or

IEC60870, 10 bit frame

EIA(RS)232 andEIA(RS)485

RP2 Address 0 – 255 (step 1) All

RP2 InactivTimer 1 – 30 minutes (step 1) All

RP2 Baud Rate 9600/19200/38400bits/s

EIA(RS)232 andEIA(RS)485

Note: To avoid exceeding second rear communications port flashclearances the length of the cable, between the port andassociated communications equipment should be limited to 300metres. In situations where 300 metres may be insufficient itmust be ensured that the communications cable is not laid inclose proximity to high current carrying conductors. Thecommunications cable should be screened with screen earthedat one end only.


MiCOM P342, P343

SCADA COMMUNICATIONS

P34x/EN CT/F33 SCADA Communications

MiCOM P342, P343



CONTENTS

1 INTRODUCTION 5

2 COURIER INTERFACE 5

2.1 Courier protocol 5

2.2 Front courier port 6

2.3 Supported command set 6

2.4 Relay courier database 7

2.5 Setting changes 8

2.5.1 Method 1 8

2.5.2 Method 2 8

2.5.3 Relay settings 8

2.5.4 Setting transfer mode 9

2.6 Event extraction 9

2.6.1 Automatic event extraction 9

2.6.2 Event types 9

2.6.3 Event format 10

2.6.4 Manual event record extraction 10

2.7 Disturbance record extraction 10

2.8 Programmable scheme logic settings 11

3 MODBUS INTERFACE 12

3.1 Communication link 12

3.2 MODBUS functions 12

3.3 Response codes 13

3.4 Register mapping 13


3.5.1 Manual selection 14

3.5.2 Automatic extraction 14

3.5.3 Record data 14


3.6.1 Manual selection 15

3.6.2 Automatic extraction 16

3.6.3 Record data 16

3.7 Setting changes 16



3.7.1 Password protection 17

3.7.2 Control and support settings 17

3.7.3 Protection and disturbance recorder settings 17

3.8 Date and time format (data type G12) 17

3.9 Power & energy measurement data formats (G29 & G125) 19

3.9.1 Data type G29 19

3.9.2 Data type G125 20

4 IEC60870-5-103 interface 21

4.1 Physical connection and link layer 21

4.2 Initialisation 21

4.3 Time synchronisation 21

4.4 Spontaneous events 22

4.5 General interrogation 22

4.6 Cyclic measurements 22

4.7 Commands 22

4.8 Test mode 22

4.9 Disturbance records 22

4.10 Blocking of monitor direction 23

5 DNP3 INTERFACE 23

5.1 DNP3 protocol 23

5.2 DNP3 menu setting 23

5.3 Object 1 binary inputs 23

5.4 Object 10 binary outputs 24

5.5 Object 20 binary counters 24

5.6 Object 30 analogue input 24

5.7 DNP3 configuration using MiCOM S1 25

5.7.1 Object 1 25

5.7.2 Object 20 25

5.7.3 Object 30 25

6 SECOND REAR COMMUNICATIONS PORT (COURIER) 26

6.1 Courier protocol 26



6.4 Connection to the second rear port 27



7 SK5 PORT CONNECTION 27





1 INTRODUCTION

This section describes the remote interfaces of the MiCOM relay in enough detail toallow integration within a substation communication network. As has been outlinedin earlier sections, the relay supports a choice of one of four protocols via the rearcommunication interface. This is in addition to the front serial interface and 2nd rearcommunications port, which supports the Courier protocol only.

The rear EIA(RS)485 interface is isolated and is suitable for permanent connectionwhichever protocol is selected. The advantage of this type of connection is that up to32 relays can be ‘daisy chained’ together using a simple twisted pair electricalconnection.

For each of the protocol options, the supported functions/commands will be listedtogether with the database definition. The operation of standard procedures such asextraction of event, fault and disturbance records, or setting changes, will also bedescribed.

It should be noted that the descriptions contained within this section do not aim tofully detail the protocol itself. The relevant documentation for the protocol should bereferred to for this information. This section serves to describe the specificimplementation of the protocol in the relay.

2 COURIER INTERFACE

2.1 Courier protocol

Courier is an AREVA T&D communication protocol. The concept of the protocol isthat a standard set of commands are used to access a database of settings and datawithin the relay. This allows a generic master to be able to communicate withdifferent slave devices. The application specific aspects are contained within thedatabase itself rather than the commands used to interrogate it, i.e. the masterstation does not need to be pre-configured.

The same protocol can be used via two physical links K-Bus or EIA(RS)232.

K-Bus is based on EIA(RS)485 voltage levels with HDLC FM0 encoded synchronoussignalling and its own frame format. The K-Bus twisted pair connection isunpolarised, whereas the EIA(RS)485 and EIA(RS)232 interfaces are polarised.

The EIA(RS)232 interface uses the IEC60870-5 FT1.2 frame format.

The relay supports an IEC60870-5 FT1.2 connection on the front-port. This isintended for temporary local connection and is not suitable for permanentconnection. This interface uses a fixed baud rate, 11-bit frame, and a fixed deviceaddress.

The rear interface is used to provide a permanent connection for K-Bus and allowsmulti-drop connection. It should be noted that although K-Bus is based onEIA(RS)485 voltage levels it is a synchronous HDLC protocol using FM0 encoding. Itis not possible to use a standard EIA(RS)232 to EIA(RS)485 converter to convertIEC60870-5 FT1.2 frames to K-Bus. Nor is it possible to connect K-Bus to anEIA(RS)485 computer port. A protocol converter, such as the KITZ101, should beemployed for this purpose.

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

2.2 Front courier port

The front EIA(RS)2321 9 pin port supports the Courier protocol for one to onecommunication. It is designed for use during installation andcommissioning/maintenance and is not suitable for permanent connection. Since thisinterface will not be used to link the relay to a substation communication system,some of the features of Courier are not implemented. These are as follows:

Automatic extraction of Event Records:

− Courier Status byte does not support the Event flag

− Send 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.

Fixed Baud Rate:

− 19200 bps

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 front port.

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*

1 This port is actually compliant to EIA(RS)574; the 9-pin version of EIA(RS)232, see www.tiaonline.org.



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

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 frontCourier port.

2.4 Relay courier database

The Courier database is a 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 as hexadecimalvalues, e.g. 0A02 is column 0A (10 decimal) row 02. Associated settings/data will bepart of the same column, row zero of the column contains a text string to identify thecontents of the column, i.e. a column heading.

P34x/EN GC contains the complete database definition for the relay. For each celllocation the following information is stated:

− Cell Text

− Cell Datatype

− Cell value

− Whether 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 R6512, 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

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 by thisaction.

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 to thiscommand will be either a positive confirm or an error code to indicate the nature of afailure. This command can be used to implement a setting more rapidly then theprevious method, however the limits are not extracted from the relay. This method ismost suitable for off-line setting editors such as MiCOM S1, or for the issuing of pre-configured (SCADA) control commands.

2.5.3 Relay settings

There are three categories of settings within the relay database

− Control and Support

− Disturbance Recorder

− Protection Settings Group

Setting changes made to the control and support settings are implementedimmediately and stored in non-volatile memory. Changes made to either theDisturbance recorder settings or the Protection Settings Groups are stored in a‘scratchpad’ memory and are not immediately implemented by the relay.



To action setting changes stored in the scratchpad the Save Changes cell in theConfiguration column must be written to. This allows the changes to either beconfirmed and stored in non-volatile memory, or the setting 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 within theCommunication System Data column can be used. This cell (location BF03) when setto 1 makes all of the relay settings visible. Any setting changes made, with the relayset in this mode, are stored in scratchpad memory (including control and supportsettings). When the value of BF03 is set back to 0 any setting changes are verifiedand 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 event 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.

2.6.1 Automatic event extraction

(See Chapter 7 Courier User Guide, publication R6512)

This method is intended for continuous extraction of event and fault information as itis 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, thisindicates 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 0 orType 3 event. The Type 3 event is used for fault records and maintenance records.

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 extracted thenext 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 the relay:

− Cell Reference

− Timestamp

− Cell Text

− Cell Value

The menu database, P34x/EN GC, contains a table of the events created by the relayand indicates how the contents of the above fields are interpreted. Fault records andMaintenance records will return a Courier Type 3 event, which contains the abovefields together with two additional fields:

− Event extraction column

− Event number

These events contain additional information that is extracted from the relay using thereferenced extraction column. Row 01 of the extraction column contains a settingthat allows the fault/maintenance record to be selected. This setting should be set tothe event number value returned within the record, the extended data can beextracted from the relay by uploading the text and data from the column.

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 on the nature of therecord selected. It is possible to select events by event number and to directly select afault record or maintenance record by number.

Event Record selection (Row 01) - This cell can be set to a value between 0 to 249 toselect which of the 250 stored events is selected, 0 will select the most recent record;249 the oldest stored record. For simple event records, (Type 0) cells 0102 to 0105contain the event details. A single cell is used to represent each of the event fields. Ifthe event selected is a fault or maintenance record (Type 3) then the remainder of thecolumn will contain the additional information.

Fault Record Selection (Row 05) – This cell can be used to directly select a fault recordusing a value between 0 and 4 to select one of up to five stored fault records. (0 willbe the most recent fault and 4 will be the oldest). The column will then contain thedetails 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 way tothe 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 new event orfault occurs.

2.7 Disturbance record extraction

The stored disturbance records within the relay are accessible in a compressed formatvia the Courier interface. The records are extracted using column B4. It should benoted that cells required for extraction of uncompressed disturbance records are notsupported.



Select Record Number (Row 01) - This cell can be used to select the record to beextracted. Record 0 will be the oldest unextracted record, already extracted olderrecords will be assigned positive values, and negative values will be used for morerecent records. To facilitate automatic extraction via the rear port the Disturbance bitof the Status byte is set by the relay whenever there are unextracted disturbancerecords.

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 extracted usingthe 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.

2.8 Programmable scheme logic settings

The programmable scheme logic (PSL) settings can be uploaded from anddownloaded to the relay using the block transfer mechanism defined in Chapter 12of the Courier User Guide.

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 beuploaded/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 MiCOM S1must be used as the data format is compressed. MiCOM S1 also performs checks onthe validity of the settings before they are downloaded to the relay.



3 MODBUS INTERFACE

The MODBUS interface is a master/slave protocol and it is defined by MODBUS.org:See

www.modbus.org

MODBUS Serial Protocol Reference Guide: PI-MBUS-300 Rev. E

3.1 Communication link

This interface also uses the rear EIA(RS)485 port for communication using ‘RTU’mode communication rather than ‘ASCII’ mode as this provides more efficient use ofthe communication bandwidth. This mode of communication is defined by theMODBUS standard.

In summary, the character framing is 1 start bit, 8 bit data, either 1 parity bit and 1stop bit, or two stop bits. This gives 11 bits per character.

The following parameters can be configured for this port using either the front panelinterface 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

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 (0xxxx addresses)

02 Read status of opto inputs (1xxxx 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 Interpretation

01 Illegal Function Code The function code transmitted is notsupported by the slave

02 Illegal Data Address The start data address in the request isnot an allowable value. If any of theaddresses in the range 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 withinthe same packet will be executed if insiderange.

06 Slave Device Busy The write command cannot beimplemented due to the database beinglocked by another interface. Thisresponse is also produced if the relaysoftware is busy executing a previousrequest.

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 inmenu database, P34x/EN GC, of this service manual.

Note that MODBUS convention is to document register addresses as ordinal valueswhereas the actual protocol addresses are literal values. The MiCOM relays begintheir register addresses at zero. Thus, the first register in a memory page is registeraddress zero. The second register is register address 1 and so on. Note that thepage number notation is not part of the address.


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 stored record.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 by therelay. If this event record is selected the additional registers allowing the fault ormaintenance 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 (G26 data type). If the event bit of this register is set then the relay hasunextracted events available. To select the next event for sequential extraction themaster station writes a value of 1 to the record selection register 40400 (G18 datatype). The event data together with any fault/maintenance data can be read from theregisters specified below. Once the data has been read the event record can bemarked as having been read by writing a value of 2 to register 40400.

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 detailed above.

EventDescription

MODBUSAddress Length Comments

Time and Date 30103 4 See G12 data type description in section3.8.

Event Type 30107 1 See G13 data type. Indicates type of event

Event Value 30108 2 Nature of Value depends on Event Type.This will contain the status as a binary flagfor Contact, Opto, Alarm, and protectionevents.



EventDescription

MODBUSAddress Length Comments

MODBUSAddress

30110 1 This indicates the MODBUS Registeraddress where the change occurred.Alarm 30011Relays 30723Optos 30725Protection events – Like the Relay andOpto addresses this will map onto theMODBUS address of the appropriate DDBstatus register depending on which bit ofthe DDB the change occurred. These willrange from 30727 to 30785.

For Platform events, Fault events andMaintenance events the default is 0.

Event Index 30111 1 This register will contain the DDB ordinalfor protection events or the bit number foralarm events. The direction of the changewill be indicated by the most significant bit;1 for 0 – 1change and 0 for 1 – 0 change.

AdditionalData Present

30112 1 0 means that there is no additional data.

1 means fault record data can be readfrom 30113 to 30199 (number of registersdepends on the product).

2 means maintenance record data can beread from 30036 to 30039.

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 registers 30103 to 30111 will not be available.

It is possible using register 40401(G6 data type) to clear independently the storedrelay event/fault and maintenance records. This register also provides an option toreset the relay indications which has the same effect on the relay as pressing the clearkey within the alarm viewer using the front panel menu.


The relay provides facilities for both manual and automatic extraction of disturbancerecords. The two methods differ only in the mechanism for selecting a disturbancerecord, the method for extracting the data and the format of the data are 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 register 40250. Itis possible to read the timestamp of the selected record and in this way produce achronological 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 (G26 data type). When the disturbance bit of thisregister is set, disturbance records are available for extraction. To select the nextdisturbance record, write a value of 4 to register 40400 (G18 data type). Once thedisturbance record data has been read by the master station this record can bemarked as having been read by writing a value of 8 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 using apaging system.

The number of pages required to extract a record will depend on the configured sizeof the record.

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 be readfrom register 30802. It will have a value of 127 for all but the last page in therecord). Once the first page has been read, the next page can be selected by writinga value of 5 to register 40400. If this action is performed after the last page for thedisturbance record has been selected an illegal value error response will be returned.This error response can be used by the MODBUS master to indicate that the last pageof the disturbance 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 the protection setting groups or the disturbance recorder settings arestored in a temporary ‘scratchpad’ area and must be confirmed before they areimplemented. All the relay settings are 4xxxx page addresses. The following pointsshould be noted when changing settings:

− 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 changea setting is indicated in the relay setting database (P34x/EN GC). Level 2 is thehighest level of password access, level 0 indicates that no password is required.

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.

3.7.3 Protection and disturbance recorder settings

Setting changes to either of these areas are stored in a scratchpad area and will notbe used by the relay unless a confirm or an abort operation is performed. Register40405 can be used either to confirm or abort the setting changes within thescratchpad area. It should be noted that the relay supports four groups of protectionsettings. The MODBUS addresses for each of the four groups are repeated within thefollowing 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 settingsby writing 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 two operationsdefined above are made to the scratchpad area. These changes must be confirmedby writing to register 40405.

The active protection setting groups can be selected by writing to register 40404. Anillegal data response will be returned if an attempt is made to set the active group toone that has been disabled.

3.8 Date and time format (data type G12)

The date-time data type G12 allows real date and time information to be conveyeddown to a resolution of 1ms. The structure of the data type is shown in Table 3-1and is compliant with the IEC60870-5-4 “Binary Time 2a” format.



The seven bytes of the structure are packed into four 16-bit registers, such that byte 1is transmitted first, followed by byte 2 through to byte 7, followed by a null (zero) byteto make eight bytes in total. Since register data is usually transmitted in big-endianformat (high order byte followed by low order byte), byte 1 will be in the high-orderbyte position followed by byte 2 in the low-order position for the first register. Thelast register will contain just byte 7 in the high order position and the low order bytewill have a value of zero.

Bit PositionByte

7 6 5 4 3 2 1 0

1 m7 m6 m5 m4 m3 m2 m1 m0

2 m15 m14 m13 m12 m11 m10 m9 m8

3 IV R I5 I4 I3 I2 I1 I0

4 SU R R H4 H3 H2 H1 H0

5 W2 W1 W0 D4 D3 D2 D1 D0

6 R R R R M3 M2 M1 M0

7 R Y6 Y5 Y4 Y3 Y2 Y1 Y0

Where:

− m = 0…59,999ms

− I = 0…59 minutes

− H = 0…23 Hours

− W = 1…7 Day of week; Monday to Sunday, 0 for not calculated

− D = 1…31 Day of Month

− M = 1…12 Month of year; January to December

− Y = 0…99 Years (year of century)

− R = Reserved bit = 0

− SU = summertime: 0=standard time, 1=summer time

− IV = invalid value: 0=valid, 1=invalid

− range = 0ms…99 years

Table 3-1 G12 Date & time data type structure

Since the range of the data type is only 100 years, the century must be deduced. Thecentury is calculated as the one that will produce the nearest time value to the currentdate. For example: 30-12-99 is 30-12-1999 when received in 1999 & 2000, but is30-12-2099 when received in 2050. This technique allows 2 digit years to beaccurately converted to 4 digits in a ±50 year window around the current datum.

The invalid bit has two applications:

1. It can indicate that the date-time information is considered inaccurate, but is thebest information available.

2. Date-time information is not available.



The summertime bit is used to indicate that summertime (day light saving) is beingused and, more importantly, to resolve the alias and time discontinuity which occurswhen summertime starts and ends. This is important for the correct time correlationof time stamped records.

The day of the week field is optional and if not calculated will be set to zero.

The concept of time zone is not catered for by this data type and hence by the relay.It is up to the end user to determine the time zone utilised by the relay. Normalpractise is to use UTC (universal co-ordinated time), which avoids the complicationswith day light saving time-stamp correlation’s.

3.9 Power & energy measurement data formats (G29 & G125)

The power and energy measurements are available in two data formats; G29 integerformat and G125 IEEE754 floating point format. For historical reasons the registerslisted in the main part of the “Measurements 2” column of the menu database (seeP34x/EN GC) are of the G29 format. The floating point, G125, versions appear atthe end of the column.

3.9.1 Data type G29

Data type G29 consists of three registers. The first register is the per unit power orenergy measurement and is of type G28, which is a signed 16 bit quantity. Thesecond and third registers contain a multiplier to convert the per unit value to a realvalue. The multiplier is of type G27, which is an unsigned 32-bit quantity. Thus, theoverall value conveyed by the G29 data type must be calculated as G29=G28×G27.

The relay calculates the G28 per unit power or energy value as G28=((measuredsecondary quantity) / (CT secondary) × (110V / (VT secondary)). Since data type G28is a signed 16-bit integer, its dynamic range is constrained to ±32768. Thislimitation should be borne in mind for the energy measurements, as the G29 valuewill saturate a long time before the equivalent G125 does.

The associated G27 multiplier is calculated as G27=(CT primary) × (VT primary /110V) when primary value measurements are selected, and as G27=(CT secondary)× (VT secondary / 110V) when secondary value measurements are selected.

Due to the required truncations from floating point values to integer values in thecalculations of the G29 component parts and its limited dynamic range, the use ofthe G29 values is only recommended when the MODBUS master cannot deal withthe G125 IEEE754 floating point equivalents.

Note that the G29 values must be read in whole multiples of three registers. It is notpossible to read the G28 and G27 parts with separate read commands.

Example:

For A-Phase Power (Watts) (registers 30300 - 30302) for a 110V relay, In = 1A, VTratio = 110V:110V and CT ratio = 1A:1A.

Applying A-phase 1A @ 63.51V

A-phase Watts = ((63.51V × 1A) / In=1A) × (110/Vn=110V) = 63.51 Watts

The G28 part of the value is the truncated per unit quantity, which will be equal to 64(40h).

The multiplier is derived from the VT and CT ratios set in the relay, with the equation((CT Primary) × (VT Primary) / 110V). Thus, the G27 part of the value will equal 1.Hence the overall value of the G29 register set is 64×1 = 64W



The registers would contain:

30300 - 0040h

30301 - 0000h

30302 - 0001h

Using the previous example with a VT ratio = 110,000V:110V and CT ratio =10,000A:1A the G27 multiplier would be 10,000A×110,000V/110 = 10,000,000.The overall value of the G29 register set is 64 × 10,000,000 = 640MW. (Note thatthere is an actual error of 49MW in this calculation due to loss of resolution.)

The registers would contain:

30300 - 0040h

30301 - 0098h

30302 - 9680h

3.9.2 Data type G125

Data type G125 is a short float IEEE754 floating point format, which occupies 32 bitsin two consecutive registers. The high order byte of the format is in the first (loworder) register and the low order byte in the second register.

The value of the G125 measurement is as accurate as the relay’s ability to resolve themeasurement after it has applied the secondary or primary scaling factors as require.It does not suffer from the truncation errors or dynamic range limitations associatedwith the G29 data format.



4 IEC60870-5-103 interface

The IEC60870-5-103 interface is a master/slave interface with the relay as the slavedevice. The relay conforms to compatibility level 2, compatibility level 3 is notsupported.

The following IEC60870-5-103 facilities are supported by this interface:

− Initialisation (Reset)

− Time Synchronisation

− Event Record Extraction

− General Interrogation

− Cyclic Measurements

− General Commands

− Disturbance Record Extraction

− Private Codes

4.1 Physical connection and link layer

Two connection options are available for IEC60870-5-103, either the rearEIA(RS)485 port or an optional rear fibre optic port. Should the fibre optic port befitted the selection of the active port can be made via the front panel menu or thefront Courier port, however the selection will only be effective following the next relaypower up.

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, see reset command description below.

4.2 Initialisation

Whenever the relay has been powered up, or if the communication parameters havebeen changed a reset command is required to initialise the communications. Therelay will respond to either of the two reset commands (Reset CU or Reset FCB), thedifference being that the Reset CU will clear any unsent messages in the relay’stransmit 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 CU orReset FCB depending on the nature of the reset command. The content of ASDU 5 isdescribed in the IEC60870-5-103 section of the menu database, P34x/EN GC.

In addition to the above identification message, if the relay has been powered up itwill 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 the time-



synchronisation message is sent as a send confirm or a broadcast (send/no reply)message, a time synchronisation Class 1 event will be generated/produced.

If the relay clock is being synchronised using the IRIG-B input then it will not bepossible to set the relay time using the IEC60870-5-103 interface. An attempt to setthe time via the interface will cause the relay to create an event with the current dateand time taken from the IRIG-B synchronised internal clock.

4.4 Spontaneous events

Events are categorised using the following information:

− Function Type

− Information number

The IEC60870-5-103 profile in the menu database, P34x/EN GC, contains acomplete listing of all events produced by the relay.

4.5 General interrogation

The GI request can be used to read the status of the relay, the function numbers, andinformation numbers that will be returned during the GI cycle are indicated in theIEC60870-5-103 profile in the menu database, P34x/EN GC.

4.6 Cyclic measurements

The relay will produce measured values using ASDU 9 on a cyclical basis, this can beread from the relay using a Class 2 poll (note ADSU 3 is not used). The rate at whichthe relay produces new measured values can be controlled using the MeasurementPeriod setting. This setting can be edited from the front panel menu/front Courierport and is active immediately following a change.

It should be noted that the measurands transmitted by the relay are sent as aproportion of 2.4 times the rated value of the analogue value.

4.7 Commands

A list of the supported commands is contained in the menu database, P34x/EN GC.The relay will respond to other commands with an ASDU 1, with a cause oftransmission (COT) indicating ‘negative acknowledgement’.

4.8 Test mode

It is possible using either the front panel menu or the front Courier port to disable therelay output contacts to allow secondary injection testing to be performed. This isinterpreted as ‘test mode’ by the IEC60870-5-103 standard. An event will beproduced to indicate both entry to and exit from test mode. Spontaneous events andcyclic measured data transmitted whilst the relay is in test mode will have a COT of‘test mode’.

4.9 Disturbance records

The disturbance records are stored in uncompressed format and can be extractedusing the standard mechanisms described in IEC60870-5-103. Note, IEC60870-5-103 only supports up to 8 records.



4.10 Blocking of monitor direction

The relay supports a facility to block messages in the Monitor direction and also inthe Command direction. Messages can be blocked in the Monitor and Commanddirections using the menu commands, Communications – CS103 Blocking –Disabled/Monitor Blocking/Command Blocking or DDB signals Monitor Blocked andCommand Blocked.

5 DNP3 INTERFACE

5.1 DNP3 protocol

The DNP3 protocol is defined and administered by the DNP Users Group.Information about the user group, DNP3 in general and the protocol specificationscan be found on their Internet site:

www.dnp.org

The descriptions given here are intended to accompany the device profile documentwhich is included in the menu database, P34x/EN GC. The DNP3 protocol is notdescribed here, please refer to the documentation available from the user group.The device profile document specifies the full details of the DNP3 implementation forthe relay. This is the standard format DNP3 document that specifies which objects,variations and qualifiers are supported. The device profile document also specifieswhat data is available from the relay via DNP3. The relay operates as a DNP3 slaveand supports subset level 2 of the protocol, plus some of the features from level 3.

DNP3 communication uses the EIA(RS)485 communication port at the rear of therelay. The data format is 1 start bit, 8 data bits, an optional parity bit and 1 stop bit.Parity is configurable (see menu settings below).

5.2 DNP3 menu setting

The settings shown below are available in the menu for DNP3 in the‘Communications’ column.

Setting Range Description

Remote Address 0 – 65534 DNP3 address of relay (decimal)

Baud Rate 1200, 2400,4800, 9600,

19200, 38400

Selectable baud rate for DNP3communication

Parity None, Odd,Even

Parity setting

Time Sync Enabled,Disabled

Enables or disables the relay requestingtime sync from the master via IIN bit 4word 1

5.3 Object 1 binary inputs

Object 1, binary inputs, contains information describing the state of signals within therelay which mostly form part of the digital data bus (DDB). In general these includethe state of the output contacts and input optos, alarm signals and protection startand trip signals. The ‘DDB number’ column in the device profile document providesthe DDB numbers for the DNP3 point data. These can be used to cross-reference tothe DDB definition list which is also found in the menu database, P34x/EN GC. The



binary input points can also be read as change events via object 2 and object 60 forclass 1-3 event data.

5.4 Object 10 binary outputs

Object 10, binary outputs, contains commands which can be operated via DNP3. Assuch the points accept commands of type pulse on [null, trip, close] and latch on/offas detailed in the device profile in the menu database, P34x/EN GC and execute thecommand once for either command. The other fields are ignored (queue, clear,trip/close, in time and off time).

Due to that fact that many of the relay’s functions are configurable, it may be thecase that some of the object 10 commands described below are not available foroperation. In the case of a read from object 10 this will result in the point beingreported as off-line and an operate command to object 12 will generate an errorresponse.

Examples of object 10 points that maybe reported as off-line are:

− Activate setting groups - Ensure setting groups are enabled

− CB trip/close - Ensure remote CB control is enabled

− Reset NPS thermal - Ensure NPS thermal protection is enabled

− Reset thermal O/L - Ensure thermal overload protection is enabled

− Reset RTD flags - Ensure RTD Inputs is enabled

− Control Inputs - Ensure control inputs are enabled

5.5 Object 20 binary counters

Object 20, binary counters, contains cumulative counters and measurements. Thebinary counters can be read as their present ‘running’ value from object 20, or as a‘frozen’ value from object 21. The running counters of object 20 accept the read,freeze and clear functions. The freeze function takes the current value of the object20 running counter and stores it in the corresponding object 21 frozen counter. Thefreeze and clear function resets the object 20 running counter to zero after freezing itsvalue.

5.6 Object 30 analogue input

Object 30, analogue inputs, contains information from the relay’s measurementscolumns in the menu. All object 30 points are reported as fixed-point valuesalthough they are stored inside the relay in a floating point format. The conversion tofixed point format requires the use of a scaling factor, which differs for the varioustypes of data within the relay e.g. current, voltage, phase angle etc. The data typessupported are listed at the end of the device profile document with each typeallocated a ‘D number’, i.e. D1, D2, etc. In the object 30 point list each data pointhas a D number data type assigned to it which defines the scaling factor, defaultdeadband setting and the range and resolution of the deadband setting. Thedeadband is the setting used to determine whether a change event should begenerated for each point. The change events can be read via object 32 or object 60and will be generated for any point whose value has changed by more than thedeadband setting since the last time the data value was reported.



Any analogue measurement that is unavailable at the time it is read will be reportedas offline, e.g. the frequency when the current and voltage frequency is outside thetracking range of the relay or the thermal state when the thermal protection isdisabled in the configuration column. Note that all object 30 points are reported assecondary values in DNP3 (with respect to CT and VT ratios).

5.7 DNP3 configuration using MiCOM S1

A PC support package for DNP3 is available as part of the Settings and Recordsmodule of MiCOM S1. The S1 module allows configuration of the relay’s DNP3response. The PC is connected to the relay via a serial cable to the 9-pin front part ofthe relay – see Introduction (P34x/EN IT). The configuration data is uploaded fromthe relay to the PC in a block of compressed format data and downloaded to therelay in a similar manner after modification. The new DNP3 configuration takeseffect in the relay after the download is complete. The default configuration can berestored at any time by choosing ‘All Settings’ from the ‘Restore Defaults’ cell in themenu ‘Configuration’ column. In S1, the DNP3 data is displayed on a three tabbedscreen, one screen each for object1, 20 and 30. Object 10 is not configurable.

5.7.1 Object 1

For every point included in the device profile document there is a check box formembership of class 0 and radio buttons for class 1, 2 or 3 membership. Any pointthat is in class 0 must be a member of one of the change event classes 1, 2 or 3.

Points that are configured out of class 0 are by default not capable of generatingchange events. Furthermore, points that are not part of class 0 are effectivelyremoved from the DNP3 response by renumbering the points that are in class 0 intoa contiguous list starting at point number 0. The renumbered point numbers areshown at the left hand side of the screen in S1 and can be printed out to form arevised device profile for the relay. This mechanism allows best use of availablebandwidth by only reporting the data points required by the user when a poll for allpoints is made.

5.7.2 Object 20

The running counter value of object 20 points can be configured to be in or out ofclass 0. Any running counter that is in class 0 can have its frozen value selected to bein or out of the DNP3 response, but a frozen counter cannot be included without thecorresponding running counter. As with object 1, the class 0 response will berenumbered into a contiguous list of points based on the selection of runningcounters. The frozen counters will also be renumbered based on the selection; notethat if some of the counters that are selected as running are not also selected asfrozen then the renumbering will result in the frozen counters having different pointnumbers to their running counterparts. For example, object 20 point 3 (runningcounter) might have its frozen value reported as object 21 point 1.

5.7.3 Object 30

For the analogue inputs, object 30, the same selection options for classes 0, 1, 2 and3 are available as for object 1. In addition to these options, which behave in exactlythe same way as for object 1, it is possible to change the deadband setting for eachpoint. The minimum and maximum values and the resolution of the deadbandsettings are defined in the device profile document; MiCOM S1 will allow thedeadband to be set to any value within these constraints.



6 SECOND REAR COMMUNICATIONS PORT (COURIER)

Relays with Courier, MODBUS, IEC60870-5-103 or DNP3 protocol on the first rearcommunications port have the option of a second rear port, running the Courierlanguage. The second port is designed typically for dial-up modem access byprotection engineers/operators, when the main port is reserved for SCADAcommunication traffic. Communication is via one of three physical links: K-Bus,EIA(RS)485 or EIA(RS)2321. The port supports full local or remote protection andcontrol access by MiCOM S1 software.

When changing the port configuration between K-Bus, EIA(RS)485 &EIA(RS)232 it is necessary to reboot the relay to update the hardwareconfiguration of the second rear port.

There is also provision for the EIA(RS)485 & EIA(RS)232 protocols to be configured tooperate with a modem, using an IEC60870 10 bit frame.

Port Configuration Valid Communication Protocol

K-Bus K-Bus

EIA(RS)232IEC60870 FT1.2, 11bit frame


EIA(RS)485IEC60870 FT1.2, 11bit frame


If both rear communications ports are connected to the same bus, care should betaken to ensure their address settings are not the same, to avoid message conflicts.

6.1 Courier protocol

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

The second rear communications port is functionally the same as detailed in section 2for a Courier rear communications port, with the following exceptions:


Automatic event extraction is not supported when the first rear port protocol isCourier, MODBUS or CS103. It is supported when the first rear port protocol isDNP3.


Automatic disturbance record extraction is not supported when the first rear portprotocol is Courier, MODBUS or CS103. It is supported when the first rear portprotocol is DNP3.



6.4 Connection to the second rear port

The second rear Courier port connects via the 9-way female D-type connector (SK4)in the middle of the card end plate (in between IRIG-B connector and lower D-type).The connection is compliant to EIA(RS)574.

For IEC60870-5-2 over EIA(RS)232

Pin Connection

1 No Connection

2 RxD

3 TxD

4 DTR#

5 Ground

6 No Connection

7 RTS#

8 CTS#

9 No Connection

For K-bus or IEC60870-5-2 over EIA(RS)485

Pin* Connection

4 EIA(RS)485 – 1 (+ ve)

7 EIA(RS)485 – 2 (- ve)

* - All other pins unconnected.

# - These pins are control lines for use with a modem.

NOTES:

1. Connector pins 4 and 7 are used by both the EIA(RS)232and EIA(RS)485physical layers, but for different purposes. Therefore, the cables should beremoved during configuration switches.

2. For the EIA(RS)485 protocol an EIA(RS)485 to EIA(RS)232 converter will berequired to connect a modem or PC running MiCOM S1, to the relay. AnAREVA T&D CK222 is recommended.

3. EIA(RS)485 is polarity sensitive, with pin 4 positive (+) and pin 7 negative (-).

4. The K-Bus protocol can be connected to a PC via a KITZ101 or 102.

7 SK5 PORT CONNECTION

The lower 9-way D-type connector (SK5) is currently unsupported. Do not connect tothis port.




MiCOM P342, P343

RELAY MENU DATABASE

P34x/EN GC/F33 Relay Menu Database

MiCOM P342, P343

MiCOM P342, P343 Guides

Generator Protection Relays

Relay Menu Database

This version of the Relay Menu Database is specific to the followingmodels

Model Number Software Number

P342------0070C P342------0070-A/B/C

P343------0070C P343------0070-A/B/C

For other models / software versions, please contact AREVA T&D for therelevant information.

(Software versions P342------0010*, P342------0020*, P342------0030*,P342------0040*, P342------0050*, P342------0060* andP343------0010*, P343------0020*, P343------0030*, P343------0040*,P343------0050*, P343------0060* are not supported by this menudatabase, see TG8614A (0010), TG8614B (0020 – 0040),P34x/EN T/C11 (0050) and P34x/EN T/D22 (0060) for information onthe menu database for these software versions).



RELAY MENU DATABASE

This Relay Menu Database 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

• IEC60870-5-103 Interoperability Guide

• Internal Digital Signals

• DNP3.0 Device Profile Document

• 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 are alsodefined within this database.

Note: The following labels are used within the database

Label Description Value

V1 Main VT Rating 1 (120/110V) 4 (380/480V)

V2 Checksynch VT Rating 1 (100/110V) 4 (380/480V)

V3 NVD VT Rating 1 (100/110V) 4 (380/480V)

Ι1 Phase CT Rating 1 or 5 (Setting 0A08)

Ι2 Earth Fault CT Rating 1 or 5 (Setting 0A0A)

Ι3 Sensitive CT Rating 1 or 5 (Setting 0A0C)

Ι4 Mutual CT Rating 1 or 5 (Setting 0A0E)

Menu datatype definition

This table defines the datatypes used for MODBUS (the datatypes for the Courier anduser interface are defined within the Menu Database itself using the standard CourierDatatypes). This section also defines the indexed string setting options for allinterfaces. The datatypes defined within this section are cross-referenced to from themenu database using a G number.

Event data

This section specifies all the event information that can be produced by the relay. Itdetails exactly how each event will be presented via the Courier, User and MODBUSinterfaces.

IEC60870-5-103 interoperability guide

This table fully defines the operation of the IEC60870-5-103 (VDEW) interface for therelay it should be read in conjunction with the relevant section of the Communicationssection of this Manual (P34x/EN CT/E33).



Internal digital signals

This table defines all of the relay internal digital signals (opto inputs, output contactsand protection inputs and outputs). A relay may have up to 1023 internal signalseach referenced by a numeric index as shown in this table. This numeric index isused to select a signal for the commissioning monitor port. It is also used to explicitlydefine protection events produced by the relay (see the Event Data section).

DNP3.0 device profile document

This table defines all of the objects, functions and/or qualifiers supported.

Default programmable logic

This section documents the default programmable logic for the various models of therelay. This default logic for each model of the relay is supplied with the MiCOM S1Scheme Logic Editor PC support software.

References

Introduction (P34x/EN IT/E33) : User Interface operation and connections to the relay

Communications (P34x/EN CT/E33) : Overview of communication interfaces

Courier User Guide R6512

Modicon MODBUS Protocol Reference Guide PI-MBUS-300 Rev E

IEC60870-5-103 Telecontrol Equipment and Systems – Transmission Protocols –Companion Standard for the informative interface of Protection Equipment

Relay Menu Database

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Page 3/170

Col Row Start End P341 P342 P343SYSTEM DATA 00 00 * * *

Language 01 Indexed String G19 G19 English Setting 0 3 1 2 * * *

Password 02 ASCII Password(4 chars) G20 40001 40002 G20 AAAA Setting 65 90 1 0 * * *

Binary Flag (8 bits)

Indexed Strings

ASCII Text(16 chars)

Plant Reference 05 ASCII Text(16 chars) G3 40012 40019 G3 ALSTOM Setting 32 163 1 2 * * *

Model Number 06 ASCII Text(32 chars) G3 30020 30035 G3 Model Number Data * * *

Serial Number 08 ASCII Text(7 chars) G3 30044 30051 G3 Serial Number Data * * *

Frequency 09 Unsigned Integer(8 bits) 40020 G1 50 Setting 50 60 10 2 * * *

Comms Level 0A Unsigned Integer(16 bits) 2 Data * * *

Needs to be address of interface

Rear Courier Address available via LCD

Plant Status 0C Binary Flag(16 bits) G4 30002 G4 Data * * *

Control Status 0D Binary Flag(16 bits) G5 30004 G5 Data * * *

Active Group 0E Unsigned Integer(16 bits) 30006 G1 Data * * *

UNUSED 0F

CB Trip/Close 10 Indexed String(2) G55 No Operation Command 0 2 1 1 * Visible to LCD+Front Port

CB Trip/Close N/A 10 Indexed String(2) G55 40021 G55 No Operation Command 0 2 1 1 * Visible to Rear Port

Software Ref. 1 11 ASCII Text(16 chars) 30052 30059 G3 Data * * *Binary FlagIndexed StringBinary FlagIndexed StringBinary FlagIndexed String

UNUSED 23

Binary Flag

Indexed String

Binary Flag

Indexed String

Binary Flag

Indexed String

Binary Flag

Indexed String

Binary Flag(32 bits)

Indexed String

Access Level D0 Unsigned Integer(16 bits) 30010 G1 Data * * *

Password Control D1 Unsigned Integer(16 bits) G22 40022 G22 2 Setting 0 2 1 2 * * *

Password Level 1 D2 ASCII Password(4 chars) G20 40023 40024 G20 AAAA Setting 65 90 1 1 * * *

Password Level 2 D3 ASCII Password(4 chars) G20 40025 40026 G20 AAAA Setting 65 90 1 2 * * *

VIEW RECORDS 01 00 * * *

Menu Text UI Data Type StringsCourier

CommentModbus Datagroup Default Setting Cell Type Min

Modbus Address ModelMax Step Password

Level

G3 40004 40011 G3Description 04 MiCOM P34* 163 1 2Setting 32 * * ** = 1 for Model 1, 2 for Model 2, 3 for Model 3

Sys Fn Links 03 G95 40003 G95 Setting 1 1 *

* * *

1 2 * *

52 G228 30015 30016

Relay Address

Alarm Status 3

Opto I/P Status

Relay O/P Status

*

The original register 30007 is available for opto inputs #1 to #16

The original register 30007 is available

0B

*

*

30001

255 Setting 0 255 1 1 *

20 G8 30725 30726 *

30008

G8 Data

21 G9 30009 G9 Data * * *

Alarm Status 1 22 G96 30011 30012 G96 Data * * *

Opto I/P Status 30 G8 30725 30726 G8 Data

40 30008 30009

30012

Data

Alarm Status 1 50

Relay O/P Status G9G9

Alarm Status 2 51 G128 30013 30014

G96 30011 G96 Data

G128 Data

Data

*

*

*

* * *

* *

* *

* *

G228

Unsigned Integer(16 bits)

Binary Flag(16 bits)Relay status (repeat of Courier Status byte without the busy flag)

* *G26 Data *

*

Relay Menu Database

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Col Row Start End P341 P342 P343Menu Text UI Data Type Strings

CourierCommentModbus

Datagroup Default Setting Cell Type MinModbus Address Model

Max Step Password Level

30100 G1 No of event records stored

30101 G1 Number of Fault records stored

30102 G1

Select Event 01 Unsigned Integer(16 bits) 40100 0 Setting 0 249 1 0 Max value is oldest record

Menu Cell Ref N/A 02 Cell Reference 30107 G13 (From Record) Data * * * Indicates type of event. See Event sheet.

Time & Date 03 IEC870 Time & Date 30103 30106 G12 (From Record) Data * * *

Event Text 04 Ascii String (32 chars) Data * * * See Event sheet

Select Fault 06 Unsigned Integer (16 bits) 40101 Setting 0 4 1 2 * * * Allows Fault Record to be selected

0 means that there is no additional data

1 means that fault record data is available

2 means that maintenance data is available

Started Phase N/A Data * * *

A B C N A/B/C/N Visible if Start A/B/C/N

Tripped Phase N/A Data * * *

A B C N A/B/C/N Visible if Trip A/B/C/N

Gen Differential N/A Data *

Trip

Power N/A Data * * *

Start 1 2 1/2 visible if Start 1/2

Power N/A Data * * *

Trip 1 2 1/2 visible if Trip 1/2

Field Failure N/A Data * *

Alarm




Trip 1 2 1/2 visible if Trip 1/2

NPS Thermal N/A Data * *

Alarm Trip

Volt Dep O/C N/A Data * *

Start Trip

Underimedance N/A Data * *

Start Z< 12 1/2 visible if Start Z< 1/2

Underimedance N/A Data * *

Trip Z< 12 1/2 visible if Trip Z< 1/2

Data

Data

*

G27 **3010930108Unsigned Int / Binary Flag (32 bits)Note DTL depends on event type binary flag for Contact, Opto, alarm & Protection. See Event sheet of Spreadsheet.

*05Event Value

* *G130110

Modbus address where change occurred. Alarm 30011; Relay 30723; Opto 30725 Protection 30727-30754. For platform events, fault events and maintenance events the default is 0.

30111 G1 Data *This register will contain the DDB ordinal for protection events or the bit number for alarm events.

* *

Data ***G130112

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Overcurrent N/A Data * * *

Start I> 1234 1/2/3/4 Visible if Start I>1/2/3/4

Overcurrent N/A Data * * *

Trip I> 1234 1/2/3/4 Visible if Trip I>1/2/3/4

Earth Fault N/A Data * * *

Start IN> 1234 1/2/3/4 visible if Start IN>1/2/3/4

Earth Fault N/A Data * * *

Trip IN> 1234 1/2/3/4 visible if Trip IN>1/2/3/4

Sensitive E/F N/A Data * * *

Start ISEF> 1234 1/2/3/4 visible if Start ISEF>1/2/3/4

Sensitive E/F N/A Data * * *

Trip ISEF> 1234 1/2/3/4 visible if Trip ISEF>1/2/3/4

Restricted E/F N/A Data * * *

Trip IREF>

Sensitive Power N/A Data * * *


Sensitive Power N/A Data * * *

Trip 1 2 1/2 visible if trip 1/2

Residual O/V NVD N/A Data * * *

Start VN> 1 2 1/2 visible if Start VN>1/2

Residual O/V NVD N/A Data * * *

Trip VN> 1 2 1/2 visible if Trip VN>1/2

100% Stator EF N/A Data *

Start Trip

V/Hz N/A Data * *

Alarm Start Trip

df/dt N/A Data *

Start Trip

V Vector Shift N/A Data *

Trip

Dead Machine N/A Data *

Trip

U/Voltage start N/A Data * * * Ph-Ph or Ph-N

V< 1 2 AB BC CA 1/2 visible if Start V<1/2

U/Voltage Trip N/A Data * * * Ph-Ph or Ph-N

V< 1 2 AB BC CA 1/2 visible if Trip V<1/2

O/Voltage Start N/A Data * * * Ph-Ph or Ph-N

V> 1 2 AB BC CA 1/2 visible if Start V>1/2

O/Voltage Trip N/A Data * * * Ph-Ph or Ph-N

V> 1 2 AB BC CA 1/2 visible if Trip V>1/2

Underfrequency N/A Data * * *

Start F< 1234 1/2/3/4 visible if Start F<1/2/3/4

Underfrequency N/A Data * * *

Trip F< 1234 1/2/3/4 visible if Trip F<1/2/3/4

Overfrequency N/A Data * * *

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Start F> 1 2 1/2 visible if Start F>1/2

Overfrequency N/A Data * * *

Trip F> 1 2 1/2 visible if Trip F>1/2

RTD Alarm N/A Data * *

RTD 1


RTD 2


RTD 3


RTD 4


RTD 5


RTD 6


RTD 7


RTD 8


RTD 9


RTD 10

RTD Trip N/A Data * *

RTD 1


RTD 2


RTD 3


RTD 4


RTD 5


RTD 6


RTD 7


RTD 8


RTD 9


RTD 10

CL I/P Alm Start N/A Data * * *

CLIO Input 1 Courier text = CLIO Input label setting

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CL Input Alarm N/A Data * * *








CL I/P TripStart N/A Data * * *








CL Input Trip N/A Data * * *








Breaker Fail N/A Data * * *

CB Fail 1 2 1/2 visible if CB Fail 1/2

Supervision N/A Data * * *

VTS CTS VTS/CTS visible if AlarmVTS/CTS

PoleSlip z based N/A Data *

Start Z1 Z2

PoleSlip z based N/A Data *

Trip Z1 Z2

Thermal Overload N/A Data * *

Alarm Trip

Faulted Phase N/A 07 Binary Flag (8 Bits) G16 30113 G16 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected

Start Elements1 N/A 08 Binary Flag (32 Bits) G84 30114 30115 G84 Data * * *

Indexed String

For fault record use only. The Modbus register cannot be accessed unless a fault record is selected

Relay Menu Database

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Start Elements2 N/A 09 Binary Flag (32 Bits) G107 30116 30117 G107 Data * * *

Indexed String

Trip Elements1 N/A 0A Binary Flag (32 Bits) G85 30118 30119 G85 Data * * *

Indexed String

Trip Elements2 N/A 0B Binary Flag (32 Bits) G86 30120 30121 G86 Data * * *

Indexed String

Fault Alarms N/A 0C Binary Flag (32 Bits) G87 30122 30123 G87 Data * * *

Indexed String

IA 13 Courier Number (current) 30135 30136 G24 Data * *

IA-1 *

IB 14 Courier Number (current) 30137 30138 G24 Data * *

IB-1 *

IC 15 Courier Number (current) 30139 30140 G24 Data * *

IC-1 *

* *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected

*G24 DataCourier Number (voltage) 30149 30150VBN 1A

* * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected

30148 G24 Data


VAN 19 Courier Number (voltage) 30147

*G24 DataCourier Number (voltage) 30145 30146VCA 18


30144 G24 Data


VBC 17 Courier Number (voltage) 30143

*G24 DataCourier Number (voltage) 30141 30142VAB 16



**

For fault record use only. The Modbus register cannot be accessed unless a fault record is selectedFor fault record use only. The Modbus register cannot be accessed unless a fault record is selected



*

For fault record use only. The Modbus register cannot be accessed unless a fault record is selectedFor fault record use only. The Modbus register cannot be accessed unless a fault record is selectedFor fault record use only. The Modbus register cannot be accessed unless a fault record is selectedFor fault record use only. The Modbus register cannot be accessed unless a fault record is selected

* *

* *

For fault record use only. The Modbus register cannot be accessed unless a fault record is selectedFor fault record use only. The Modbus register cannot be accessed unless a fault record is selectedFor fault record use only. The Modbus register cannot be accessed unless a fault record is selected

Fault Time 0D IEC870 Time & Date 30124 30127 G12 (From Record) Data

G1

* * *

Active Group 0E Unsigned Integer 30128 Data * * *

System Frequency 0F Courier Number (frequency) 30129 G30 Data *

Fault Duration 10 Courier Number (time) 30130 30131 G24 Data *

CB Operate Time 11 Courier Number (time) 30132 G25 Data

Relay Trip Time 12 Courier Number (time) 30133 30134 G24 Data *

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IA-2 1C Courier Number (current) 30153 30154 G24 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IB-2 1D Courier Number (current) 30155 30156 G24 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IC-2 1E Courier Number (current) 30157 30158 G24 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IA Differential 1F Courier Number (current) 30159 30160 G24 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IB Differential 20 Courier Number (current) 30161 30162 G24 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IC Differential 21 Courier Number (current) 30163 30164 G24 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

VN Measured 22 Courier Number (voltage) 30165 30166 G24 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

VN Derived 23 Courier Number (voltage) 30167 30168 G24 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IN Measured 24 Courier Number (current) 30169 30170 G24 Data * *

IN Derived *

I Sensitive 25 Courier Number (current) 30171 30172 G24 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IREF Diff 26 Courier Number (current) 30173 30174 G24 Data * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

IREF Bias 27 Courier Number (current) 30175 30176 G24 Data * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

I2 28 Courier Number (current) 30177 30178 G24 Data * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

3 Phase Watts 29 Courier Number (Power) 30179 30180 G125 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

3 Phase VArs 2A Courier Number (VAr) 30181 30182 G125 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

3Ph Power Factor 2B Courier Number (Decimal) 30183 G30 Data * * *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

RTD 1 2C Courier Number (Temperature) 30184 G10 Data * *Courier text = RTD Label setting for fault record use only


30152 G24 DataVCN 1B Courier Number (voltage) 30151

For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

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RTD 2 2D Courier Number (Temperature) 30185 G10 Data * *Courier text = RTD Label setting for fault record use only

RTD 3 2E Courier Number (Temperature) 30186 G10 Data * *Courier text = RTD Label setting for fault record use only

RTD 4 2F Courier Number (Temperature) 30187 G10 Data * *Courier text = RTD Label setting for fault record use only

RTD 5 30 Courier Number (Temperature) 30188 G10 Data * *Courier text = RTD Label setting for fault record use only






df/dt 36 Courier Number (Hz/s) 30194 G25 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

V Vector Shift 37 Courier Number (Angle) 30195 G30 Data *For fault record use only. The Modbus register cannot be accessed unless a fault record is selected.

CLIO Input 1 38 Courier Number (Decimal) 30196 G125 Data * * *Courier text = CLIO Input label setting for fault record use only

CLIO Input 2 39 Courier Number (Decimal) 30197 G125 Data * * *Courier text = CLIO Input label setting for fault record use only

CLIO Input 3 3A Courier Number (Decimal) 30198 G125 Data * * *Courier text = CLIO Input label setting for fault record use only

CLIO Input 4 3B Courier Number (Decimal) 30199 G125 Data * * *Courier text = CLIO Input label setting for fault record use only

Select Maint F0 Unsigned Integer (16 bits) 40102 G1Manual override to select a fault record

Setting 0 4 1 0 * * * Allows Self Test Report to be selected

Maint Text F1 Ascii Text (32 chars) Data * * *

Maint Type F2 Unsigned integer (32 bits) 30036 30037 G27 Data * * *

Maint Data F3 Unsigned integer (32 bits) 30038 30039 G27 Data * * *

Reset Indication FF Indexed String G11 No Command 0 1 1 1 * * *

MEASUREMENTS 1 02 00 * * *

IA Magnitude 01 Courier Number (current) 30200 30201 G24 Data * *

IA-1 Magnitude 01 Courier Number (current) 30200 30201 G24 Data *

IA Phase Angle 02 Courier Number (angle) 30202 G30 Data * *

IA-1 Phase Angle 02 Courier Number (angle) 30202 G30 Data *

IB Magnitude 03 Courier Number (current) 30203 30204 G24 Data * *

IB-1 Magnitude 03 Courier Number (current) 30203 30204 G24 Data *

IB Phase Angle 04 Courier Number (angle) 30205 G30 Data * *

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IB-1 Phase Angle 04 Courier Number (angle) 30205 G30 Data *

IC Magnitude 05 Courier Number (current) 30206 30207 G24 Data * *

IC-1 Magnitude 05 Courier Number (current) 30206 30207 G24 Data *

IC Phase Angle 06 Courier Number (angle) 30208 G30 Data * *

IC-1 Phase Angle 06 Courier Number (angle) 30208 G30 Data *

IN Measured Mag 07 Courier Number (current) 30209 30210 G24 Data * *

IN Measured Ang 08 Courier Number (angle) 30211 G30 Data * *

IN Derived Mag 09 Courier Number (current) 30212 30213 G24 Data *

IN Derived Angle 0A Courier Number (angle) 30214 G30 Data *

I Sen Magnitude 0B Courier Number (current) 30215 30216 G24 Data * * *

I Sen Angle 0C Courier Number (degrees) 30217 G30 Data * * *

I1 Magnitude 0D Courier Number (current) 30218 30219 G24 Data * * *

I2 Magnitude 0E Courier Number (current) 30220 30221 G24 Data * * *

I0 Magnitude 0F Courier Number (current) 30222 30223 G24 Data * * *

IA RMS 10 Courier Number (current) 30224 30225 G24 Data * * *

IB RMS 11 Courier Number (current) 30226 30227 G24 Data * * *

IC RMS 12 Courier Number (current) 30228 30229 G24 Data * * *

VAB Magnitude 14 Courier Number (voltage) 30230 30231 G24 Data * * *

VAB Phase Angle 15 Courier Number (angle) 30232 G30 Data * * *

VBC Magnitude 16 Courier Number (voltage) 30233 30234 G24 Data * * *

VBC Phase Angle 17 Courier Number (angle) 30235 G30 Data * * *

VCA Magnitude 18 Courier Number (voltage) 30236 30237 G24 Data * * *

VCA Phase Angle 19 Courier Number (angle) 30238 G30 Data * * *

VAN Magnitude 1A Courier Number (voltage) 30239 30240 G24 Data * * *

VAN Phase Angle 1B Courier Number (angle) 30241 G30 Data * * *

VBN Magnitude 1C Courier Number (voltage) 30242 30243 G24 Data * * *

VBN Phase Angle 1D Courier Number (angle) 30244 G30 Data * * *

VCN Magnitude 1E Courier Number (voltage) 30245 30246 G24 Data * * *

VCN Phase Angle 1F Courier Number (angle) 30247 G30 Data * * *

VN Measured Mag 20 Courier Number (voltage) 30248 30249 G24 Data * * *

VN Measured Ang 21 Courier Number (angle) 30250 G30 Data * * *

VN Derived Mag 22 Courier Number (voltage) 30251 30252 G24 Data * * *

VN Derived Ang 23 Courier Number (angle) 30252 G30 Data * * *

V1 Magnitude 24 Courier Number (voltage) 30253 30254 G24 Data * * *



VAN RMS 27 Courier Number (voltage) 30259 30260 G24 Data * * *

VBN RMS 28 Courier Number (voltage) 30261 30262 G24 Data * * *

VCN RMS 29 Courier Number (voltage) 30263 30264 G24 Data * * *

Frequency 2D Courier Number (frequency) 30265 G30 Data * * *

VBC Phase Angle 17 Courier Number (angle) 30235 G30 Data * * *

VCA Magnitude 18 Courier Number (voltage) 30236 30237 G24 Data * * *

VCA Phase Angle 19 Courier Number (angle) 30238 G30 Data * * *

VAN Magnitude 1A Courier Number (voltage) 30239 30240 G24 Data * * *

VAN Phase Angle 1B Courier Number (angle) 30241 G30 Data * * *

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VBN Magnitude 1C Courier Number (voltage) 30242 30243 G24 Data * * *

VBN Phase Angle 1D Courier Number (angle) 30244 G30 Data * * *

VCN Magnitude 1E Courier Number (voltage) 30245 30246 G24 Data * * *

VCN Phase Angle 1F Courier Number (angle) 30247 G30 Data * * *

VN Measured Mag 20 Courier Number (voltage) 30248 30249 G24 Data * * *

VN Measured Ang 21 Courier Number (angle) 30250 G30 Data * * *

VN Derived Mag 22 Courier Number (voltage) 30251 30252 G24 Data * * *

VN Derived Ang 23 Courier Number (angle) 30252 G30 Data * * *




VAN RMS 27 Courier Number (voltage) 30259 30260 G24 Data * * *

VBN RMS 28 Courier Number (voltage) 30261 30262 G24 Data * * *

VCN RMS 29 Courier Number (voltage) 30263 30264 G24 Data * * *

Frequency 2D Courier Number (frequency) 30265 G30 Data * * *

I1 Magnitude 40 Courier Number (current) 30218 30219 G24 Data * * *

I1 Phase Angle 41 Courier Number (angle) 30266 G30 Data * * *






V1 Phase Angle 47 Courier Number (angle) 30269 G30 Data * * *


V2 Phase Angle 49 Courier Number (angle) 30270 G30 Data * * *

V0 Magnitude 4A Courier Number (voltage) 30257 30258 G24 Data * * *

V0 Phase Angle 4B Courier Number (angle) 30271 G30 Data * * *

MEASUREMENTS 2 03 00 * * *

A Phase Watts 01 Courier Number (Power) 30300 30302 G29 Data * * *Alternative Modbus register pairs 30391& 30392 available with improved G125 floating point data type

B Phase Watts 02 Courier Number (Power) 30303 30305 G29 Data * * *Alternative Modbus register pairs 30393 & 30394 available with improved G125 floating point data type

C Phase Watts 03 Courier Number (Power) 30306 30308 G29 Data * * *Alternative Modbus register pairs 30395 & 30396 available with improved G125 floating point data type

A Phase VArs 04 Courier Number (VAr) 30309 30311 G29 Data * * *Alternative Modbus register pairs 30397 & 30398 available with improved G125 floating point data type

B Phase VArs 05 Courier Number (VAr) 30312 30314 G29 Data * * *Alternative Modbus register pairs 30399 & 30400 available with improved G125 floating point data type

C Phase VArs 06 Courier Number (VAr) 30315 30317 G29 Data * * *Alternative Modbus register pairs 30401 & 30402 available with improved G125 floating point data type

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A Phase VA 07 Courier Number (VA) 30318 30320 G29 Data * * *Alternative Modbus register pairs 30403 & 30404 available with improved G125 floating point data type

B Phase VA 08 Courier Number (VA) 30321 30323 G29 Data * * *Alternative Modbus register pairs 30405 & 30406 available with improved G125 floating point data type

C Phase VA 09 Courier Number (VA) 30324 30326 G29 Data * * *Alternative Modbus register pairs 30407 & 30408 available with improved G125 floating point data type

3 Phase Watts 0A Courier Number (Power) 30327 30329 G29 Data * * *Alternative Modbus register pairs 30409 & 30410 available with improved G125 floating point data type

3 Phase VArs 0B Courier Number (VAr) 30330 30332 G29 Data * * *Alternative Modbus register pairs 30411 & 30412 available with improved G125 floating point data type

3 Phase VA 0C Courier Number (VA) 30333 30335 G29 Data * * *Alternative Modbus register pairs 30413 & 30414 available with improved G125 floating point data type

3Ph Power Factor 0E Courier Number (decimal) 30339 G30 Data * * *

APh Power Factor 0F Courier Number (decimal) 30340 G30 Data * * *

BPh Power Factor 10 Courier Number (decimal) 30341 G30 Data * * *

CPh Power Factor 11 Courier Number (decimal) 30342 G30 Data * * *

3Ph WHours Fwd 12 Courier Number (Wh) 30343 30345 G29 Data * * *Alternative Modbus register pairs 30415 & 30416 available with improved G125 floating point data type

3Ph WHours Rev 13 Courier Number (Wh) 30346 30348 G29 Data * * *Alternative Modbus register pairs 30417 & 30418 available with improved G125 floating point data type

3Ph VArHours Fwd 14 Courier Number (VArh) 30349 30351 G29 Data * * *Alternative Modbus register pairs 30419 & 30420 available with improved G125 floating point data type

3Ph VArHours Rev 15 Courier Number (VArh) 30352 30354 G29 Data * * *Alternative Modbus register pairs 30421 & 30422 available with improved G125 floating point data type

3Ph W Fix Demand 16 Courier Number (Power) 30355 30357 G29 Data * * *Alternative Modbus register pairs 30423 & 30424 available with improved G125 floating point data type

3Ph VArs Fix Dem 17 Courier Number (Vars) 30358 30360 G29 Data * * *Alternative Modbus register pairs 30425 & 30426 available with improved G125 floating point data type

IA Fixed Demand 18 Courier Number (Current) 30361 30362 G24 Data * * *

IB Fixed Demand 19 Courier Number (Current) 30363 30364 G24 Data * * *

IC Fixed Demand 1A Courier Number (Current) 30365 30366 G24 Data * * *

3 Ph W Roll Dem 1B Courier Number (Power) 30367 30369 G29 Data * * *Alternative Modbus register pairs 30427 & 30428 available with improved G125 floating point data type

3Ph VArs RollDem 1C Courier Number (VAr) 30370 30372 G29 Data * * *Alternative Modbus register pairs 30429 & 30430 available with improved G125 floating point data type

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IA Roll Demand 1D Courier Number (Current) 30373 30374 G24 Data * * *

IB Roll Demand 1E Courier Number (Current) 30375 30376 G24 Data * * *

IC Roll Demand 1F Courier Number (Current) 30377 30378 G24 Data * * *

3Ph W Peak Dem 20 Courier Number (Power) 30379 30381 G29 Data * * *Alternative Modbus register pairs 30431 & 30432 available with improved G125 floating point data type

3Ph VAr Peak Dem 21 Courier Number (VAr) 30382 30384 G29 Data * * *Alternative Modbus register pairs 30433 & 30434 available with improved G125 floating point data type

IA Peak Demand 22 Courier Number (Current) 30385 30386 G24 Data * * *

IB Peak Demand 23 Courier Number (Current) 30387 30388 G24 Data * * *

IC Peak Demand 24 Courier Number (Current) 30389 30390 G24 Data * * *

Reset Demand 25 Indexed String G11 40103 G11 No Command 0 1 1 1 * * *

N/A 30391 30392 G125 Data * * * A Phase Watts (see [0301])

N/A 30393 30394 G125 Data * * * B Phase Watts (see [0302])

N/A 30395 30396 G125 Data * * * C Phase Watts (see [0303])

N/A 30397 30398 G125 Data * * * A Phase VArs (see [0304])

N/A 30399 30400 G125 Data * * * B Phase VArs (see [0305])

N/A 30401 30402 G125 Data * * * C Phase VArs (see [0306])

N/A 30403 30404 G125 Data * * * A Phase VA (see [0307])

N/A 30405 30406 G125 Data * * * B Phase VA (see [0308])

N/A 30407 30408 G125 Data * * * C Phase VA (see [0309])

N/A 30409 30410 G125 Data * * * 3 Phase Watts (see [030A])

N/A 30411 30412 G125 Data * * * 3 Phase VArs (see [030B])

N/A 30413 30414 G125 Data * * * 3 Phase VA (see [030C])

N/A 30415 30416 G125 Data * * * 3 Phase WHours Fwd (see [0312])

N/A 30417 30418 G125 Data * * * 3 Phase WHours Rev (see [0313])

N/A 30419 30420 G125 Data * * * 3 Phase VArHours Fwd (see [0314])

N/A 30421 30422 G125 Data * * * 3 Phase VArHours Rev (see [0315])

N/A 30423 30424 G125 Data * * * 3 Phase W Fix Demand (see [0316])

N/A 30425 30426 G125 Data * * * 3 Phase VArs Fix Demand (see [0317])

N/A 30427 30428 G125 Data * * * 3 Phase W Roll Demand (see [031B])

N/A 30429 30430 G125 Data * * * 3 Phase VArs Roll Demand (see [031C])

N/A 30431 30432 G125 Data * * * 3 Phase W Peak Demand (see [0320])

N/A 30433 30434 G125 Data * * * 3 Phase VArs Peak Demand (see [0321])

MEASUREMENTS 3 04 00 *

IA-2 Magnitude 01 Courier Number (Current) 30435 30436 G24 Data *

IA-2 Phase Angle 02 Courier Number (Angle) 30437 G30 Data *

IB-2 Magnitude 03 Courier Number (Current) 30438 30439 G24 Data *

IB-2 Phase Angle 04 Courier Number (Angle) 30440 G30 Data *

IC-2 Magnitude 05 Courier Number (Current) 30441 30442 G24 Data *

IC-2 Phase Angle 06 Courier Number (Angle) 30443 G30 Data *

IA Differential 07 Courier Number (Current) 30444 30445 G24 Data *

IB Differential 08 Courier Number (Current) 30446 30447 G24 Data *

Recommended Modbus register pairs for power and energy measurements using G125 floating point data type. See Scada Communications section (P34x/EN CT) of the Technical Guide

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IC Differential 09 Courier Number (Current) 30448 30449 G24 Data *

IA Bias 0A Courier Number (Current) 30450 30451 G24 Data *

IB Bias 0B Courier Number (Current) 30452 30453 G24 Data *

IC Bias 0C Courier Number (Current) 30454 30455 G24 Data *

IREF Diff 0D Courier Number (Current) 30456 30457 G24 Data * *

IREF Bias 0E Courier Number (Current) 30458 30459 G24 Data * *

VN 3rd Harmonic 0F Courier Number (Voltage) 30460 30461 G24 Data *

NPS Thermal 10 Courier Number (Percentage) 30462 G1 Data * *

Reset NPSThermal 11 Indexed String G11 40104 G11 No Command 0 1 1 1 * *

RTD 1 12 Courier Number (Temperature) 30463 G10 Data * * Courier text = RTD label setting








RTD 9 1A Courier Number (Temperature) 30471 G10 Data * * Courier text = RTD label setting

RTD 10 1B Courier Number (Temperature) 30472 G10 Data * * Courier text = RTD label settingBinary Flag (10 bits)Indexed StringBinary Flag (10 bits)Indexed StringBinary Flag (10 bits)Indexed String

Reset RTD Flags 1F Indexed string G11 40105 G11 No Command 0 1 1 1 * *

APh Sen Watts 20 Courier Number (Power) 30476 30477 G125 Data * * *

APh Sen Vars 21 Courier Number (Var) 30478 30479 G125 Data * * *

APh Power Angle 22 Courier Number (angle) 30480 G30 Data * * *

Thermal Overload 23 Courier Number (Percentage) 30481 G1 Data * * *

Reset ThermalO/L 24 Indexed String G11 40106 G11 No Command 0 1 1 1 * * *

CLIO Input 1 25 Courier Number (Decimal) 30482 30483 G125 Data * * * Courier Text = CLIO label setting




CB CONDITION 06 00 * * * CB CONDITION MONITORING

CB Operations 01 Unsigned Integer 30600 G1 Data * * * Number of Circuit Breaker Operations

Total IA Broken 02 Courier Number (current) 30601 30602 G24 Data * * * Broken Current A Phase

Total IB Broken 03 Courier Number (current) 30603 30604 G24 Data * * * Broken Current B Phase

Total IC Broken 04 Courier Number (current) 30605 30606 G24 Data * * * Broken Current C Phase

CB Operate Time 05 Courier Number (time) 30607 G25 Data * * * Circuit Breaker operating time

Reset CB Data 06 Indexed String G11 40150 G11 No Command 0 1 1 1 * * * Reset All Values

CB CONTROL 07 00 * * *

CB Control by 01 Indexed String G99 40200 G99 Disabled Setting 0 7 1 2 *

Close Pulse Time 02 Courier Number (Time) 40201 G2 0.5 Setting 0.1 10 0.01 2 *

*Data *

*

RTD Data Error 1E G110 30475 G110

*Data

*

RTD Short Cct 1D G109 30474 G109

*DataRTD Open Cct 1C G108 30473 G108

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Trip Pulse Time 03 Courier Number (Time) 40202 G2 0.5 Setting 0.1 5 0.01 2 *

Man Close Delay 05 Courier Number (Time) 40203 G2 10 Setting 0.01 600 0.01 2 * Manual Close Delay

CB Healthy Time 06 Courier Number (Time) 40204 40205 G35 5 Setting 0.01 9999 0.01 2 *

Lockout Reset 08 Indexed String G11 40206 G11 No Command 0 1 1 2 * * *

Reset Lockout by 09 Indexed String G81 40207 G81 CB Close Setting 0 1 1 2 * * *

Man Close RstDly 0A Courier Number (Time) 40208 G2 5 Setting 0.01 600 0.01 2 * * * Manual Close Reset Delay

CB Status Input 11 Indexed String G118 40209 G118 None Setting 0 3 1 2 * * *

DATE AND TIME 08 00 * * *

Date/Time N/A 01 IEC870 Time & Date 40300 40303 G12 Setting 0 * * *

Date N/A * * * Front Panel Menu only

12-Jan-98

Time N/A * * * Front Panel Menu only

12:00

IRIG-B Sync 04 Indexed String G37 40304 G37 Disabled Setting 0 1 1 2 * * *

IRIG-B Status 05 Indexed String G17 30090 G17 Data * * *

Battery Status 06 Indexed String G59 30091 G59 Data * * *

Battery Alarm 07 Indexed String G37 40305 G37 Enabled Setting 0 1 1 2 * * *

CONFIGURATION 09 00 * * *

Restore Defaults 01 Indexed String G53 40402 G53 No Operation Command 0 5 1 2 * * *

Setting Group 02 Indexed String G61 40403 G61 Menu Setting 0 1 1 2 * * *

Active Settings 03 Indexed String G90 40404 G90 1 Setting 0 3 1 1 * * *

Save Changes 04 Indexed String G62 40405 G62 No Operation Command 0 2 1 2 * * *

Copy From 05 Indexed String G90 40406 G90 Group 1 Setting 0 3 1 2 * * *

Copy To 06 Indexed String G98 40407 G98 No Operation Command 0 3 1 2 * * *

Setting Group 1 07 Indexed String G37 40408 G37 Enabled Setting 0 1 1 2 * * *

Setting Group 2 08 Indexed String G37 40409 G37 Disabled Setting 0 1 1 2 * * *

Setting Group 3 09 Indexed String G37 40410 G37 Disbaled Setting 0 1 1 2 * * *

Setting Group 4 0A Indexed String G37 40411 G37 Disabled Setting 0 1 1 2 * * *

Gen Differential 0B Indexed String G37 40412 G37 Enabled Setting 0 1 1 2 *

Power 0C Indexed String G37 40413 G37 Enabled Setting 0 1 1 2 * * *

Field Failure 0D Indexed String G37 40414 G37 Enabled Setting 0 1 1 2 * *

NPS Thermal 0E Indexed String G37 40415 G37 Enabled Setting 0 1 1 2 * *

System Backup 0F Indexed String G37 40416 G37 Enabled Setting 0 1 1 2 * *

Overcurrent 10 Indexed String G37 40417 G37 Enabled Setting 0 1 1 2 * * *

Thermal Overload 11 Indexed String G37 40433 G37 Disabled Setting 0 1 1 2 * * *

NOT USED 12

Earth Fault 13 Indexed String G37 40418 G37 Enabled Setting 0 1 1 2 * * *

NOT USED 14

SEF/REF/SPower 15 Indexed String G114 40419 Disabled Setting 0 2 1 2 *

G114 SEF/REF * *

Residual O/V NVD 16 Indexed String G37 40420 G37 Enabled Setting 0 1 1 2 * * * Residual Overvoltage

100% Stator EF 17 Indexed String G37 40421 G37 Disabled Setting 0 1 1 2 *

V/Hz 18 Indexed String G37 40422 G37 Disabled Setting 0 1 1 2 * *

df/dt 19 Indexed String G37 40423 G37 Enabled Setting 0 1 1 2 *

V Vector Shift 1A Indexed String G37 40424 G37 Disabled Setting 0 1 1 2 *

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Dead Machine 1B Indexed String G37 40425 G37 Disabled Setting 0 1 1 2 *

Reconnect Delay 1C Indexed String G37 40426 G37 Disabled Setting 0 1 1 2 *

Volt Protection 1D Indexed String G37 40427 G37 Enabled Setting 0 1 1 2 * * *

Freq Protection 1E Indexed String G37 40428 G37 Enabled Setting 0 1 1 2 * * *

RTD Inputs 1F Indexed String G37 40429 G37 Enabled Setting 0 1 1 2 * *

CB Fail 20 Indexed String G37 40430 G37 Disabled Setting 0 1 1 2 * * *

Supervision 21 Indexed String G37 40431 G37 Disabled Setting 0 1 1 2 * * *

NOT USED 22 NOT USED

NOT USED 23

Pole Slipping 24 Indexed String G37 40436 G37 Enabled Setting 0 1 1 2 *

Input Labels 25 Indexed String G80 Visible Setting 0 1 1 1 * * *

Output Labels 26 Indexed String G80 Visible Setting 0 1 1 1 * * *

RTD Labels 27 Indexed String G80 Visible Setting 0 1 1 1 * *

CT & VT Ratios 28 Indexed String G80 Visible Setting 0 1 1 1 * * *

Record Control 29 Indexed String G80 Visible Setting 0 1 1 1 * * *

Disturb Recorder 2A Indexed String G80 Visible Setting 0 1 1 1 * * * Disturbance recorder

Measure't Setup 2B Indexed String G80 Visible Setting 0 1 1 1 * * *

Comms Settings 2C Indexed String G80 Visible Setting 0 1 1 1 * * *

Commission Tests 2D Indexed String G80 Visible Setting 0 1 1 1 * * *

Setting Values 2E Indexed String G54 Primary Setting 0 1 1 1 * * *

Control Inputs 2F Indexed String G80 Visible Setting 0 1 1 2 * * *

CLIO Inputs 30 Indexed String G37 40434 G37 Enabled Setting 0 1 1 2 * * *

CLIO Outputs 31 Indexed String G37 40435 G37 Enabled Setting 0 1 1 2 * * *

CLIO status (Hidden) 32 Cell value set to False if CLIO not fitted

(Note: No Courier text) Cell value set to True if CLIO is fitted

40400 G18 * * * Record selection command register

40401 G6 * * * Record control command register

CT AND VT RATIOS 0A 00 * * * values for multiplier see mult column

Main VT Primary 01 Courier Number (Voltage) 40500 40501 G35 110 Setting 100 1000000 1 2 * * * Label V1=Main VT Rating/110

Main VT Sec'y 02 Courier Number (Voltage) 40502 G2 110 Setting 80*V1 140*V1 1*V1 2 * * * Label M1=0A01/0A02

NVD VT Primary 05 Courier Number (Voltage) 40506 40507 G35 110 Setting 100 1000000 1 2 * * *Neutral Displacement VT Primary Label V3=Neutral Disp VT Rating/110

NVD VT Secondary 06 Courier Number (Voltage) 40508 G2 110 Setting 80*V3 140*V3 1*V3 2 * * *Neutral Displacement VT Secondary Label M3=0A05/0A06

Phase CT Primary 07 Courier Number (Current) 40509 G2 1 Setting 1 30000 1 2 * * * I1=Phase CT secondary rating

Phase CT Sec'y 08 Courier Number (Current) 40510 G2 1 Setting 1 5 4 2 * * * Label M4=0A07/0A08

E/F CT Primary 09 Courier Number (Current) 40511 G2 1 Setting 1 30000 1 2 * * Label I2=E/F CT secondary rating

E/F CT Secondary 0A Courier Number (Current) 40512 G2 1 Setting 1 5 4 2 * * Label M5=0A09/0A0A

SEF CT Primary 0B Courier Number (Current) 40513 G2 1 Setting 1 30000 1 2 * * * Label I3=SEF CT secondary rating

SEF CT Secondary 0C Courier Number (Current) 40514 G2 1 Setting 1 5 4 2 * * * Label M6=0A0B/0A0C

RECORD CONTROL 0B 00 * * *

Clear Events 01 Indexed String G11 No Command 0 1 1 1 * * *

Clear Faults 02 Indexed String G11 No Command 0 1 1 1 * * *

Clear Maint 03 Indexed String G11 No Command 0 1 1 1 * * *

Alarm Event 0B 04 Indexed String G37 40520 G37 Enabled Setting 0 1 1 2 * * *

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Output Event 0B 05 Indexed String G37 40521 G37 Enabled Setting 0 1 1 2 * * *

Opto Input Event 0B 06 Indexed String G37 40522 G37 Enabled Setting 0 1 1 2 * * *

Relay Sys Event 0B 07 Indexed String G37 40523 G37 Enabled Setting 0 1 1 2 * * *

Fault Rec Event 0B 08 Indexed String G37 40524 G37 Enabled Setting 0 1 1 2 * * *

Maint Rec Event 0B 09 Indexed String G37 40525 G37 Enabled Setting 0 1 1 2 * * *

Protection Event 0B 0A Indexed String G37 40526 G37 Enabled Setting 0 1 1 2 * * *

DDB 31 - 0 0B 0B Binary Flag (32 bits) 40527 40528 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 63 - 32 0B 0C Binary Flag (32 bits) 40529 40530 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 95 - 64 0B 0D Binary Flag (32 bits) 40531 40532 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 127 - 96 0B 0E Binary Flag (32 bits) 40533 40534 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 159 - 128 0B 0F Binary Flag (32 bits) 40535 40536 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 191 - 160 0B 10 Binary Flag (32 bits) 40537 40538 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *










DDB 511 - 480 0B 1A Binary Flag (32 bits) 40557 40558 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 543 - 512 0B 1B Binary Flag (32 bits) 40559 40560 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 575 - 544 0B 1C Binary Flag (32 bits) 40561 40562 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 607 - 576 0B 1D Binary Flag (32 bits) 40563 40564 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 639 - 608 0B 1E Binary Flag (32 bits) 40565 40566 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 671 - 640 0B 1F Binary Flag (32 bits) 40567 40568 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *











DDB 1022 - 992 0B 2A Binary Flag (32 bits) 40589 40590 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DISTURB RECORDER 0C 00 * * * DISTURBANCE RECORDER

Duration 01 Courier Number (Time) 40600 G2 1.5 Setting 0.1 10.5 0.01 2 * * *

Trigger Position 02 Courier Number (%) 40601 G2 33.3 Setting 0 100 0.1 2 * * *

Trigger Mode 03 Indexed String G34 40602 G34 Single 0 1 1 2 * * *

Analog Channel 1 04 Indexed String G31 40603 G31 VAN Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

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Analog Channel 2 05 Indexed String G31 40604 G31 VBN Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Analog Channel 3 06 Indexed String G31 40605 G31 VCN Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Analog Channel 4 07 Indexed String G31 40606 G31 VN Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Analog Channel 5 08 Indexed String G31 40607 G31 IA Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Analog Channel 6 09 Indexed String G31 40608 G31 IB Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Analog Channel 7 0A Indexed String G31 40609 G31 IC Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Analog Channel 8 0B Indexed String G31 40610 G31 IN SEF Setting 0 ** 1 2 * * *** Max = 7 for Model1, 8 for Model2, 11 for Model3

Digital Input 1 0C Indexed String G32 40611 G32 Relay 1 Setting 0 DDB Size 1 2 * * *

Input 1 Trigger 0D Indexed String G66 40612 G66 No Trigger Setting 0 2 1 2 * * *

Digital Input 2 0E Indexed String G32 40613 G32 Relay 2 Setting 0 DDB Size 1 2 * * *

Input 2 Trigger 0F Indexed String G66 40614 G66 No Trigger Setting 0 2 1 2 * * *

Digital Input 3 10 Indexed String G32 40615 G32 Relay 3 Setting 0 DDB Size 1 2 * * *

Input 3 Trigger 11 Indexed String G66 40616 G66 No Trigger Setting 0 2 1 2 * * *









Digital Input 8 1A Indexed String G32 40625 G32 Opto Input 1 Setting 0 DDB Size 1 2 * *

Relay 8 *

Input 8 Trigger 1B Indexed String G66 40626 G66 No Trigger Setting 0 2 1 2 * * *

Digital Input 9 1C Indexed String G32 40627 G32 Opto Input 2 Setting 0 DDB Size 1 2 * *

Relay 9 *


Digital Input 10 1E Indexed String G32 40629 G32 Opto Input 3 Setting 0 DDB Size 1 2 * *

Relay 10 *


Digital Input 11 20 Indexed String G32 40631 G32 Opto Input 4 Setting 0 DDB Size 1 2 * *

Relay 11 *



Relay 12 *



Relay 13 *

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Relay 14 *



Opto Input 1 *


Digital Input 16 2A Indexed String G32 40641 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 2 *


Digital Input 17 2C Indexed String G32 40643 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 3 *


Digital Input 18 2E Indexed String G32 40645 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 4 *


Digital Input 19 30 Indexed String G32 40647 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 5 *



Opto Input 6 *



Opto Input 7 *



Opto Input 8 *



Opto Input 9 *


Digital Input 24 3A Indexed String G32 40657 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 10 *


Digital Input 25 3C Indexed String G32 40659 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 11 *


Digital Input 26 3E Indexed String G32 40661 G32 Not Used Setting 0 DDB Size 1 2 * *

Opto Input 12 *



Opto Input 13 *



Opto Input 14 *

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Opto Input 15 *



Opto Input 16 *


Digital Input 31 48 Indexed String G32 40671 G32 Not Used Setting 0 DDB Size 1 2 * * *


Digital Input 32 4A Indexed String G32 40673 G32 Not Used Setting 0 DDB Size 1 2 * * *


MEASURE'T SETUP 0D 00 * * * MEASUREMENT SETTINGS

Default Display 01 Indexed String G52 40700 G52 Description Setting 0 7 1 2 * * *

Local Values 02 Indexed String G54 40701 G54 Primary Setting 0 1 1 1 * * * Local Measurement Values

Remote Values 03 Indexed String G54 40702 G54 Primary Setting 0 1 1 1 * * * Remote Measurement Values

Measurement Ref 04 Indexed String G56 40703 G56 VA Setting 0 5 1 1 * * * Measurement Phase Reference

Measurement Mode 05 Unsigned Integer 40705 G1 0 Setting 0 3 1 1 * * *

Fix Dem Period 06 Courier Number (time-minutes) 40706 G2 15 Setting 1 99 1 2 * * * Fixed Demand Interval

Roll Sub Period 07 Courier Number (time-minutes) 40707 G2 1 Setting 1 99 1 2 * * * Rolling demand sub period

Num Sub Periods 08 Unsigned Integer 40708 G1 15 Setting 1 15 1 2 * * * Number of rolling sub-periods

Remote 2 Values 0B Indexed String G54 G54 Primary Setting 0 1 1 2 * * *Remote 2 Measurement Values visible when model no. hardware option (Field 7) = 7 or 8

COMMUNICATIONS 0E 00 * * *

Rear Protocol 01 Indexed String G71 Data * * *

Remote Address 02 Unsigned integer (16 bits) 255 Setting 0 255 1 1 * * * Build = Courier

Remote Address 02 Unsigned integer (16 bits) 1 Setting 1 247 1 1 * * * Build = Modbus. Default Modbus address is 1

Remote Address 02 Unsigned integer (16 bits) 1 Setting 0 254 1 1 * * * Build = IEC60870-5-103

Remote Address 02 Unsigned integer (16 bits) 1 Setting 0 65534 1 1 * * * Build=DNP 3.0

Inactivity Timer 03 Courier Number (Time-minutes) 15 Setting 1 30 1 2 * * * Build = Courier

Inactivity Timer 03 Courier Number (Time-minutes) 15 Setting 1 30 1 2 * * * Build = Modbus

Inactivity Timer 03 Courier Number (Time-minutes) 15 Setting 1 30 1 2 * * * Build = IEC60870-5-103

Baud Rate 04 Indexed String G38m 19200 bits/s Setting 0 2 1 2 * * * Build = Modbus

Baud Rate 04 Indexed String G38v 19200 bits/s Setting 0 1 1 2 * * * Build = IEC60870-5-103

Baud Rate 04 Indexed String G38d 19200 bits/s Setting 0 5 1 2 * * * Build = DNP 3.0

Parity 05 Indexed String G39 None Setting 0 2 1 2 * * * Build = Modbus

Parity 05 Indexed String G39 None Setting 0 2 1 2 * * * Build = DNP 3.0

Measure't Period 06 Courier Number (Time) 15 Setting 1 60 1 2 * * * Build = IEC60870-5-103

Physical Link 07 Indexed String G21 RS485 Setting 0 1 1 1 * * *Build=IEC60870-5-103 and Fibre Optic Board fitted

Time Sync 08 Indexed String G37 Disabled Setting 0 1 1 2 * * * Build=DNP 3.0 visible when IRIG-B is disabled

CS103 Blocking 0A Indexed String G210 Disabled Setting 0 2 1 2 * * * Build=IEC60870-5-103

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REAR PORT2 (RP2) 80 (Sub Heading) * * *Visible when Model no. Hardware option (Field 7) = 7 or 8

RP2 Protocol 81 ASCII Text(16 chars) Courier Data * * *Visible when Model no. Hardware option (Field 7) = 7 or 8. Implemented as datatype G71

RP2 Card Status 84 Indexed String G204 Data * * *Visible when Model no. Hardware option (Field 7) = 7 or 8

RP2 Port Config 88 Indexed String G205 EIA232 (RS232) Setting 0 1 1 2 * * * Visible if RP2 Card status = OK

RP2 Comms Mode 8A Indexed String G206 IEC60870 FT1.2 Setting 0 1 1 2 * * * Visible if RP2 Card status = OK and 0E88<2

RP2 Address 90 Unsigned Integer (16 bits) 255 Setting 0 255 1 1 * * * Visible if RP2 Card status = OK

RP2 InactivTimer 92 Courier Number (time-minutes) 15 Setting 1 30 1 2 * * * Visible if RP2 Card status = OK

RP2 Baud Rate 94 Indexed String G38c 19200 bits/s Setting 0 2 1 2 * * * Visible if RP2 Card status = OK and

COMMISSION TESTS 0F 00 * * *

LED Status 04 Binary Flag(8 bits) Data * * *

Monitor Bit 1 05 Unsigned Integer 40850 G1 64 Setting 0 1022 1 1 * * *





Monitor Bit 6 0A Unsigned Integer 40855 G1 69 Setting 0 1022 1 1 * * *

Monitor Bit 7 0B Unsigned Integer 40856 G1 70 Setting 0 1022 1 1 * * *

Monitor Bit 8 0C Unsigned Integer 40857 G1 71 Setting 0 1022 1 1 * * *

Test Mode 0D Indexed String G119 40858 G119 Disabled Setting 0 2 1 2 * * * IEC60870 Test Mode Change

Contact Test 0F Indexed String G93 40861 G93 No Operation Command 0 2 1 2 * * * IEC60870 Test Mode Change

DDB 31 - 0 N/A 20 Binary Flag(32) 30723 30724 G27 Data * * * DDB Elements 0-31

DDB 63 - 32 N/A 21 Binary Flag(32) 30725 30726 G27 Data * * *








The following cells (0F20 to 0F3F) and Modbus addresses (30723 to 30786) are available to access real-time DDB status, including starts, trips and alarms

* * 10 1 1 2 *G94 No Operation Command 0Binary Flag(8 bits) Indexed String

G94 40862Test LEDs

0ETest Pattern 40859Binary Flag Indexed String

G9 IEC60870 Test Mode ChangeSetting0G940860 21200 ***

Data30726 G8

Data03Binary Flag(8 bits) Indexed String

Opto I/P Status 01Binary Flag(32 bits) Indexed String

G8 30725

G9

* * *

Relay O/P Status

Test Port Status

Binary Flag(32 bits) Indexed String

02 G93000930008 *** Data

* * *The original register 30007 is available for opto inputs #1 to #16

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DDB 351 - 320 N/A 2A Binary Flag(32) 30743 30744 G27 Data * * *

DDB 383 - 352 N/A 2B Binary Flag(32) 30745 30746 G27 Data * * *

DDB 415 - 384 N/A 2C Binary Flag(32) 30747 30748 G27 Data * * *

DDB 447 - 416 N/A 2D Binary Flag(32) 30749 30750 G27 Data * * *

DDB 479 - 448 N/A 2E Binary Flag(32) 30751 30752 G27 Data * * *

DDB 511 - 480 N/A 2F Binary Flag(32) 30753 30754 G27 Data * * *











DDB 863 - 832 N/A 3A Binary Flag(32) 30775 30776 G27 Data * * *

DDB 895 - 864 N/A 3B Binary Flag(32) 30777 30778 G27 Data * * *

DDB 927 - 896 N/A 3C Binary Flag(32) 30779 30780 G27 Data * * *

DDB 959 - 928 N/A 3D Binary Flag(32) 30781 30782 G27 Data * * *

DDB 991 - 960 N/A 3E Binary Flag(32) 30783 30784 G27 Data * * *

DDB 1022 - 992 N/A 3F Binary Flag(32) 30785 30786 G27 Data * * *

N/A Binary Flag(16) 30701 G26 Data * * * Relay Status (repeat of Courier status)

N/A Courier Number (current) 30702 30703 G24 Data * * * IA Magnitude

N/A Courier Number (current) 30704 30705 G24 Data * * * IB Magnitude

N/A Courier Number (current) 30706 30707 G24 Data * * * IC Magnitude

N/A Courier Number (voltage) 30708 30709 G24 Data * * * VAB Magnitude

N/A Courier Number (voltage) 30710 30711 G24 Data * * * VBC Magnitude

N/A Courier Number (voltage) 30712 30713 G24 Data * * * VCA Magnitude

N/A Courier Number (power) 30714 30716 G29 Data * * * 3 Phase Watts

N/A Courier Number (power) 30717 30719 G29 Data * * * 3 Phase VArs

N/A Courier Number (decimal) 30720 G30 Data * * * 3 Phase Power Factor

N/A Courier Number (frequency) 30721 G30 Data * * * Frequency

N/A Binary Flag(8) 30722 G1 Data * * * Relay Test Port Status

CB MONITOR SETUP 10 00 * * *

Broken I^ 01 Courier Number (Decimal) 40151 G2 2 Setting 1 2 0.1 2 * * * Broken Current Index

I^ Maintenance 02 Indexed String G88 40152 G88 Alarm Disabled Setting 0 1 1 2 * * * Broken Current to cause maintenance alarm

I^ Maintenance 03 Courier Number (Current) 40153 40154 G35 1000 Setting 1 25000 1 2 * * * IX Maintenance Alarm

I^ Lockout 04 Indexed String G88 40155 G88 Alarm Disabled Setting 0 1 1 2 * * * Broken Current to cause lockout alarm

I^ Lockout 05 Courier Number (Current) 40156 40157 G35 2000 Setting 1 25000 1 2 * * * IX Maintenance Lockout

No. CB Ops Maint 06 Indexed String G88 40158 G88 Alarm Disabled Setting 0 1 1 2 * * *Circuit Breaker Trips to cause maintenance alarm

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No. CB Ops Maint 07 Unsigned Integer 40159 G1 10 Setting 1 10000 1 2 * * *Number of Circuit Breaker Trips for maintenance alarm

No. CB Ops Lock 08 Indexed String G88 40160 G88 Alarm Disabled Setting 0 1 1 2 * * * Circuit Breaker Trips to cause lockout alarm

No. CB Ops Lock 09 Unsigned Integer 40161 G1 20 Setting 1 10000 1 2 * * *Number of Circuit Breaker Trips for lockout alarm

CB Time Maint 0A Indexed String G88 40162 G88 Alarm Disabled Setting 0 1 1 2 * * *Circuit Breaker Operating Time to cause maintenance alarm

CB Time Maint 0B Courier Number (Time) 40163 40164 G35 0.1 Setting 0.005 0.5 0.001 2 * * *Circuit Breaker Operating time for maintenance alarm

CB Time Lockout 0C Indexed String G88 40165 G88 Alarm Disabled Setting 0 1 1 2 * * *Circuit Breaker Operating Time to cause lockout alarm

CB Time Lockout 0D Courier Number (Time) 40166 40167 G35 0.2 Setting 0.005 0.5 0.001 2 * * *Circuit Breaker Operating time for lockout alarm

Fault Freq Lock 0E Indexed String G88 40168 G88 Alarm Disabled Setting 0 1 1 2 * * * Excessive fault frequency

Fault Freq Count 0F Unsigned Integer 40169 G1 10 Setting 1 9999 1 2 * * * Excessive Fault Frequency Counter

Fault Freq Time 10 Courier Number (Time) 40170 40171 G35 3600 Setting 0 9999 1 2 * * * Excessive Fault Frequency Time

OPTO CONFIG 11 00 * * *Visible for Model Number design suffix 'B' and beyond

Global Nominal V 01 Indexed String G200 40900 G200 48-54V Setting 0 5 1 2 * * *Select Custom to select individual Opto Threshold Voltages

Opto Input 1 02 Indexed String G201 40901 G201 48-54V Setting 0 4 1 2 * * *








Opto Input 9 0A Indexed String G201 40909 G201 48-54V Setting 0 4 1 2 * * *

Opto Input 10 0B Indexed String G201 40910 G201 48-54V Setting 0 4 1 2 * * *

Opto Input 11 0C Indexed String G201 40911 G201 48-54V Setting 0 4 1 2 * * *

Opto Input 12 0D Indexed String G201 40912 G201 48-54V Setting 0 4 1 2 * * *

Opto Input 13 0E Indexed String G201 40913 G201 48-54V Setting 0 4 1 2 * * *

Opto Input 14 0F Indexed String G201 40914 G201 48-54V Setting 0 4 1 2 * * *











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Opto Input 25 1A Indexed String G201 40925 G201 48-54V Setting 0 4 1 2 *

Opto Input 26 1B Indexed String G201 40926 G201 48-54V Setting 0 4 1 2 *

Opto Input 27 1C Indexed String G201 40927 G201 48-54V Setting 0 4 1 2 *

Opto Input 28 1D Indexed String G201 40928 G201 48-54V Setting 0 4 1 2 *

Opto Input 29 1E Indexed String G201 40929 G201 48-54V Setting 0 4 1 2 *

Opto Input 30 1F Indexed String G201 40930 G201 48-54V Setting 0 4 1 2 *

Opto Input 31 20 Indexed String G201 40931 G201 48-54V Setting 0 4 1 2 *

Opto Input 32 21 Indexed String G201 40932 G201 48-54V Setting 0 4 1 2 *

CONTROL INPUTS 12 00 * * *

Ctrl I/P Status 01 Binary Flag (32 bits) G202 40950 40951 G202 Setting 2 * * *

Control Input 1 02 Indexed String G203 40952 G203 No Operation Command 0 2 1 2 * * *








Control Input 9 0A Indexed String G203 40960 G203 No Operation Command 0 2 1 2 * * *

Control Input 10 0B Indexed String G203 40961 G203 No Operation Command 0 2 1 2 * * *

Control Input 11 0C Indexed String G203 40962 G203 No Operation Command 0 2 1 2 * * *

Control Input 12 0D Indexed String G203 40963 G203 No Operation Command 0 2 1 2 * * *

Control Input 13 0E Indexed String G203 40964 G203 No Operation Command 0 2 1 2 * * *

Control Input 14 0F Indexed String G203 40965 G203 No Operation Command 0 2 1 2 * * *











Control Input 25 1A Indexed String G203 40976 G203 No Operation Command 0 2 1 2 * * *

Control Input 26 1B Indexed String G203 40977 G203 No Operation Command 0 2 1 2 * * *

Control Input 27 1C Indexed String G203 40978 G203 No Operation Command 0 2 1 2 * * *

Control Input 28 1D Indexed String G203 40979 G203 No Operation Command 0 2 1 2 * * *

Control Input 29 1E Indexed String G203 40980 G203 No Operation Command 0 2 1 2 * * *

Control Input 30 1F Indexed String G203 40981 G203 No Operation Command 0 2 1 2 * * *



GROUP 1

GEN DIFF

GenDiff Function 01 Indexed String G101 41000 G101 Percentage Bias Setting 0 3 1 2 *

*30 00

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Gen Diff Is1 02 Courier Number (Current) 41001 G2 0.1 Setting 0.05*I1 0.5*I1 0.01*I1 2 *

Gen Diff k1 03 Courier Number (Percentage) 41002 G2 0 Setting 0 20 5 2 *

Gen Diff Is2 04 Courier Number (Current) 41003 G2 1.2 Setting 1*I1 5*I1 0.1*I1 2 *

Gen Diff k2 05 Courier Number (Percentage) 41004 G2 150 Setting 20 150 10 2 *

Interturn Is_A 10 Courier Number (Current) 41005 G2 0.1 Setting 0.05*I1 2*I1 0.01*I1 2 *

Interturn Is_B 14 Courier Number (Current) 41006 G2 0.1 Setting 0.05*I1 2*I1 0.01*I1 2 *

Interturn Is_C 18 Courier Number (Current) 41007 G2 0.1 Setting 0.05*I1 2*I1 0.01*I1 2 *

Interturn Delay 1C Courier Number (Time) 41008 G2 0.1 Setting 0 100 0.01 2 *

GROUP 1

POWER

Operating Mode 20 Indexed String G115 41064 G115 Generating Setting 0 1 1 2 * * *

Power1 Function 24 Indexed String G102 41050 G102 Over Setting 0 3 1 2 *

-P>1 Setting 28 Courier Number (Power) 41051 G2 20 Setting 14*V1*I1 300*V1*I1 2*V1*I1 2 *

5 4*V1*I1 300*V1*I1 0.5*V1*I1 2 * *

P<1 Setting 2C Courier Number (Power) 41052 G2 20 Setting 14*V1*I1 300*V1*I1 2*V1*I1 2 *

10 4*V1*I1 300*V1*I1 0.5*V1*I1 2 * *

P>1 Setting 30 Courier Number (Power) 41053 G2 120 Setting 14*V1*I1 300*V1*I1 2*V1*I1 2 *

120 4*V1*I1 300*V1*I1 0.5*V1*I1 2 * *

Power1 TimeDelay 34 Courier Number (Time) 41054 G2 5 Setting 0 100 0.01 2 * * *

Power1 DO Timer 38 Courier Number (Time) 41055 G2 0 Setting 0 100 0.01 2 * * *

P1 Poledead Inh 3C Indexed String G37 41056 G37 Enabled Setting 0 1 1 2 * * *

Power2 Function 40 Indexed String G102 41057 G102 Disabled Setting 0 3 1 2 *

Low Forward * *

-P>2 Setting 44 Courier Number (Power) 41058 G2 20 Setting 14*V1*I1 300*V1*I1 2*V1*I1 2 *

5 4*V1*I1 300*V1*I1 0.5*V1*I1 2 * *

P<2 Setting 48 Courier Number (Power) 41059 G2 20 Setting 14*V1*I1 300*V1*I1 2*V1*I1 2 *

10 4*V1*I1 300*V1*I1 0.5*V1*I1 2 * *

P>2 Setting 4C Courier Number (Power) 41060 G2 120 Setting 14*V1*I1 300*V1*I1 2*V1*I1 2 *

120 4*V1*I1 300*V1*I1 0.5*V1*I1 2 * *

Power2 TimeDelay 50 Courier Number (Time) 41061 G2 2 Setting 0 100 0.01 2 * * *


P2 Poledead Inh 58 Indexed String G37 41063 G37 Enabled Setting 0 1 1 2 * * *

GROUP 1

FIELD FAILURE

FFail Alm Status 01 Indexed String G37 41100 G37 Disabled Setting 0 1 1 2 * *

FFail Alm Angle 02 Courier Number (Angle) 41101 G2 15 Setting 15 75 1 2 * *

FFail Alm Delay 03 Courier Number (Time) 41102 G2 5 Setting 0 100 0.01 2 * *

FFail1 Status 04 Indexed String G37 41103 G37 Enabled Setting 0 1 1 2 * *

FFail1 -Xa1 05 Courier Number (Impedance) 41104 G2 20 Setting 0 40*V1/I1 0.5*V1/I1 2 * *

FFail1 Xb1 06 Courier Number (Impedance) 41105 G2 220 Setting 25*V1/I1 325*V1/I1 1*V1/I1 2 * *

FFail1 TimeDelay 07 Courier Number (Time) 41106 G2 5 Setting 0 100 0.01 2 * *

FFail1 DO Timer 08 Courier Number (Time) 41107 G2 0 Setting 0 100 0.01 2 * *

FFail2 Status 09 Indexed String G37 41108 G37 Disabled Setting 0 1 1 2 * *

FFail2 -Xa2 0A Courier Number (Impedance) 41109 G2 20 Setting 0 40*V1/I1 0.5*V1/I1 2 * *

FFail2 Xb2 0B Courier Number (Impedance) 41110 G2 110 Setting 25*V1/I1 325*V1/I1 1*V1/I1 2 * *

** *

*

31 00

* 32 00

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FFail2 TimeDelay 0C Courier Number (Time) 41111 G2 0 Setting 0 100 0.01 2 * *

FFail2 DO Timer 0D Courier Number (Time) 41112 G2 0 Setting 0 100 0.01 2 * *

GROUP 1

NPS THERMAL

I2>1 Alarm 01 Indexed String G37 41150 G37 Enabled Setting 0 1 1 2 * *

I2>1 Current Set 02 Courier Number (Current) 41151 G2 0.05 Setting 0.03*I1 0.5*I1 0.01*I1 2 * *

I2>1 Time Delay 03 Courier Number (Time) 41152 G2 20s Setting 0 100 0.01 2 * *

I2>2 Trip 04 Indexed String G37 41153 G37 Enabled Setting 0 1 1 2 * *

I2>2 Current Set 05 Courier Number (Current) 41154 G2 0.1 Setting 0.05*I1 0.5*I1 0.01*I1 2 * *

I2>2 k Setting 06 Courier Number (Time) 41155 G2 15 Setting 2 40 0.1 2 * *

I2>2 kRESET 07 Courier Number (Time) 41156 G2 15 Setting 2 40 0.1 2 * *

I2>2 tMAX 08 Courier Number (Time) 41157 G2 1000 Setting 500 2000 1 2 * *

I2>2 tMIN 09 Courier Number (Time) 41158 G2 0.25 Setting 0 100 0.01 2 * *

GROUP 1

SYSTEM BACKUP

Backup Function 01 Indexed String G103 41200 G103 Voltage controlled Setting 0 3 1 2 * *

Vector Rotation 02 Indexed String G104 41201 G104 None Setting 0 1 1 2 * *

V Dep OC Char 20 Indexed String G111 41202 G111 IEC S Inverse Setting 0 11 1 2 * *

V Dep OC I> Set 23 Courier Number (Current) 41203 G2 1 Setting 0.8*I1 4*I1 0.01*I1 2 * *

V Dep OC T Dial 25 Courier Number (Decimal) 41204 G2 1 Setting 0.01 100 0.01 2 * *

V Dep OC Reset 26 Indexed String G60 41205 G60 DT Setting 0 1 1 2 * *OC reset characteritic selection. Apply to US curves only

V Dep OC Delay 27 Courier Number (Time) 41206 G2 1 Setting 0 100 0.01 2 * * Apply to DT trip characteristic only

V Dep OC TMS 28 Courier Number (Decimal) 41207 G2 1 Setting 0.025 1.2 0.025 2 * *

V Dep OC K (RI) 29 Courier Number (Decimal) 41219 G2 1 Setting 0.1 10 0.05 2 * *

V Dep OC tRESET 2A Courier Number (Time) 41208 G2 0 Setting 0 100 0.01 2 * *

V Dep OC V<1 Set 2D Courier Number (Voltage) 41209 G2 80 Setting 5*V1 120*V1 1*V1 2 * *

V Dep OC V<2 Set 2E Courier Number (Voltage) 41210 G2 60 Setting 5*V1 120*V1 1*V1 2 * *

V Dep OC k Set 2F Courier Number (Decimal) 41211 G2 0.25 Setting 0.1 1 0.05 2 * *

Z<1 Setting 30 Courier Number (Impedance) 41212 G2 70 Setting 2*V1/I1 120*V1/I1 0.5*V1/I1 2 * *

Z<1 Time Delay 31 Courier Number (Time) 41213 G2 5 Setting 0 100 0.01 2 * *

Z<1 tRESET 32 Courier Number (Time) 41214 G2 0 Setting 0 100 0.01 2 * *

Z< Stage 2 33 Indexed String G37 41215 G37 Disabled Setting 0 1 1 2 * *

Z<2 Setting 34 Courier Number (Impedance) 41216 G2 70 Setting 2*V1/I1 120*V1/I1 0.5*V1/I1 2 * *

Z<2 Time Delay 35 Courier Number (Time) 41217 G2 5 Setting 0 100 0.01 2 * *

Z<2 tRESET 36 Courier Number (Time) 41218 G2 0 Setting 0 100 0.01 2 * *

GROUP 1

OVERCURRENT

I>1 Function 23 Indexed String G150 41250 G150 Disabled Setting 0 12 1 2 * *

IEC S Inverse *

I>1 Direction 24 Indexed String G44 41251 G44 Non-Directional Setting 0 2 1 2 *

I>1 Current Set 27 Courier Number (Current) 41252 G2 1 Setting 0.08*I1 4.0*I1 0.01*I1 2 * * * I>1 Current Setting

I>1 Time Delay 29 Courier Number (Time) 41253 G2 1 Setting 0 100 0.01 2 * * * I>1 Definite Time

I>1 TMS 2A Courier Number (Decimal) 41254 G2 1 Setting 0.025 1.2 0.025 2 * * *

I>1 Time Dial 2B Courier Number (Decimal) 41255 G2 1 Setting 0.01 100 0.01 2 * * *

** *35 00

** 34 00

Will include NPS Overcurrent (P341) and NPS overvoltage in Phase 2.20

** 0033

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I>1 K (RI) 2C Courier Number (Decimal) 41276 G2 1 Setting 0.1 10 0.05 2 * * *

I>1 Reset Char 2E Indexed String G60 41256 G60 DT Setting 0 1 1 2 * * *

I>1 tRESET 2F Courier Number (Time) 41257 G2 0 Setting 0 100 0.01 2 * * *

I>2 Function 32 Indexed String G150 41258 G150 Disabled Setting 0 12 1 2 * I>2 Overcurrent Status

G105 G105 DT 0 1 1 2 * *


I>2 Current Set 36 Courier Number (Current) 41260 G2 1 Setting 0.08*I1 4.0*I1 0.01*I1 2 *

10 0.08*I1 10.0*I1 0.01*I1 2 * *

I>2 Time Delay 38 Courier Number (Time) 41261 G2 1 Setting 0 100 0.01 2 *

I>2 TMS 39 Courier Number (Decimal) 41262 G2 1 Setting 0.025 1.2 0.025 2 *

I>2 Time Dial 3A Courier Number (Decimal) 41263 G2 1 Setting 0.01 100 0.01 2 *

I>2 K (RI) 3B Courier Number (Decimal) 41277 G2 1 Setting 0.1 10 0.05 2 *

I>2 Reset Char 3D Indexed String G60 41264 G60 DT Setting 0 1 1 2 *

I>2 tRESET 3E Courier Number (Time) 41265 G2 0 Setting 0 100 0.01 2 *

I>3 Status 40 Indexed String G37 41266 G37 Disabled Setting 0 1 1 2 *


I>3 Current Set 44 Courier Number (Current) 41268 G2 20 Setting 0.08*I1 32*I1 0.01*I1 2 *

I>3 Time Delay 45 Courier Number (Time) 41269 G2 0 Setting 0 100 0.01 2 *

I>4 Status 47 Indexed String G37 41270 G37 Disabled Setting 0 1 1 2 *


I>4 Current Set 4B Courier Number (Current) 41272 G2 20 Setting 0.08*I1 32*I1 0.01*I1 2 *

I>4 Time Delay 4C Courier Number (Time) 41273 G2 0 Setting 0 100 0.01 2 *

I> Char Angle 4E Courier Number (Angle) 41274 G2 30 Setting -95 95 1 2 * I> Characteristic Angle

I> Function Link 4F Binary Flag G14 41275 G14 15 Setting 15 4 1 2 *

GROUP 1

THERMAL OVERLOAD

Thermal 50 Indexed String G37 41308 G37 Enabled Setting 0 1 1 2 * * * Thermal overload (I2t characteristic)

Thermal I> 55 Courier Number (Current) 41309 G2 1.2 Setting 0.5*I1 2.5*I1 0.01*I1 2 * * *

Thermal Alarm 5A Courier Number (Percentage) 41310 G2 90 Setting 20 100 1 2 * * *

T-heating 5F Courier Number (Time, minutes) 41311 G2 60 Setting 1 200 1 2 * * *

T-cooling 64 Courier Number (Time, minutes) 41312 G2 60 Setting 1 200 1 2 * * *

M Factor 69 Courier Number (Decimal) 41313 G2 0 Setting 0 10 1 2 * * *

GROUP 1

Not Used

GROUP 1

EARTH FAULT

IN Input 01 Indexed String G49 G49 Derived Data *

IN>1 Function 25 Indexed String G151 41400 G151 IEC S Inverse Setting 0 12 1 2 * * *

IN>1 Direction 26 Indexed String G44 41401 G44 Non-Directional Setting 0 2 1 2 *

IN>1 Current 29 Courier Number (Current) 41402 G2 0.2 Setting 0.08*I1 4.0*I1 0.01*I1 2 *

0.1 0.02*I2 4.0*I2 0.01*I2 * * Change scaling factor for Models 2 & 3

IN>1 IDG Is 2A Courier Number (Decimal) 41431 G2 1.5 Setting 1 4 0.1 2 * * *

IN>1 Time Delay 2C Courier Number (Time) 41403 G2 1 Setting 0 200 0.01 2 * * * I>1 Definite Time

IN>1 TMS 2D Courier Number (Decimal) 41404 G2 1 Setting 0.025 1.2 0.025 2 * * *

** *38 00

*

37 00

* *36 00

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IN>1 Time Dial 2E Courier Number (Decimal) 41405 G2 1 Setting 0.01 100 0.01 2 * * *

IN>1 K (RI) 2F Courier Number (Decimal) 41432 G2 1 Setting 0.1 10 0.05 2 * * *

IN>1 IDG Time 30 Courier Number (Decimal) 41433 G2 1.2 Setting 1 2 0.01 2 * * *

IN>1 Reset Char 32 Indexed String G60 41406 G60 DT Setting 0 1 1 2 * * *

IN>1 tRESET 33 Courier Number (Time) 41407 G2 0 Setting 0 100 0.01 2 * * *

IN>2 Function 36 Indexed String G151 41408 G151 Disabled Setting 0 12 1 2 *

G105 G105 Disabled 1 1 1 2 * *


IN>2 Current 3A Courier Number (Current) 41410 G2 0.2 Setting 0.08*I1 4.0*I1 0.01*I1 2 *

0.45 0.02*I2 10.0*I2 0.01*I2 * * Change scaling factor for Models 2 & 3

IN>2 IDG Is 3B Courier Number (Decimal) 41434 G2 1.5 Setting 1 4 0.1 2 *IN>2 Time Delay 3D Courier Number (Time) 41411 G2 1 Setting 0 200 0.01 2 *

0 * *

IN>2 TMS 3E Courier Number (Decimal) 41412 G2 1 Setting 0.025 1.2 0.025 2 *

IN>2 Time Dial 3F Courier Number (Decimal) 41413 G2 1 Setting 0.01 100 0.01 2 *

IN>2 K (RI) 40 Courier Number (Decimal) 41435 G2 1 Setting 0.1 10 0.05 2 *

IN>2 IDG Time 41 Courier Number (Time) 41436 G2 1.2 Setting 1 2 0.01 2 *

IN>2 Reset Char 43 Indexed String G60 41414 G60 DT Setting 0 1 1 2 *

IN>2 tRESET 44 Courier Number (Time) 41415 G2 0 Setting 0 100 0.01 2 *

IN>3 Status 46 Indexed String G37 41416 G37 Disabled Setting 0 1 1 2 *


IN>3 Current 4A Courier Number (Current) 41418 G2 0.5 Setting 0.08*I1 32*I1 0.01*I1 2 *

IN>3 Time Delay 4B Courier Number (Time) 41419 G2 0 Setting 0 200 0.01 2 *

IN>4 Status 4D Indexed String G37 41420 G37 Disabled Setting 0 1 1 2 *

IN>4 Direction 4E Indexed String G44 41421 G44 Non-Directional Setting 0 2 1 2 *

IN>4 Current 51 Courier Number (Current) 41422 G2 0.5 Setting 0.08*I1 32*I1 0.01*I1 2 *

IN>4 Time Delay 52 Courier Number (Time) 41423 G2 0 Setting 0 200 0.01 2 *

IN> Func Link 54 Binary Flags G63 41424 G63 15 Setting 15 4 1 2 *

IN> DIRECTIONAL 55 (Sub Heading) 2 *

IN> Char Angle 56 Courier Number(Angle) 41425 G2 -60 Setting -95 95 1 2 *

IN> Pol 57 Indexed String G46 41426 G46 Zero Sequence Setting 0 1 1 2 *

IN> VNpol Input 58 Indexed String G49 41427 G49 Measured Setting 0 1 1 2 *IN> VNpol Set 59 Courier Number (Voltage) 41428 G2 5 Setting 0.5*V1 80*V1 0.5*V1 2 * IN> V0 Polarising Setting

0.5*V3 80*V3 0.5*V3 Change scaling factor

IN> V2pol Set 5A Courier Number (Voltage) 41429 G2 5 Setting 0.5*V1 25*V1 0.5*V1 2 * IN> V2 Polarising Setting

IN> I2pol Set 5B Courier Number (Current) 41430 G2 0.08 Setting 0.08*I1 1*I1 0.01*I1 2 *

GROUP 1

Not Used

GROUP 1

SEF/REF PROT'NSEF/REF Options 01 Indexed String G58 41500 G58 SEF Setting 0 4 1 2 * Protection Options

0 7 1 2 * *ISEF>1 Function 2A Indexed String G152 41501 G152 DT Setting 0 11 1 2 *

G105 G105 0 1 1 * *

ISEF>1 Direction 2B Indexed String G44 41502 G44 Non-Directional Setting 0 2 1 2 * * * ISEF>1 Directionality

ISEF>1 Current 2E Courier Number (Current) 41503 G2 0.05 Setting 0.005*I3 0.1*I3 0.00025*I3 2 * * * ISEF>1 Current Setting

** *3A 00

39 00

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ISEF>1 IDG Is 2F Courier Number (Decimal) 41535 G2 1.5 Setting 1 4 0.1 2 *

ISEF>1 Delay 31 Courier Number (Time) 41504 G2 1 Setting 0 200 0.01 2 * * * ISEF>1 Definite Time

ISEF>1 TMS 32 Courier Number (Decimal) 41505 G2 1 Setting 0.025 1.2 0.025 2 *

ISEF>1 Time Dial 33 Courier Number (Decimal) 41506 G2 1 Setting 0.01 100 0.01 2 *

ISEF>1 IDG Time 34 Courier Number (Time) 41536 G2 1.2 Setting 1 2 0.01 2 *

ISEF>1 Reset Chr 36 Indexed String G60 41507 G60 DT Setting 0 1 1 2 *

ISEF>1 tRESET 37 Courier Number (Time) 41508 G2 0 Setting 0 100 0.01 2 *

ISEF>2 Function 3A Indexed String G152 41509 G152 Disabled Setting 0 11 1 2 *

ISEF>2 Direction 3B Indexed String G44 41510 G44 Non-Directional Setting 0 2 1 2 *

ISEF>2 Current 3E Courier Number (Current) 41511 G2 0.05 Setting 0.005*I3 0.1*I3 0.00025*I3 2 *

ISEF>2 IDG Is 3F Courier Number (Decimal) 41537 G2 1.5 Setting 1 4 0.1 2 *

ISEF>2 Delay 41 Courier Number (Time) 41512 G2 1 Setting 0 200 0.01 2 *

ISEF>2 TMS 42 Courier Number (Decimal) 41513 G2 1 Setting 0.025 1.2 0.025 2 *

ISEF>2 Time Dial 43 Courier Number (Decimal) 41514 G2 1 Setting 0.01 100 0.01 2 *

ISEF>2 IDG Time 44 Courier Number (Time) 41538 G2 1.2 Setting 1 2 0.01 2 *

ISEF>2 Reset Chr 46 Indexed String G60 41515 G60 DT Setting 0 1 1 2 *

ISEF>2 tRESET 47 Courier Number (Time) 41516 G2 0 Setting 0 100 0.01 2 *

ISEF>3 Status 49 Indexed String G37 41517 G37 Disabled Setting 0 1 1 2 *

ISEF>3 Direction 4A Indexed String G44 41518 G44 Non-Directional Setting 0 2 1 2 * ISEF>3 Directionality

ISEF>3 Current 4D Courier Number (Current) 41519 G2 0.4 Setting 0.005*I3 0.80*I3 0.001*I3 2 * ISEF>3 Current Setting

ISEF>3 Delay 4E Courier Number (Time) 41520 G2 0.5 Setting 0 200 0.01 2 * ISEF>3 Definite Time

ISEF>4 Status 50 Indexed String G37 41521 G37 Disabled Setting 0 1 1 2 *

ISEF>4 Direction 51 Indexed String G44 41522 G44 Non-Directional Setting 0 2 1 2 * ISEF>4 Directionality

ISEF>4 Current 54 Courier Number (Current) 41523 G2 0.6 Setting 0.005*I3 0.80*I3 0.001*I3 2 * ISEF>4 Current Setting

ISEF>4 Delay 55 Courier Number (Time) 41524 G2 0.25 Setting 0 200 0.01 2 * ISEF>4 Definite Time

ISEF> Func Link 57 Binary Flags G64 41525 G64 15 Setting 15 4 1 2 *

ISEF DIRECTIONAL 58 (Sub Heading) 2 * * *

ISEF> Char Angle 59 Courier Number(Angle) 41526 G2 90 Setting -95 95 1 2 * * *

ISEF>VNpol Input 5A Indexed String G49 41527 G49 Measured Setting 0 1 1 2 * * *ISEF> VNpol Set 5B Courier Number (Voltage) 41528 G2 5 Setting 0.5*V1 80*V1 0.5*V1 2 * * *

0.5*V3 80*V3 0.5*V3 * * *

WATTMETRIC SEF 5D (Sub Heading) * * *PN> Setting 5E Courier Number (Power) 41529 G2 9 Setting 0.0*V1*I3 20*V1*I3 0.05*V1*I3 2 * * *

0.0*V3*I3 20*V3*I3 0.05*V3*I3 * * *

RESTRICTED E/F 60 (Sub Heading) * * * Restricted Earth Fault

IREF> k1 61 Courier Number (Percentage) 41530 G2 20 Setting 0 20 1 2 * * REF K1, applied to L Impedance

IREF> k2 62 Courier Number (Percentage) 41531 G2 150 Setting 0 150 1 2 * * REF K2, applied to L impedance

IREF> Is1 63 Courier Number (Current) 41532 G2 0.2 Setting 0.05*I1 1.0*I1 0.01*I1 2 * * REF Is1, applied to L impedance

IREF> Is2 64 Courier Number (Current) 41533 G2 1 Setting 0.1*I1 1.5*I1 0.01*I1 2 * * REF Is2, applied to L impedance

IREF> Is 65 Courier Number (Current) 41534 G2 0.2 Setting 0.05*I3 1.0*I3 0.01*I3 2 * * * REF Is, applied to H impedance

GROUP 1

RESIDUAL O/V NVD

VN Input 01 Indexed String G49 41550 G49 Measured Setting 0 1 1 2 * * *

VN>1 Function 02 Indexed String G23 41551 G23 DT Setting 0 2 1 2 * * *

** *3B 00

V3 applied when 3A5A=0, V1 applied when 3A5A=1

V3 applied when 3A5A=0, V1 applied when 3A5A=1

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VN>1 Voltage Set 03 Courier Number (Voltage) 41552 G2 5 Setting 1*V1 50*V1 1*V1 2 * * *1*V3 50*V3 1*V3 Change scaling factor

VN>1 Time Delay 04 Courier Number (Time) 41553 G2 5 Setting 0 100 0.01 2 * * *

VN>1 TMS 05 Courier Number (Decimal) 41554 G2 1 Setting 0.5 100 0.5 2 * * *

VN>1 tReset 06 Courier Number (Time) 41555 G2 0 Setting 0 100 0.01 2 * * *

VN>2 Status 07 Indexed String G37 41556 G37 Disabled Setting 0 1 1 2 * * *VN>2 Voltage Set 08 Courier Number (Voltage) 41557 G2 10 Setting 1*V1 50*V1 1*V1 2 * * *

1*V3 50*V3 1*V3 Change scaling factor

VN>2 Time Delay 09 Courier Number (Time) 41558 G2 10 Setting 0 100 0.01 2 * * *

GROUP 1

100% STATOR EF

100%St EF Status 01 Indexed String G112 41600 G112 1 (Undervoltage) Setting 0 2 1 2 *

100% St EF VN3H< 02 Courier Number (Voltage) 41601 G2 1 Setting 0.3*V3 20*V3 0.1*V3 2 *

VN3H< Delay 03 Courier Number (Time) 41602 G2 5 Setting 0 100 0.01 2 *

V<Inhibit set 04 Courier Number (Voltage) 41603 G2 80 Setting 30*V1 120*V1 1*V1 2 *

P< Inhibit 05 Indexed String G37 41604 G37 Disabled Setting 0 1 1 2 *

P<Inhibit set 06 Courier Number (Power) 41605 G2 4 Setting 4*V1*I1 200*V1*I1 0.5*V1*I1 2 *

Q< Inhibit 07 Indexed String G37 41606 G37 Disabled Setting 0 1 1 2 *

Q<Inhibit set 08 Courier Number (VAr) 41607 G2 4 Setting 4*V1*I1 200*V1*I1 0.5*V1*I1 2 *

S< Inhibit 09 Indexed String G37 41608 G37 Disabled Setting 0 1 1 2 *

S<Inhibit set 0A Courier Number (VA) 41609 G2 4 Setting 4*V1*I1 200*V1*I1 0.5*V1*I1 2 *

100% St EF VN3H> 0B Courier Number (Voltage) 41610 G2 1 Setting 0.3*V3 20*V3 0.1*V3 2 *

VN3H> Delay 0C Courier Number (Time) 41611 G2 5 Setting 0 100 0.01 2 *

GROUP 1

VOLTS/HZ

V/Hz Alm Status 01 Indexed String G37 41650 G37 Enabled Setting 0 1 1 2 * *

V/Hz Alarm Set 02 Courier Number (Volts/Hz) 41651 G2 2.31 Setting 1.5*V1 3.5*V1 0.01*V1 2 * *

V/Hz Alarm Delay 03 Courier Number (Time) 41652 G2 10 Setting 0 100 0.01 2 * *

V/Hz Trip Func 04 Indexed String G23 41653 G23 DT Setting 0 2 1 2 * *

V/Hz Trip Set 05 Courier Number (Volts/Hz) 41654 G2 2.42 Setting 1.5*V1 3.5*V1 0.01*V1 2 * *

V/Hz Trip TMS 06 Courier Number (Decimal) 41655 G2 1 Setting 1 63 1 2 * *

V/Hz Trip Delay 07 Courier Number (Time) 41656 G2 1 Setting 0 100 0.01 2 * *

GROUP 1

DF/DT

df/dt Status 01 Indexed String G37 41700 G37 Enabled Setting 0 1 1 2 *

df/dt Setting 02 Courier Number (Hz/s) 41701 G2 0.2 Setting 0.1 10 0.01 2 *

df/dt Time Delay 03 Courier Number (Time) 41702 G2 0.5 Setting 0 100 0.01 2 *

df/dt f Low 04 Courier Number (Frequency) 41703 G2 49.5 Setting 45 65 0.01 2 *

df/dt f High 05 Courier Number (Frequency) 41704 G2 50.5 Setting 45 65 0.01 2 *

GROUP 1

V VECTOR SHIFT

V Shift Status 01 Indexed String G37 41750 G37 Enabled Setting 0 1 1 2 *

*3F 00

*

*

3E 00

*

*

3D 00

3C 00

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V Shift Angle 02 Courier Number (Angle) 41751 G2 10 Setting 2 30 1 2 *

GROUP 1

DEAD MACHINE

Dead Mach Status 01 Indexed String G37 41800 G37 Disabled Setting 0 1 1 2 *

Dead Mach I> 02 Courier Number (Current) 41801 G2 0.1 Setting 0.08*I1 4*I1 0.01*I1 2 *

Dead Mach V< 03 Courier Number (Voltage) 41802 G2 80 Setting 10*V1 120*V1 1*V1 2 *

Dead Mach tPU 04 Courier Number (Time) 41803 G2 5 Setting 0 10 0.1 2 *

Dead Mach tDO 05 Courier Number (Time) 41804 G2 0.5 Setting 0 10 0.1 2 *

GROUP 1

RECONNECT DELAY

Reconnect Status 01 Indexed String G37 41850 G37 Enabled Setting 0 1 1 2 *

Reconnect Delay 02 Courier Number (Time) 41852 G2 60 Setting 0 300 0.01 2 *

Reconnect tPULSE 03 Courier Number (Time) 41853 G2 1 Setting 0.01 30 0.01 2 *

Modbus addresses 41900-41931 assigned for CLIO labels

GROUP 1

VOLT PROTECTION

UNDER VOLTAGE 01 (Sub Heading) * * *

V< Measur't Mode 02 Indexed String G47 41950 G47 Phase-Neutral Setting 0 1 1 2 * * *

V< Operate Mode 03 Indexed String G48 41951 G48 Any Phase Setting 0 1 1 2 * * *

V<1 Function 04 Indexed String G23 41952 G23 DT Setting 0 2 1 2 * * *

V<1 Voltage Set 05 Courier Number (Voltage) 41953 G2 50 Setting 10*V1 120*V1 1*V1 2 * * * Range covers Ph-N & Ph-Ph

V<1 Time Delay 06 Courier Number (Time) 41954 G2 10 Setting 0 100 0.01 2 * * *

V<1 TMS 07 Courier Number (Decimal) 41955 G2 1 Setting 0.5 100 0.5 2 * * *

V<1 Poledead Inh 08 Indexed String G37 41956 G37 Enabled Setting 0 1 1 2 * * *

V<2 Status 09 Indexed String G37 41957 G37 Disabled Setting 0 1 1 2 * * *

V<2 Voltage Set 0A Courier Number (Voltage) 41958 G2 38 Setting 10*V1 120*V1 1*V1 2 * * * Range covers Ph-N & Ph-Ph

V<2 Time Delay 0B Courier Number (Time) 41959 G2 5 Setting 0 100 0.01 2 * * *

V<2 Poledead Inh 0C Indexed String G37 41960 G37 Enabled Setting 0 1 1 2 * * *

OVERVOLTAGE 0D (Sub Heading) * * *

V> Measur't Mode 0E Indexed String G47 41961 G47 Phase-Phase Setting 0 1 1 2 * * *

V> Operate Mode 0F Indexed String G48 41962 G48 Any Phase Setting 0 1 1 2 * * *

V>1 Function 10 Indexed String G23 41963 G23 DT Setting 0 2 1 2 * * *

V>1 Voltage Set 11 Courier Number (Voltage) 41964 G2 130 Setting 60*V1 185*V1 1*V1 2 * * *

V>1 Time Delay 12 Courier Number (Time) 41965 G2 10 Setting 0 100 0.01 2 * * *

V>1 TMS 13 Courier Number (Decimal) 41966 G2 1 Setting 0.5 100 0.5 2 * * *

V>2 Status 14 Indexed String G37 41967 G37 Disabled Setting 0 1 1 2 * * *

V>2 Voltage Set 15 Courier Number (Voltage) 41968 G2 150 Setting 60*V1 185*V1 1*V1 2 * * *

V>2 Time Delay 16 Courier Number (Time) 41969 G2 0.5 Setting 0 100 0.01 2 * * *

GROUP 1

FREQ PROTECTION

UNDER FREQUENCY 01 (Sub Heading) * * *

F<1 Status 02 Indexed String G37 42000 G37 Enabled Setting 0 1 1 2 * * *

F<1 Setting 03 Courier Number (Frequency) 42001 G2 49.5 Setting 45 65 0.01 2 * * *

F<1 Time Delay 04 Courier Number (Time) 42002 G2 4 Setting 0 100 0.01 2 * * *

F<2 Status 05 Indexed String G37 42003 G37 Disabled Setting 0 1 1 2 * * *

** *

*

43 00

* *42 00

*

*

41 00

40 00

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F<2 Setting 06 Courier Number (Frequency) 42004 G2 49 Setting 45 65 0.01 2 * * *

F<2 Time Delay 07 Courier Number (Time) 42005 G2 3 Setting 0 100 0.01 2 * * *

F<3 Status 08 Indexed String G37 42006 G37 Disabled Setting 0 1 1 2 * * *

F<3 Setting 09 Courier Number (Frequency) 42007 G2 48.5 Setting 45 65 0.01 2 * * *

F<3 Time Delay 0A Courier Number (Time) 42008 G2 2 Setting 0 100 0.01 2 * * *

F<4 Status 0B Indexed String G37 42009 G37 Disabled Setting 0 1 1 2 * * *

F<4 Setting 0C Courier Number (Frequency) 42010 G2 48 Setting 45 65 0.01 2 * * *

F<4 Time Delay 0D Courier Number (Time) 42011 G2 1 Setting 0 100 0.01 2 * * *

F< Function Link 0E Binary Flag (4 bits) G65 42012 G65 16 Setting 15 4 1 2 * * *

OVER FREQUENCY 0F (Sub Heading) * * *

F>1 Status 10 Indexed String G37 42013 G37 Enabled Setting 0 1 1 2 * * *

F>1 Setting 11 Courier Number (Frequency) 42014 G2 50.5 Setting 45 68 0.01 2 * * *

F>1 Time Delay 12 Courier Number (Time) 42015 G2 2 Setting 0 100 0.01 2 * * *

F>2 Status 13 Indexed String G37 42016 G37 Disabled Setting 0 1 1 2 * * *

F>2 Setting 14 Courier Number (Frequency) 42017 G2 51 Setting 45 68 0.01 2 * * *

F>2 Time Delay 15 Courier Number (Time) 42018 G2 1 Setting 0 100 0.01 2 * * *

GROUP 1

RTD PROTECTION

Select RTD 01 Binary Flags(10 bits)Indexed String G50 42053 G50 0 Setting 1023 10 1 2 * *

RTD 1 Alarm Set 02 Courier Number (Temperature) 42054 G1 80 Setting 0 200 1 2 * *

RTD 1 Alarm Dly 03 Courier Number (Time) 42055 G1 10 Setting 0 100 1 2 * *

RTD 1 Trip Set 04 Courier Number (Temperature) 42056 G1 85 Setting 0 200 1 2 * *

RTD 1 Trip Dly 05 Courier Number (Time) 42057 G1 1 Setting 0 100 1 2 * *





RTD 3 Alarm Set 0A Courier Number (Temperature) 42062 G1 80 Setting 0 200 1 2 * *

RTD 3 Alarm Dly 0B Courier Number (Time) 42063 G1 10 Setting 0 100 1 2 * *

RTD 3 Trip Set 0C Courier Number (Temperature) 42064 G1 85 Setting 0 200 1 2 * *

RTD 3 Trip Dly 0D Courier Number (Time) 42065 G1 1 Setting 0 100 1 2 * *

RTD 4 Alarm Set 0E Courier Number (Temperature) 42066 G1 80 Setting 0 200 1 2 * *

RTD 4 Alarm Dly 0F Courier Number (Time) 42067 G1 10 Setting 0 100 1 2 * *











RTD 7 Alarm Set 1A Courier Number (Temperature) 42078 G1 80 Setting 0 200 1 2 * *

RTD 7 Alarm Dly 1B Courier Number (Time) 42079 G1 10 Setting 0 100 1 2 * *

RTD 7 Trip Set 1C Courier Number (Temperature) 42080 G1 85 Setting 0 200 1 2 * *

**44 00

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RTD 7 Trip Dly 1D Courier Number (Time) 42081 G1 1 Setting 0 100 1 2 * *

RTD 8 Alarm Set 1E Courier Number (Temperature) 42082 G1 80 Setting 0 200 1 2 * *

RTD 8 Alarm Dly 1F Courier Number (Time) 42083 G1 10 Setting 0 100 1 2 * *











GROUP 1

CB FAIL & I<

BREAKER FAIL 01 (Sub Heading) * * *

CB Fail 1 Status 02 Indexed String G37 42100 G37 Enabled Setting 0 1 1 2 * * *

CB Fail 1 Timer 03 Courier Number (Time) 42101 G2 0.2 Setting 0 10 0.01 2 * * *

CB Fail 2 Status 04 Indexed String G37 42102 G37 Disabled Setting 0 1 1 2 * * *

CB Fail 2 Timer 05 Courier Number (Time) 42103 G2 0.4 Setting 0 10 0.01 2 * * *

CBF Non I Reset 06 Indexed String G68 42104 G68 CB Open & I< Setting 0 2 1 2 * * *

CBF Ext Reset 07 Indexed String G68 42105 G68 CB Open & I< Setting 0 2 1 2 * * *

UNDER CURRENT 08 (Sub Heading) * * *

I< Current Set 09 Courier Number (Current) 42106 G2 0.1 Setting 0.02*I1 3.2*I1 0.01*I1 2 * * *

IN< Current Set 0A Courier Number (Current) 42107 G2 0.1 Setting 0.02*I2 3.2*I2 0.01*I2 2 * * P341 does not have IN input

ISEF< Current 0B Courier Number (Current) 42108 G2 0.02 Setting 0.001*I3 0.8*I3 0.0005*I3 2 * * *

BLOCKED O/C 0C (Sub Heading) * Blocked Overcurrent Schemes

Remove I> Start 0D Indexed String G37 42109 G37 Disabled Setting 0 1 1 2 *

Remove IN> Start 0E Indexed String G37 42110 G37 Disabled Setting 0 1 1 2 *

I< Current Input 15 Indexed String G116 42111 G116 IA-1, IB-1, IC-1 Setting 0 1 1 2 *

GROUP 1

SUPERVISION

VT SUPERVISION 01 (Sub Heading) * * *

VTS Status 02 Indexed String G7 42150 G7 Blocking Setting 0 1 1 2 * * *

VTS Reset Mode 03 Indexed String G69 42151 G69 Manual Setting 0 1 1 2 * * *

VTS Time Delay 04 Courier Number (Time) 42152 G2 5 Setting 1 10 0.1 2 * * *

VTS I> Inhibit 05 Courier Number (Current) 42153 G2 10 Setting 0.08*I1 32*I1 0.01*I1 2 * * *

VTS I2> Inhibit 06 Courier Number (Current) 42154 G2 0.05 Setting 0.05*I1 0.5*I1 0.01*I1 2 * * *

CT SUPERVISION 07 (Sub Heading) * * *

CTS Status 08 Indexed String G37 42155 G37 Disabled Setting 0 1 1 2 * * *

CTS VN Input 09 Indexed String G49 42156 G49 Derived Setting 0 1 1 2 * * *CTS VN< Inhibit 0A Courier Number (Voltage) 42157 G2 5 Setting 0.5*V1 22*V1 0.5*V1 2 * * *

0.5*V3 22*V3 0.5*V3 Change scaling factor

CTS IN> Set 0B Courier Number (Current) 42158 G2 0.2 Setting 0.08*I1 4*I1 0.01*I1 2 * * *

** *

*

46 00

* *45 00

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CTS Time Delay 0C Courier Number (Time) 42159 G2 5 Setting 0 10 1 2 * * *

GROUP 1

SENSITIVE POWER

Comp Angle 20 Courier Number (Angle) 42175 G2 0 Setting -5 5 0.1 2 * * *

Operating Mode 24 Indexed String G115 42190 G115 Generating Setting 0 1 1 2 * * *

Sen Power1 Func 28 Indexed String G102 42176 G102 Reverse Setting 0 3 1 2 * * *

Sen -P>1 Setting 2C Courier Number (Power) 42177 G2 0.5*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen P<1 Setting 30 Courier Number (Power) 42178 G2 0.5*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen P>1 Setting 34 Courier Number (Power) 42179 G2 50*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen Power1 Delay 38 Courier Number (Time) 42180 G2 5 Setting 0 100 0.01 2 * * *

Power1 DO Timer 3C Courier Number (Time) 42181 G2 0 Setting 0 100 0.01 2 * * *

P1 PoleDead Inh 40 Indexed String G37 42182 G37 Enabled Setting 0 1 1 2 * * *

Sen Power2 Func 44 Indexed String G102 42183 G102 Low Forward Setting 0 3 1 2 * * *

Sen -P>2 Setting 48 Courier Number (Power) 42184 G2 0.5*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen P<2 Setting 4C Courier Number (Power) 42185 G2 0.5*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen P>2 Setting 50 Courier Number (Power) 42186 G2 50*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen Power2 Delay 54 Courier Number (Time) 42187 G2 2 Setting 0 100 0.01 2 * * *


P2 PoleDead Inh 5C Indexed String G37 42189 G37 Enabled Setting 0 1 1 2 * * *

GROUP 1

NOT USED

GROUP 1

POLE SLIPPING

PSlip Function 01 Indexed String G37 42250 G37 Enabled Setting 0 1 1 2 *

Z Based PoleSlip 02 (Sub Heading) *

Pole Slip Mode 03 Indexed String G113 42251 G113 Generating Setting 0 2 1 2 *

PSlip Za Forward 04 Courier Number (Impedance) 42252 G2 100*V1/I1 Setting 0.5*V1/I1 350*V1/I1 0.5*V1/I1 2 *

PSlip Zb Reverse 05 Courier Number (Impedance) 42253 G2 150*V1/I1 Setting 0.5*V1/I1 350*V1/I1 0.5*V1/I1 2 *

Lens Angle 06 Courier Number (Angle) 42254 G2 120 Setting 90 150 1 2 *

PSlip Timer T1 07 Courier Number (Time) 42255 G2 0.015 Setting 0 1 0.005 2 *

PSlip Timer T2 08 Courier Number (Time) 42256 G2 0.015 Setting 0 1 0.005 2 *

Blinder Angle 09 Courier Number (Angle) 42257 G2 75 Setting 20 90 1 2 *

PSlip Zc 0A Courier Number (Impedance) 42258 G2 50*V1/I1 Setting 0.5*V1/I1 350*V1/I1 0.5*V1/I1 2 *

Zone1 Slip Count 0B Unsigned Integer 42259 G1 1 Setting 1 20 1 2 *

Zone2 Slip Count 0C Unsigned Integer 42260 G1 2 Setting 1 20 1 2 *

PSlip Reset Time 0D Courier Number (Time) 42261 G2 30 Setting 0 100 0.01 2 *

GROUP 1

INPUT LABELS

Opto Input 1 01 ASCII Text (16 chars) 42300 42307 G3 L1 Setting Group Setting 32 163 1 2 * * *

Opto Input 2 02 ASCII Text (16 chars) 42308 42315 G3 L2 Setting Group Setting 32 163 1 2 * * *Opto Input 3 03 ASCII Text (16 chars) 42316 42323 G3 L3 Block IN>3&4 Setting 32 163 1 2 *

L3 Block IN>2 * *Opto Input 4 04 ASCII Text (16 chars) 42324 42331 G3 L4 Block I>3&4 Setting 32 163 1 2 *

L4 Block I>2 * *

Opto Input 5 05 ASCII Text (16 chars) 42332 42339 G3 L5 Reset Setting 32 163 1 2 * * *

Opto Input 6 06 ASCII Text (16 chars) 42340 42347 G3 L6 Ext Prot Trip Setting 32 163 1 2 * * *

** *

*

4A 00

49 00

*

48 00

* *47 00

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Opto Input 7 07 ASCII Text (16 chars) 42348 42355 G3 L7 52a Setting 32 163 1 2 * * *

Opto Input 8 08 ASCII Text (16 chars) 42356 42363 G3 L8 52b Setting 32 163 1 2 * * *

Opto Input 9 09 ASCII Text (16 chars) 42364 42371 G3 L9 Not Used Setting 32 163 1 2 * * *

Opto Input 10 0A ASCII Text (16 chars) 42372 42379 G3 L10 Not Used Setting 32 163 1 2 * * *

Opto Input 11 0B ASCII Text (16 chars) 42380 42387 G3 L11 Not Used Setting 32 163 1 2 * * *

Opto Input 12 0C ASCII Text (16 chars) 42388 42395 G3 L12 Not Used Setting 32 163 1 2 * * *

Opto Input 13 0D ASCII Text (16 chars) 42396 42403 G3 L13 Not Used Setting 32 163 1 2 * * *

Opto Input 14 0E ASCII Text (16 chars) 42404 42411 G3 L14 Not Used Setting 32 163 1 2 * * *

Opto Input 15 0F ASCII Text (16 chars) 42412 42419 G3 L15 Not Used Setting 32 163 1 2 * * *










Opto Input 25 19 ASCII Text (16 chars) 42492 42499 G3 L25 Not Used Setting 32 163 1 2 *

Opto Input 26 1A ASCII Text (16 chars) 42500 42507 G3 L26 Not Used Setting 32 163 1 2 *

Opto Input 27 1B ASCII Text (16 chars) 42508 42515 G3 L27 Not Used Setting 32 163 1 2 *

Opto Input 28 1C ASCII Text (16 chars) 42516 42523 G3 L28 Not Used Setting 32 163 1 2 *

Opto Input 29 1D ASCII Text (16 chars) 42524 42531 G3 L29 Not Used Setting 32 163 1 2 *

Opto Input 30 1E ASCII Text (16 chars) 42532 42539 G3 L30 Not Used Setting 32 163 1 2 *

Opto Input 31 1F ASCII Text (16 chars) 42540 42547 G3 L31 Not Used Setting 32 163 1 2 *Opto Input 32 20 ASCII Text (16 chars) 42548 42555 G3 L32 Not Used Setting 32 163 1 2 *GROUP 1

OUTPUT LABELSRelay 1 01 ASCII Text (16 chars) 42556 42563 G3 R1 IN>1 Start Setting 32 163 1 2 * * *

R1 Trip CBRelay 2 02 ASCII Text (16 chars) 42564 42571 G3 R2 I>1 Start Setting 32 163 1 2 * * *

R2 Trip PrimeMov

Relay 3 03 ASCII Text (16 chars) 42572 42579 G3 R3 Any Trip Setting 32 163 1 2 * * *

Relay 4 04 ASCII Text (16 chars) 42580 42587 G3 R4 General Alarm Setting 32 163 1 2 * * *

Relay 5 05 ASCII Text (16 chars) 42588 42595 G3 R5 CB Fail Setting 32 163 1 2 * * *Relay 6 06 ASCII Text (16 chars) 42596 42603 G3 R6 Control Close Setting 32 163 1 2 *

R6 E/F Trip * *Relay 7 07 ASCII Text (16 chars) 42604 42611 G3 R7 Control Trip Setting 32 163 1 2 *

R7 V or F Trip *R7 Volt Trip *

Relay 8 08 ASCII Text (16 chars) 42612 42619 G3 R8 Not Used Setting 32 163 1 2 * *R8 Freq Trip *

Relay 9 09 ASCII Text (16 chars) 42620 42627 G3 R9 Not Used Setting 32 163 1 2 * *R9 Diff Trip *

Relay 10 0A ASCII Text (16 chars) 42628 42635 G3 R10 Not Used Setting 32 163 1 2 * *R10 SysBack Trip *

** *4B 00

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Relay 11 0B ASCII Text (16 chars) 42636 42643 G3 R11 Not Used Setting 32 163 1 2 * *R11 NPS Trip *

Relay 12 0C ASCII Text (16 chars) 42644 42651 G3 R12 Not Used Setting 32 163 1 2 * *R12 Ffail Trip *

Relay 13 0D ASCII Text (16 chars) 42652 42659 G3 R13 Not Used Setting 32 163 1 2 * *R13 Power Trip *

Relay 14 0E ASCII Text (16 chars) 42660 42667 G3 R14 Not Used Setting 32 163 1 2 * *R14 V/Hz Trip *

Relay 15 0F ASCII Text (16 chars) 42668 42675 G3 R15 Not Used Setting 32 163 1 2 * * *

Relay 16 10 ASCII Text (16 chars) 42676 42683 G3 R16 Not Used Setting 32 163 1 2 * * *









Relay 25 19 ASCII Text (16 chars) 42748 42755 G3 R25 Not Used Setting 32 163 1 2 *

Relay 26 1A ASCII Text (16 chars) 42756 42763 G3 R26 Not Used Setting 32 163 1 2 *

Relay 27 1B ASCII Text (16 chars) 42764 42771 G3 R27 Not Used Setting 32 163 1 2 *

Relay 28 1C ASCII Text (16 chars) 42772 42779 G3 R28 Not Used Setting 32 163 1 2 *

Relay 29 1D ASCII Text (16 chars) 42780 42787 G3 R29 Not Used Setting 32 163 1 2 *

Relay 30 1E ASCII Text (16 chars) 42788 42795 G3 R30 Not Used Setting 32 163 1 2 *

Relay 31 1F ASCII Text (16 chars) 42796 42803 G3 R31 Not Used Setting 32 163 1 2 *

Relay 32 20 ASCII Text (16 chars) 42804 42811 G3 R32 Not Used Setting 32 163 1 2 *

GROUP 1

RTD LABELS

RTD 1 01 ASCII Text (16 chars) 42812 42819 G3 RTD 1 Setting 32 163 1 2 * *









RTD 10 0A ASCII Text (16 chars) 42884 42891 G3 RTD 10 Setting 32 163 1 2 * *

GROUP 1

CLIO PROTECTION

CLIO Input 1 02 Indexed String G37 42895 G37 Enabled Setting 0 1 1 2 * * *

CLI1 Input Type 04 Indexed String G153 42896 G153 4-20mA Setting 0 3 1 2 * * *

CLI1 Input Label 06 ASCII Text (16 chars) 41900 41907 G3 CLIO Input 1 Setting 32 163 1 2 * * *

CLI1 Minimum 08 Courier Number (Decimal) 42897 42898 G35 0 Setting -9999 9999 0.1 2 * * *

CLI1 Maximum 0A Courier Number (Decimal) 42899 42900 G35 100 Setting -9999 9999 0.1 2 * * *

** *

*

4D 00

*4C 00

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CLI1 Alarm 0C Indexed String G37 42901 G37 Disabled Setting 0 1 1 2 * * *

CLI1 Alarm Fn 0E Indexed String G154 42902 G154 Over Setting 0 1 1 2 * * *CLI1 Alarm Set 10 Courier Number (Decimal) 42903 42904 G35 50 Setting MIN(CLI1 MAX(CLI1 0.1 2 * * *

Min, Max) Min, Max)

CLI1 Alarm Delay 12 Courier Number (Time) 42905 G2 1 Setting 0 100 0.1 2 * * *

CLI1 Trip 14 Indexed String G37 42906 G37 Disabled Setting 0 1 1 2 * * *

CLI1 Trip Fn 16 Indexed String G154 42907 G154 Over Setting 0 1 1 2 * * *CLI1 Trip Set 18 Courier Number (Decimal) 42908 42909 G35 60 Setting MIN(CLI1 MAX(CLI1 0.1 2 * * *

Min, Max) Min, Max)

CLI1 Trip Delay 1A Courier Number (Time) 42910 G2 0 Setting 0 100 0.1 2 * * *

CLI1 I< Alarm 1C Indexed String G37 42911 G37 Disabled Setting 0 1 1 2 * * * Visible only when 4D04 = 4-20mA

CLI1 I< Alm Set 1E Courier Number (Current) 42912 G2 0.0035 Setting 0 0.004 0.0001 2 * * * Visible only when 4D04 = 4-20mA








Min, Max) Min, Max)

CLI2 Alarm Delay 32 Courier Number (Time) 42923 G2 1s Setting 0 100 0.1 2 * * *



Min, Max) Min, Max)

CLI2 Trip Delay 3A Courier Number (Time) 42928 G2 0s Setting 0 100 0.1 2 * * *

CLI2 I< Alarm 3C Indexed String G37 42929 G37 Disabled Setting 0 1 1 2 * * * Visible only when 4D24=4-20mA

CLI2 I< Alm Set 3E Courier Number (Current) 42930 G2 0.0035 Setting 0 0.004 0.0001 2 * * * Visible only when 4D24=4-20mA








Min, Max) Min, Max)




Min, Max) Min, Max)



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Min, Max) Min, Max)




Min, Max) Min, Max)




CLIO Output 1 A0 Indexed String G37 42967 G37 Disabled Setting 0 1 1 2 * * *

CLO1 Output Type A2 Indexed String G153 42968 G153 4-20mA Setting 0 2 1 2 * * *

CLO1 Set Values A4 Indexed String G54 42969 G54 Primary Setting 0 1 1 2 * * *CLO1 Parameter A6 Indexed String G155 42970 G155 IA Magnitude Setting 0 See 1 2 * * *

G155

CLO1 Minimum A8 Courier Number 42971 42972 G35 See G155 table Setting 2 * * *

CLO1 Maximum AA Courier Number 42973 42974 G35 See G155 table Setting 2 * * *

CLIO Output 2 B0 Indexed String G37 42975 G37 Disabled Setting 0 1 1 2 * * *

CLO2 Output Type B2 Indexed String G153 42976 G153 4-20mA Setting 0 2 1 2 * * *

CLO2 Set Values B4 Indexed String G54 42977 G54 Primary Setting 0 1 1 2 * * *CLO2 Parameter B6 Indexed String G155 42978 G155 IB Magnitude Setting 0 See 1 2 * * *

G155

CLO2 Minimum B8 Courier Number 42979 42980 G35 See G155 table Setting 2 * * *

CLO2 Maximum BA Courier Number 42981 42982 G35 See G155 table Setting 2 * * *

CLIO Output 3 C0 Indexed String G37 42983 G37 Disabled Setting 0 1 1 2 * * *

CLO3 Output Type C2 Indexed String G153 42984 G153 4-20mA Setting 2 * * *

CLO3 Set Values C4 Indexed String G54 42985 G54 Primary Setting 2 * * *CLO3 Parameter C6 Indexed String G155 42986 G155 IC Magnitude Setting 0 See 1 2 * * *

G155

CLO3 Minimum C8 Courier Number 42987 42988 G35 See G155 Table Setting 2 * * *

CLO3 Maximum CA Courier Number 42989 42990 G35 See G155 Table Setting 2 * * *

CLIO Output 4 D0 Indexed String G37 42991 G37 Disabled Setting 2 * * *

CLO4 Output Type D2 Indexed String G153 42992 G153 4-20mA Setting 2 * * *

CLO4 Set Values D4 Indexed String G54 42993 G54 Primary Setting 2 * * *CLO4 Parameter D6 Indexed String G155 42994 G155 IN Measured Mag Setting 0 See 1 2 * *

IN Derived Mag G155 *

CLO4 Minimum D8 Courier Number 42995 42996 G35 See G155 Table Setting 2 * * *

See G155 Meas. Range Table


0

0






0

0

0

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CLO4 Maximum DA Courier Number 42997 42998 G35 See G155 Table Setting 2 * * *

GROUP 2 PROTECTION SETTINGS * * *Repeat of Group 1 columns/rows 50 00 43000 44999 * * *



(No Header) N/A B0 00 Auto extraction Event Record Column * * *

Select Record 01 Unsigned Integer(2) Setting 0 65535 1 * * * Unique cyclical fault number(from event)

Faulted Phase 02 Binary Flag (8 bits) Indexed String G16 Data * * * Product Specific Bit Flags Targetting

Start Elements1 03 Binary Flag (32 Bits)Indexed String 0..31 G841 bit per elementLSB

String..MSB StringData * * * Product Specific Bit Flags Targetting

Start Elements2 04 Binary Flag (32 Bits)Indexed String 0..31 G1071 bit per elementLSB

String..MSB StringData * * *

Trip Elements1 05 Binary Flag (32 Bits)Indexed String 0..31 G851 bit per elementLSB


Trip Elements2 06 Binary Flag (32 Bits)Indexed String 0..31 G861 bit per elementLSB


Fault Alarms 07 Binary Flag (32 Bits)Indexed String 0..31 G871 bit per elementLSB


Fault Time 08 IEC870 Time & Date Data * * *

Active Group 09 Unsigned Integer Data * * *

System Frequency 0A Courier Number (frequency) Data * * *

Fault Duration 0B Courier Number (time) Data * * *

CB Operate Time 0C Courier Number (time) Data * * *

Relay Trip Time 0D Courier Number (time) Data * * *

IA 0E Courier Number (current) Data * *

IA-1 0E Courier Number (current) Data *

IB 0F Courier Number (current) Data * *

IB-1 0F Courier Number (current) Data *

IC 10 Courier Number (current) Data * *

IC-1 10 Courier Number (current) Data *

VAB 11 Courier Number (voltage) Data * * *

VBC 12 Courier Number (voltage) Data * * *

VCA 13 Courier Number (voltage) Data * * *

VAN 14 Courier Number (voltage) Data * * *

VBN 15 Courier Number (voltage) Data * * *

VCN 16 Courier Number (voltage) Data * * *

IA-2 17 Courier Number (current) Data *

IB-2 18 Courier Number (current) Data *

IC-2 19 Courier Number (current) Data *

IA Differential 1A Courier Number (Current) Data *

IB Differential 1B Courier Number (Current) Data *

IC Differential 1C Courier Number (Current) Data *

VN Measured 1D Courier Number (Voltage) Data * * *


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VN Derived 1E Courier Number (Voltage) Data * * *

IN Measured 1F Courier Number (Voltage) Data * *

IN Derived 1F Courier Number (Current) Data *

I Sensitive 20 Courier Number (Current) Data * * *

IREF Diff 21 Courier Number (Current) Data * *

IREF Bias 22 Courier Number (Current) Data * *

I2 23 Courier Number (Current) Data * *

3 Phase Watts 24 Courier Number (Watts) Data * * *

3 Phase VARs 25 Courier Number (VARs) Data * * *

3 Phase Power Factor 26 Courier Number (No unit) Data * * *

RTD 1 27 Courier Number (Temperature) Data * * Courier Text = RTD label setting



RTD 4 2A Courier Number (Temperature) Data * * Courier Text = RTD label setting

RTD 5 2B Courier Number (Temperature) Data * * Courier Text = RTD label setting

RTD 6 2C Courier Number (Temperature) Data * * Courier Text = RTD label setting

RTD 7 2D Courier Number (Temperature) Data * * Courier Text = RTD label setting

RTD 8 2E Courier Number (Temperature) Data * * Courier Text = RTD label setting

RTD 9 2F Courier Number (Temperature) Data * * Courier Text = RTD label setting


df/dt 31 Courier Number (Hz/s) Data *

V Vector Shift 32 Courier Number (Angle) Data *

CLIO Input 1 33 Courier Number (Decimal) Data * * * Courier Text = CLIO label setting




No Header N/A B1 00 * * *

Select Record 01 UINT16 Setting 0 65535 1 * * *

Time and Date 02 IEC Date and Time Data * * *

Record Text 03 ASCII Text Data * * * Text Description of Error

Error No1 04 UINT32 Data * * * Error Code

Error No2 05 UINT32 Data * * * Error Code

DATA TRANSFER N/A B2 00

Domain 04 Indexed String G57 PSL Settings Setting 0 1 1 2 * * *

Sub-Domain 08 Indexed String G90 Group 1 Setting 0 3 1 2 * * *

Version 0C Unsigned Integer (2 Bytes) 256 Setting 0 65535 1 2 * * *

Start 10 Not Used * * *

Length 14 Not Used * * *

Data Transfer Reference 18 * * *

Transfer Mode 1C Unsigned Integer Indexed Strings G76 6 Setting 0 7 1 2 * * *

Data Transfer 20 Repeated groups of Unsigned Integers Setting * * * Only settable if Domain = PSL Settings

RECORDER CONTROL N/A B3 00 * * *

UNUSED 01 * * *

Recorder Source 02 Indexed String Samples Data * * *

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Reserved for future use 03-1F * * *

RECORDER EXTRACTION COLUMN

N/A B4 00 * * *

Select Record 01 Unsigned Integer 0 Setting -199 199 1 0 * * *

Trigger Time 02 IEC870 Time & Date Data * * *

Active Channels 03 Binary Flag Data * * * Build=IEC60870-5-103

Channel Types 04 Binary Flag Data * * * Build=IEC60870-5-103

Channel Offsets 05 Courier Number (decimal) Data * * * Build=IEC60870-5-103

Channel Scaling 06 Courier Number (decimal) Data * * * Build=IEC60870-5-103

Channel SkewVal 07 Integer Data * * * Build=IEC60870-5-103

Channel MinVal 08 Integer Data * * * Build=IEC60870-5-103

Channel MaxVal 09 Integer Data * * * Build=IEC60870-5-103

Format 0A Unsigned Integer Data * * * 0 = uncompressed, 1 = compressed

Upload 0B Unsigned Integer Data * * * Unused when Build=IEC60870-5-103

UNUSED 0C-0F

No. Of Samples 10 Unsigned Integer Data * * * Build=IEC60870-5-103

Trig Position 11 Unsigned Integer Data * * * Build=IEC60870-5-103

Time Base 12 Courier Number (time) Data * * * Build=IEC60870-5-103

UNUSED 13

Sample Timer 14 Unsigned Integer Data * * * Build=IEC60870-5-103

UNUSED 15-1F

Dist. Channel 1 20 Integer Data * * * Build=IEC60870-5-103










Dist. Channel 11 2A Integer Data * * * Build=IEC60870-5-103

Dist. Channel 12 2B Integer Data * * * Build=IEC60870-5-103

Dist. Channel 13 2C Integer Data * * * Build=IEC60870-5-103

UNUSED 2D-3D

Dist. Channel 31 3E Binary Flag Data * * * Build=IEC60870-5-103

Dist. Channel 32 3F Binary Flag Data * * * Build=IEC60870-5-103

30800 G1 Data Number of Disturbance Records (0 to 200)

30801 G1 Data Oldest Stored Disturbance Record (1 to 65535)

30802 G1 Data Number of Registers in Current Page

30803 30929 G1 Data Disturbance Record Page (0 to 65535)

40250 G1 Setting 1 65535 1 2 Select Disturbance Record

30930 30933 G12 Data Timestamp of selected record

Calibration Coefficients N/A B5 * * *

Cal Soft Version 01 ASCII text 16 chars * * *

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Cal Date and Time 02 IEC Date and time * * *

Channel Types 03 Repeated Group 16 * Binary Flag 8 bits * * *

Cal Coeffs 04 Block transfer Repeated Group of UINT32 (4 coeffs voltage channel, 8 coeffs current channel) * * *

Comms Diagnostics N/A B6 00 Note: No text in column text * * *

Bus Comms Err Count Front 01 UINT32 * * *

02 UINT32 * * *

Protocol Err Count Front 03 UINT32 * * *

Slave Message Count Front 04 UNIT32

Reset front count 05 (Reset Menu Cell cmd only) * * *

Bus Comms Err Count Rear 06 UINT32 * * *

Protocol Err Count Rear 07 UINT32 * * *

Slave Message Count Rear 08 UINT32

Busy Count Rear 09 UINT32 * * *

Reset Rear Count 0A (Reset Menu Cell cmd only) * * *

PSL DATA B7 00

Grp 1 PSL Ref 01 ASCII Text (32 Chars) 31000 31015 G3 Data * * *

Date/Time 02 IEC 870 Date & Time 31016 31019 G12 Data * * *

Grp 1 PSL ID 03 Unsigned Integer (32 bits) 31020 31021 G27 Data * * *










COMMS SYS DATA N/A BF 00 * * *

Dist Record Cntrl Ref 01 Menu Cell(2) B300 Data * * *

Dist Record Extract Ref 02 Menu Cell(2) B400 Data * * *

Setting Transfer 03 Unsigned Integer Setting * * *

Reset Demand 04 None (Reset Menu Cell) * * *

UNUSED 05 * * *

Block Xfer Ref 06 Menu Cell(2) B200 Data * * *

DIAGNOSTICS E0 00 * * *

Enable Column 01 Indexed String G11 0 (No) Setting 0 1 1 2 * * * CPU Load Measurements

CPU Load-Instant 11 Unsigned Integer (32 bits) Data * * *

CPU Load-Average 12 Unsigned Integer (32 bits) Data * * *

CPU Load-Min 13 Unsigned Integer (32 bits) Data * * *

CPU Load-Max 14 Unsigned Integer (32 bits) Data * * *

CPU Load Reset 1F Indexed String G11 0 (No) Setting 0 1 1 2 * * *

DDB to set: 21 Unsigned Integer (32 bits) Setting 0 1022 1 2 * * * Manual DDB Control for tests

DDB to reset: 22 Unsigned Integer (32 bits) Setting 0 1022 1 2 * * *

DDB to pulse: 23 Unsigned Integer (32 bits) Setting 0 1022 1 2 * * * Label unfitted IO

Name Unfitted IO 26 Indexed String G11 0 (No) Setting 0 1 1 2 * * *

UINT32 - 1 31 Unsigned Integer (32 bits) Setting 0 2^32-1 1 2 * * * Debug variables - default: Not used

Bus Message Count Front

Data(but supports Reset Menu cell)

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UINT32 - 2 32 Unsigned Integer (32 bits) Setting 0 2^32-1 1 2 * * *




INT32 - 1 41 Signed Integer (32 bits) Data * * *





BIN32 - 1 51 Binary Flag (32 bits) Data * * *





FLT32 - 1 61 Courier Number (meters) Data * * *





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P341 P342 P343

G1 1 Register * * *

G2 1 Register * * *

G3 1 Register * * *

Bit Mask (hex)

0xFF00

0x00FF

G4 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004

0x00000008

0x00000010

0x00000020

0x00000040

0x00000080

0x00000100

0x00000200

0x00000400

0x00000800

0x00001000

0x00002000

0x00004000

0x00008000

0x00010000

0x00020000

0x00040000

0x00080000

0x00100000

0x00200000

0x00400000

0x00800000

0x01000000

0x02000000

0x04000000

0x08000000

0x10000000

0x20000000

0x40000000

0x80000000

G5 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

UNSIGNED INTEGER (16 Bits)

First character in high order 8 bits

Second character in low order 8 bits

PLANT STATUS (32 Bits)

NUMERIC SETTING (Unsigned 16 bit)

Used for floating point settings. The setting value is represented as the number of step increments from the minimum value (see also G35)

Data Types

Model

Type Value / Bit Mask Description

i.e. Setting value = (setting minimum) + ((register value) x (setting step size))

ASCII TEXT CHARACTERS (2 characters per register)

Data formatted as per data type G27

CB1 Open (0 = Off, 1 = On)

CB1 Closed (0 = Off, 1 = On)

Not Used (0 = Off, 1 = On)






























CONTROL STATUS (32 Bits)





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P341 P342 P343

Model


0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

0x00000100 * * *

0x00000200 * * *

0x00000400 * * *

0x00000800 * * *

0x00001000 * * *

0x00002000 * * *

0x00004000 * * *

0x00008000 * * *

0x00010000 * * *

0x00020000 * * *

0x00040000 * * *

0x00080000 * * *

0x00100000 * * *

0x00200000 * * *

0x00400000 * * *

0x00800000 * * *

0x01000000 * * *

0x02000000 * * *

0x04000000 * * *

0x08000000 * * *

0x10000000 * * *

0x20000000 * * *

0x40000000 * * *

0x80000000 * * *

G6 1 Register * * *

Value

0

1

2

3

4

G7 1 Register * * *

Value

0

1

G8 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

RECORD CONTROL COMMAND REGISTER




























No operation

Clear Event records

Clear Fault Record

Clear Maintenance Records

Reset Indications

VTS INDICATE/BLOCK

Blocking

Indication

LOGIC INPUT STATUS (32 Bits)


Opto 1 Input State (0=Off, 1=Energised)










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P341 P342 P343

Model


0x00000100 * * *

0x00000200 * * *

0x00000400 * * *

0x00000800 * * *

0x00001000 * * *

0x00002000 * * *

0x00004000 * * *

0x00008000 * * *

0x00010000 * * *

0x00020000 * * *

0x00040000 * * *

0x00080000 * * *

0x00100000 * * *

0x00200000 * * *

0x00400000 * * *

0x00800000 * * *

0x01000000 *

0x02000000 *

0x04000000 *

0x08000000 *

0x10000000 *

0x20000000 *

0x40000000 *

0x80000000 *

G9 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

0x00000100 * * *

0x00000200 * * *

0x00000400 * * *

0x00000800 * * *

0x00001000 * * *

0x00002000 * * *

0x00004000 * * *

0x00008000 * * *

0x00010000 * * *

0x00020000 * * *

0x00040000 * * *

0x00080000 * * *

0x00100000 * * *

0x00200000 * * *

0x00400000 * * *

0x00800000 * * *

























RELAY OUTPUT STATUS (32 Bits)


Relay 1 (0=Not Operated, 1=Operated)
























Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 48/170

P341 P342 P343

Model


0x01000000 *

0x02000000 *

0x04000000 *

0x08000000 *

0x10000000 *

0x20000000 *

0x40000000 *

0x80000000 *

G10 1 Register * * *


Value

0

1

G12 4 Registers * * *

Bit Mask (hex)

0xFFFF

0x9FBF

0x0FFF

0x007F


Value

0

1

2

3

4

5

6

7

8

9

G14 1 Register

Bit Mask (hex)

0x0001 *

0x0002 *

0x0004 *

0x0008 *

0x0010

0x0020

0x0040

0x0080


Value

0

1

2


Bit Mask (hex)

EVENT RECORD TYPE

Latched alarm active







SIGNED FIXED POINT NUMBER WITH 1 DECIMAL PLACE (16 Bits)

i.e. divide register value by 10 to obtain actual value.

YES/NO

No

Yes

TIME AND DATE

IEC60870-5-4 "Binary Time 2a" format - see Section 3.8 of SCADA Communications (P34x/EN CT) of Technical Guide

First Register - Milli-seconds

Second Register - Summertime and hours / Validity and minutes

Third register - Month of year / Day of month / Day of week

Fourth register - Years

Not Used

DISTURBANCE RECORD INDEX STATUS

No Record

Unextracted

Extracted

Latched alarm inactive

Self reset alarm active

Self reset alarm inactive

I>2 VTS Block

I>3 VTS Block

I>4 VTS Block

I>3 Block A/R

I>4 Block A/R

Not Used

Relay event

Opto event

Protection event

Platform event

Fault logged event

Maintenance record logged event

I> FUNCTION LINK

I>1 VTS Block

FAULTED PHASE



Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 49/170

P341 P342 P343

Model


0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

0x0040

0x0080


Value

0

1

2

3


Bit Mask (hex)

0x0000

0x0001

0x0002

0x0004

0x0008

0x0010


Value

0

1

2

3


Bit Mask (hex)

0xFF00

0x00FF

0xFF00

0x00FF


Value

0

1


Value

0

1

2


Value

0

1

Start A

Start B

Start C

Start N

Trip A

Trip B

Trip C

Trip N

IRIG-B STATUS

Card not fitted

Card failed

Signal healthy

No signal

RECORD SELECTION COMMAND REGISTER (MODBUS)

No Operation

Select next event

Accept Event

Select next Disturbance Record

Accept disturbance record

Select Next Disturbance record page

LANGUAGE

English

Francais

Deutsch

Espanol

PASSWORD (4 Characters packed into 32 Bits)


First register, first password character

First register, second password character

Second register, third password character

Second register, 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.

IEC60870-5-103 INTERFACE

EIA(RS)485

Fibre Optic

PASSWORD CONTROL ACCESS LEVEL

Level 0 - Passwords required for levels 1 & 2

Level 1 - Password required for level 2

Level 2 - No passwords required

VOLTAGE AND V/Hz CURVE SELECTION

Disabled

DT

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 50/170

P341 P342 P343

Model


2




Bit Mask (hex)

0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

0x0040

0x0080

0x0100

0x0200

0x0400

0x0800

0x1000

0x2000

0x4000

0x8000



G29 3 Registers

First Register

Second & third registers


G31 1 Register

Value

0 * * *

1 * * *

2 * * *

3 * * *

4 * *

4 *

5 * *

5 *

Unused

Unused

UNSIGNED LONG (32 Bit) VALUE

High order word stored in 1st register

Low order word stored in 2nd register

IDMT

UNSIGNED FIXED POINT NUMBER WITH 3 DECIMAL PLACES (32 Bits)


i.e. divide 'G27' value by 1000 to obtain actual value

Current 0 - 4,000,000A Resolution 1mA

Voltage 0 - 4MV Resolution 1mV

New auto-extraction event available (=1, 0 otherwise)

Time Synchronised (=1 after Modbus time synch. Resets to 0 after 5 minutes unless re-time synch'd. Other time synch sources do not affect this bit.)

New auto-extraction disturbance record available (=1, 0 otherwise)

Fault (not used, always zero)

Trip LED status (1=LED On, 0 = LED Off)

Alarm status summary (logical OR of all alarm status bits)

Unused

Unused

Unused

Unused

Unused

Unused

SIGNED INTEGER (16 Bit)

INTEGER POWER/ENERGY WITH MULTIPLIER

Per unit value formatted as a G28

Scalar, formatted as a G27

Overall value = 'G28'x'G27' see Section 3.9 of SCADA Communications (P34x/EN CT) of Technical Guide for details

IA-1

IB

IB-1

SIGNED VALUE, 2 DECIMAL PLACES

i.e. divide register value by 100 to obtain actual value

ANALOGUE CHANNEL ASSIGNMENT SELECTOR (Generator specific)

VAN

VBN

VCN

VN

IA

In Service Status (1= In service, 0= Out of service)

Minor self test failure (=1, 0 otherwise)

MODBUS RELAY STATUS REGISTER

UNSIGNED FIXED POINT NUMBER WITH 3 DECIMAL PLACES (16 Bits)

i.e. divide register value by 1000 to obtain actual value

Time Interval 0.000 - 655.000s Resolution 1ms

Frequency 0.000 - 655.000Hz Resolution 0.001Hz

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MiCOM P342, P343

P34x/EN GC/F33

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P341 P342 P343

Model


6 * *

6 *

7 * *

8 * * *

9 *

10 *

11 *


Value

0

1 onwards

G33


Value

0

1



Value

0

1


Value

0

1

G38c * * *

Value

0

1

2

G38m * * *

Value

0

1

2

G38v * * *

Value

0

1

G38d * * *

Value

0

1

2

3

4

IN

IN Sensitive

IA-2

IB-2

IC-2

DISTURBANCE RECORD DIGITAL CHANNEL ASSIGNMENT SELECTOR

IC

IC-1

Not used (i.e. nothing recorded for the channel)

See separate G32 DDB Table

NOT USED

TRIGGER MODE

Single

Extended

NUMERIC SETTING (Unsigned 32 Bit)

Used for floating point settings. The setting value is represented as the number of step increments from the minimum value (see also G2)


i.e. Setting value = (setting minimum) + (('G27' value) x (setting step size))

REAL NUMBERS

Polar

Rectangular

ENABLED / DISABLED

Disabled

Enabled

COMMUNICATION BAUD RATE (COURIER)

9600 bits/s

19200 bits/s

38400 bits/s

COMMUNICATION BAUD RATE (MODBUS)

9600 bits/s

19200 bits/s

38400 bits/s

COMMUNICATION BAUD RATE (IEC60870-5-103)

9600 bits/s

19200 bits/s

COMMUNICATION BAUD RATE (DNP 3.0)

1200 bits/s

2400 bits/s

4800 bits/s

9600 bits/s

19200 bits/s

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P34x/EN GC/F33

Page 52/170

P341 P342 P343

Model


5


Value

0

1

2

G40 1 Register

Value

0

1

2

3

4

5

G41 1 Register

Value

0

1

2

3

G42 1 Register

Value

0

1

2

3


Value

0

1

2

3

4

5

6

7

8

9

10


Value

0

1

2


Value

0

1

G46 1 Register *

Value

IDMT CURVE TYPE

Disabled

DT

38400 bits/s

COMMUNICATIONS PARITY

Odd

Even

None

CHECK SYNC INPUT SELECTION

A-N

B-N

C-N

A-B

B-C

C-A

CHECK SYNC VOLTAGE BLOCKING

None

Undervoltage

Differential

Both

CHECK SYNC SLIP CONTROL

None

Timer

Frequency

Both

IEC S Inverse

POLARISATION

Non-Directional

Directional Fwd

Directional Rev

VTS BLOCK

Block

Non-Directional

IEC V Inverse

IEC E Inverse

UK LT Inverse

IEEE M Inverse

IEEE V Inverse

IEEE E Inverse

US Inverse

US ST Inverse

DIRECTION

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P34x/EN GC/F33

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P341 P342 P343

Model


0

1


Value

0

1


Value

0

1


Value

0

1

G50 1 Register * *

Bit Mask (hex)

0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

0x0040

0x0080

0x0100

0x0200

G51 1 Register

Value

0

1

2


Value

0

1

2

3

4

5

6

7


Value

0

1

2

3

4

5


Zero Sequence

Neg Sequence

MEASURING MODE

Phase-Phase

Phase-Neutral

OPERATION MODE

Any Phase

Three Phase

VN OR IN INPUT

Measured

Derived

RTD SELECT

RTD Input #1

RTD Input #2

RTD Input #3

RTD Input #4

RTD Input #5

RTD Input #6

RTD Input #7

RTD Input #8

RTD Input #9

RTD Input #10

FAULT LOCATION

Distance

Ohms

% of Line

DEFAULT DISPLAY

3Ph + N Current

3 Ph-neutral Voltage

Power

Date and Time

Description

Plant Reference

Frequency

Access Level

SELECT FACTORY DEFAULTS

No Operation

All Settings

Setting Group 1

Setting Group 2

Setting Group 3

Setting Group 4

SELECT PRIMARY SECONDARY MEASUREMENTS

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P34x/EN GC/F33

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P341 P342 P343

Model


Value

0

1

G55 1 Register *

Value

0

1

2


Value

0

1

2

3

4

5


Value

0

1

G58 1 Register

Value

0 * * *

1 * * *

2 * * *

3 * * *

4 * * *

5 * *

6 * *

7 * *


Value

0

1


Value

0

1


Value

0

1


Value

0

1

2

G63 1 Register

Bit Mask (hex)

0x0001 *

CIRCUIT BREAKER CONTROL

No Operation

Trip

Primary

Secondary

DATA TRANSFER DOMAIN

PSL Settings

PSL Configuration

SEF/REF SELECTION

Close

PHASE MEASUREMENT REFERENCE

VA

VB

VC

IA

IB

IC

SEF

SEF cos(PHI)

SEF sin(PHI)

Wattmetric

Hi Z REF

Lo Z REF

Lo Z REF+SEF

Lo Z REF+Wattmet

BATTERY STATUS

Dead

Healthy

TIME DELAY SELECTION

DT

Inverse

ACTIVE GROUP CONTROL

Select via Menu

Select via Opto

SAVE AS

No Operation

Save

Abort

IN> FUNCTION LINK

IN>1 VTS Block

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P34x/EN GC/F33

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P341 P342 P343

Model


0x0002 *

0x0004 *

0x0008 *

0x0010

0x0020

0x0040

0x0080

G64 1 Register

Bit Mask (hex)

0x0001 * * *

0x0002 *

0x0004 *

0x0008 *

0x0010

0x0020

0x0040

0x0080


Bit Mask (hex)

0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

0x0040

0x0080


Value

0

1

2


Value

0

1


Value

0

1

2


Value

0

1

G70 1 Register

Value

0

1

2

DISTURBANCE RECORDER DIGITAL CHANNEL TRIGGER

No Trigger

Trigger L/H

IN>2 VTS Block

IN>3 VTS Block

IN>4 VTS Block

IN>3 Block A/R

IN>4 Block A/R

Not Used

Not Used

ISEF> FUNC LINK

ISEF>1 VTS Block

ISEF>2 VTS Block

ISEF>3 VTS Block

ISEF>4 VTS Block

ISEF>3 Block A/R

ISEF>4 Block A/R

Not Used

Not Used

F< FUNCTION LINK

F<1 Poledead Blk

F<2 Poledead Blk

F<3 Poledead Blk

F<4 Poledead Blk

Not Used

Not Used

Not Used

Not Used

Auto

User Set

Trigger H/L

THERMAL OVERLOAD

Manual

Auto

AUTORECLOSE MODE

Opto set

Single

Dual

CB FAIL RESET OPTIONS

I< Only

CB Open & I<

Prot Reset & I<

VTS RESET MODE

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P34x/EN GC/F33

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P341 P342 P343

Model


3


Value

0

1

2

G72 1 Register

Value

0

1

G73 1 Register

Value

0

1

G74 1 Register

Value

0

1

G75 1 Register

Value

0

1


Value

0

1

2

3

4

5

6

7

G77 1 Register

Value

0

1

G78 1 Register

Value

0

1

2


Value

0

1

2


Value

0

Pulse Set

PROTOCOL

Courier

IEC870-5-103

Modbus

START DEAD TIME

Protection Reset

CB Trips

RECLAIM TIME if PROTECTION START

Suspend

Continue

RESET LOCKOUT

User Interface

Select NonAuto

AUTO-RECLOSE AFTER CONTROL CLOSE

Enabled

Inhibited

TRANSFER MODE

Prepare Rx

Complete Rx

Prepare Tx

Complete Tx

Rx Prepared

Tx Prepared

OK

Error

AUTO-RECLOSE

Out of Service

In Service

A/R TELECONTROL

No Operation

Auto

Non-auto

CUSTOM SETTINGS

Disabled

Basic

Complete

VISIBLE/INVISIBLE

Invisible

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P34x/EN GC/F33

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P341 P342 P343

Model


1


Value

0

1

G82 1 Register

Value

0

1

G83 1 Register

Value

0

1 Non-auto Mode

2

G84 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * *

0x00000010 * *

0x00000020 * *

0x00000040 * * *

0x00000080 * * *

0x00000100 *

0x00000200 *

0x00000400 * * *

0x00000800 * * *

0x00001000 *

0x00002000 *

0x00004000 * * *

0x00008000 *

0x00010000 *

0x00020000 *

0x00040000 * * *

0x00080000 * * *

0x00100000 *

0x00200000 * * *

0x00400000 * * *

0x00800000 *

0x01000000 *

0x02000000 * *

0x04000000 * *

0x08000000

0x10000000

0x20000000

RESET LOCKOUT BY

User Interface

CB Close

Visible

A/R PROTECTION BLOCKING

Live Line

STARTED ELEMENTS - 1 (32 Bits)

(For fault record use only. The associated Modbus registers cannot be accessed unless a fault record is selected)


General Start

Start I>3

No Block

Block Inst Prot

A/R STATUS

Auto Mode

Start Z<2

Start Power1

Start Power2

Start FFail1

Start FFail2

Start V Dep O/C

Start I>1

Start I>2

Start I>4

Start IN>1

Start Sen Power2

Start z PSlip Z1

Start z PSlip Z2

Start Z<1

Start IN>2

Start NVD VN>2

Start 100% ST EF

Start Sen Power1

Start IN>3

Start IN>4

Start ISEF>1

Start ISEF>2

Start ISEF>3

Start ISEF>4

Start NVD VN>1

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P34x/EN GC/F33

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P341 P342 P343

Model


0x40000000

0x80000000

G85 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 *

0x00000004 * * *

0x00000008 * * *

0x00000010 * *

0x00000020 * *

0x00000040 * *

0x00000080 * *

0x00000100 * * *

0x00000200 * * *

0x00000400 *

0x00000800 *

0x00001000 * * *

0x00002000 * * *

0x00004000 *

0x00008000 *

0x00010000 * * *

0x00020000 *

0x00040000 *

0x00080000 *

0x00100000 * * *

0x00200000 * * *

0x00400000 * * *

0x00800000 *

0x01000000 *

0x02000000 * * *

0x04000000 * * *

0x08000000 *

0x10000000 *

0x20000000 * * *

0x40000000 * *

0x80000000 * *

G86 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

Trip Z<2

Trip Z<1

TRIPPED ELEMENTS - 1 (32 Bits)



Any Trip

Trip Gen Diff

Trip Power1

Trip Power2

Trip FFail1

Trip FFail2

Trip NPS

Trip V Dep O/C

Trip I>1

Trip I>2

Trip I>3

Trip I>4

Trip IN>1

Trip IN>2

Trip IN>3

Trip IN>4

Trip ISEF>1

Trip ISEF>2

Trip ISEF>3

Trip ISEF>4

Trip IREF>

Trip NVD VN>1

Trip NVD VN>2

Trip 100% ST EF

Trip Dead Mach

Trip Sen Power1

Trip Sen Power2

Trip z PSlip Z1

Trip z PSlip Z2

Trip Thermal O/L

TRIPPED ELEMENTS - 2 (32 Bits)



Trip V<1

Trip V<2

Trip V< A/AB

Trip V< B/BC

Trip V< C/CA

Trip V>1

Trip V>2

Trip V> A/AB

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MiCOM P342, P343

P34x/EN GC/F33

Page 59/170

P341 P342 P343

Model


0x00000100 * * *

0x00000200 * * *

0x00000400 * * *

0x00000800 * * *

0x00001000 * * *

0x00002000 * * *

0x00004000 * * *

0x00008000 * * *

0x00010000 * *

0x00010000 *

0x00020000 *

0x00040000 * *

0x00080000 * *

0x00100000 * *

0x00200000 * *

0x00400000 * *

0x00800000 * *

0x01000000 * *

0x02000000 * *

0x04000000 * *

0x08000000 * *

0x10000000 * * *

0x20000000 * * *

0x40000000 * * *

0x80000000 * * *

G87 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * *

0x00000020 * *

0x00000040 * *

0x00000080 * *

0x00000100 * *

0x00000200 * *

0x00000400 * *

0x00000800 * *

0x00001000 * *

0x00002000 * *

0x00004000 * *

0x00008000 * *

0x00010000 * *

0x00020000 * * *

0x00040000 * * *

0x00080000 * * *

0x00100000 * * *

FAULT ALARMS (32 Bits)

Trip V> B/BC

Trip V> C/CA

Trip F<1

Trip F<2

Trip F<3

Trip F<4

Trip F>1

Trip F>2

Trip V/Hz

Trip V Shift

Trip df/dt

Trip RTD 1

Trip RTD 2

Trip RTD 3

Trip RTD 4

Trip RTD 5

Trip CL Input 4

Trip RTD 6

Trip RTD 7

Trip RTD 8

Trip RTD 9

Trip RTD 10

Trip CL Input 1

Trip CL Input 2

Trip CL Input 3



CB Fail 1

CB Fail 2

VTS

CTS

Alarm FFail

Alarm NPS

Alarm V/Hz

Alarm RTD 1

Alarm RTD 2

Alarm RTD 3

Alarm RTD 4

Alarm RTD 5

Alarm RTD 6

Alarm RTD 7

Alarm RTD 8

Alarm RTD 9

Alarm RTD 10

Alarm Thermal

Alarm CL Input 1

Alarm CL Input 2

Alarm CL Input 3

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MiCOM P342, P343

P34x/EN GC/F33

Page 60/170

P341 P342 P343

Model


0x00200000 * * *

0x00400000

0x00800000

0x01000000

0x02000000

0x04000000

0x08000000

0x10000000

0x20000000

0x40000000

0x80000000


Value

0

1

G89 1 Register

Value

0

1


Value

0

1

2

3

G91 1 Register

Value

0

1

G92 1 Register

Value

0

1


Value

0

1

2


Value

0

1


Bit Mask (hex)

0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

Block Tripping

No Lockout

Lockout

A/R PROTECTION BLOCKING

Allow Tripping

LOCKOUT

COMMISSION TEST

No Operation

Apply Test

Remove Test

COMMISSION TEST

Not Used

Not used

Not Used

Not Used

Alarm CL Input 4

ALARMS

Alarm Disabled

No Operation

Apply Test

SYSTEM FN LINKS

Trip led self reset (1 = enable self reset)

Not Used

Alarm Enabled

MAIN VT LOCATION

Line

Bus

GROUP SELECTION

Group 1

Group 2

Group 3

Group 4

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P34x/EN GC/F33

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P341 P342 P343

Model


0x0040

0x0080

G96 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

0x00000100 * * *

0x00000200 * * *

0x00000400 * * *

0x00000800 * * *

0x00001000 * * *

0x00002000 * * *

0x00004000 * * *

0x00008000 *

0x00010000 *

0x00020000 *

0x00040000 *

0x00040000 * *

0x00080000 * * *

0x00100000 * *

0x00200000 * *

0x00400000 * *

0x00800000 * *

0x01000000 * *

0x02000000 * *

0x04000000 * *

0x08000000 * * *

0x10000000 * * *

0x20000000

0x40000000

0x80000000

G97 1 Register

Value

0

1


Value

0

1

2

3

4

G99 1 Register *

Value


Not Used

Not Used

SG-opto Invalid

Prot'n Disabled

CB OPs Maint

CB OPs Lock

CB Time Maint

VT Fail Alarm

CTS Fail Alarm

CB Fail

I^ Maint Alarm

Fault Freq Lock

CB Status Alarm

I^ Maint Lockout

ALARM STATUS 1 (ALARMS 1 - 32) (32 Bits)

Not Used

Not Used

CB Trip Fail

RTD Open Cct

RTD short Cct

RTD Data Error

RTD Board Fail

CB Time Lockout

Freq Prot Alm

Voltage Prot Alm

Not used

Not Used

DISTANCE UNIT

Kilometres

Miles

COPY TO

No Operation

Group 1

Group 2

Group 3

Group 4

CB CONTROL

CB Close Fail

Man CB Unhealthy

F out of Range

NPS Alarm

Thermal Alarm

V/Hz Alarm

Field Fail Alarm

RTD Thermal Alm

Not Used

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P34x/EN GC/F33

Page 62/170

P341 P342 P343

Model


0

1

2

3

4

5

6

7

G100

G101 1 Register * *

Value

0

1

2

3


Value

0

1

2

3

G103 1 Register * *

Value

0

1

2

3

G104 1 Register * *

Value

0

1


Value

0

1

G107 2 Registers

Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

0x00000100 * * *

0x00000200 * * *

0x00000400 * * *

GEN DIFF FUNCTION SELECT

Disabled

Percentage Bias

High Impedance

Interturn

POWER FUNCTION SELECT

Disabled

Underimpedance

Volt controlled

Reverse

Low Forward

Over

SYSTEM BACKUP FUNCTION SELECT

Disabled

Delta-Star

DEFINITE TIME OVERCURRENT SELECTION

Disabled

DT

Start V> B/BC

Start V> C/CA

Start F<1

Start V<2

Start V< A/AB

Start V< B/BC

Start V< C/CA

Start V>1

Start V>2

Start V> A/AB

Start V<1

Volt restrained

SYSTEM BACKUP VECTOR ROTATION

None

Opto+local

Disabled

Local

STARTED ELEMENTS - 2 (32 Bits)



Opto+Remote

Opto+Rem+local

NOT USED

Remote

Local+Remote

Opto

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 63/170

P341 P342 P343

Model


0x00000800 * * *

0x00001000 * * *

0x00002000 * * *

0x00004000 * * *

0x00008000 * * *

0x00010000 * *

0x00020000 *

0x00040000 * * *

0x00080000 * * *

0x00100000 * * *

0x00200000 * * *

0x00400000 * * *

0x00800000 * * *

0x01000000 * * *

0x02000000 * * *

0x04000000

0x08000000

0x10000000

0x20000000

0x40000000

0x80000000

G108 1 Register * *

Bit Mask (hex)

0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

0x0040

0x0080

0x0100

0x0200

G109 1 Register * *

Bit Mask (hex)

0x0001

0x0002

0x0004

0x0008

0x0010

0x0020

0x0040

0x0080

0x0100

0x0200

G110 1 Register * *

Bit Mask (hex)

0x0001

0x0002

0x0004

Start F<2

Start F<3

Start F<4

Start F>1

Start F>2

Start CLI2 Trip

Start CLI3 Trip

Start CLI4 Trip

Start CLI3 Alarm

Start CLI4 Alarm

Start CLI1 Trip

Start V/Hz

Start df/dt

Start CLI1 Alarm

Start CLI2 Alarm

RTD OPEN CIRCUIT FLAGS

RTD 1 label

RTD 2 label

RTD 3 label

RTD 4 label

RTD 5 label

RTD 6 label

RTD 7 label

RTD 8 label

RTD 9 label

RTD 10 label

RTD SHORT CIRCUIT FLAGS

RTD 1 label

RTD 2 label

RTD 3 label

RTD 4 label

RTD 5 label

RTD 6 label

RTD 7 label

RTD 8 label

RTD 9 label

RTD 10 label

RTD DATA ERROR

RTD 1 label

RTD 2 label

RTD 3 label

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 64/170

P341 P342 P343

Model


0x0008

0x0010

0x0020

0x0040

0x0080

0x0100

0x0200

G111 1 Register * *

Value

0

1

2

3

4

5

6

7

8

9

10

11

G112 1 Register *

Value

0

1

2

G113 1 Register *

Value

0

1

2


Value

0

1

2


Value

0

1


Value

0

1


Value

0

1

2

IA-2 IB-2 IC-2

CB FAIL PHASE UNDERCURRENT CURRENT INPUTS

IA-1 IB-1 IC-1

RTD 4 label

RTD 5 label

RTD 6 label

RTD 7 label

RTD 8 label

RTD 9 label

RTD 10 label

SYSTEM BACKUP V DEP OC IDMT CURVE TYPE

DT (DT)

IEC S Inverse (TMS)

IEC V Inverse (TMS)

IEC E Inverse (TMS)

UK LT Inverse (TMS)

Rectifier (TMS)

RI (K)

IEEE M Inverse (TD)

IEEE V Inverse (TD)

IEEE E Inverse (TD)

US Inverse (TD)

US ST Inverse (TD)

100% STATOR EARTH FAULT STATUS

Disabled

VN3H< Enabled

VN3H> Enabled

POLE SLIPPING OPERATING MODE

Generating

Motoring

Both

SEF/REF/SPOWER SELECTION

Disabled

SEF/REF

Sensitive Power

POWER PROTECTION OPERATING MODE

Generating

Motoring

CB CONTROL LOGIC INPUT ASSIGNMENTS

None

52A

52B

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 65/170

P341 P342 P343

Model


3


Value

0

1

2



Bit Mask (hex)

0x00000001 * * *

0x00000002 * * *

0x00000004 * * *

0x00000008 * * *

0x00000010 * * *

0x00000020 * * *

0x00000040 * * *

0x00000080 * * *

0x00000100 * * *

0x00000200 * * *

0x00000400

0x00000800

0x00001000

0x00002000

0x00004000

0x00008000

0x00010000 * * *

0x00020000 * * *

0x00040000 * * *

0x00080000 * * *

0x00100000 * * *

0x00200000 * * *

0x00400000 * * *

0x00800000 * * *

0x01000000 * * *

0x02000000 * * *

0x04000000 * * *

0x08000000 * * *

0x10000000 * * *

0x20000000 * * *

0x40000000 * * *

0x80000000 * * *


Value

0

1

CL Input 4 Alarm

CLI1 I< Fail Alm

CL Input 3 Alarm

CL Card O/P Fail

CL Input 1 Alarm

CL Input 2 Alarm



CL Card I/P Fail

POC IDMT CURVE TYPE

Disabled

DT (DT)

Both 52A and 52B

TEST MODE

Disabled

Test Mode

Blocked

IEEE FLOATING POINT FORMAT (Short float; 32 Bits)

Bit 31 = sign

Bits 30-23 = e7 - e0

Implicit 1

Bits 22-0 = f22 - f0

(32 bit value formatted as per data type G27)

CLI2 I< Fail Alm

CLI3 I< Fail Alm

CLI4 I< Fail Alm

Not Used

Not Used

Not Used

Not Used

Not Used

Not Used

MR User Alarm 16

MR User Alarm 15

MR User Alarm 14

MR User Alarm 13

MR User Alarm 12

MR User Alarm 11

MR User Alarm 10

MR User Alarm 9

MR User Alarm 8

MR User Alarm 7

MR User Alarm 6

MR User Alarm 5

SR User Alarm 4

SR User Alarm 3

SR User Alarm 2

SR User Alarm 1

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 66/170

P341 P342 P343

Model


2

3

4

5

6

7

8

9

10

11

12


Value

0

1

2

3

4

5

6

7

8

9

10

11

12


Value

0

1

2

3

4

5

6

7

8

9

10

11


Value

0

1

2

3


Value

0

IEC S Inverse (TMS)

IEC V Inverse (TMS)

IEC E Inverse (TMS)

UK LT Inverse (TMS)

Rectifier (TMS)

RI (K)

IEEE M Inverse (TD)

IEEE V Inverse (TD)

IEEE E Inverse (TD)

US Inverse (TD)

US ST Inverse (TD)

EF IDMT CURVE TYPE

Disabled

DT (DT)

IEC S Inverse (TMS)

IEC V Inverse (TMS)

IEC E Inverse (TMS)

UK LT Inverse (TMS)

RI (K)

IEEE M Inverse (TD)

UK LT Inverse (TMS)

DT (DT)

IEC S Inverse (TMS)

IEC V Inverse (TMS)

IEC E Inverse (TMS)

IDG

SEF IDMT CURVE TYPE

US Inverse (TD)

US ST Inverse (TD)

IDG

IEEE M Inverse (TD)

IEEE V Inverse (TD)

IEEE E Inverse (TD)

CLIO INPUT RANGE

0-1mA

Disabled

IEEE V Inverse (TD)

IEEE E Inverse (TD)

US Inverse (TD)

US ST Inverse (TD)

0-10mA

0-20mA

4-20mA

CLIO TRIP / ALARM OPERATING MODE

Under

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 67/170

P341 P342 P343

Model


1

G155 1 Register

Value Value Value

0 0 0

1 1 1

2 2 2

3 3

3

4 4 4

5 5 5

6 6 6

7 7 7

8 8 8

9 9 9

10 10 10

11 11 11

12 12 12

13 13 13

14 14 14

15 15 15

16 16 16

17 17 17

18 18 18

19 19 19

20 20 20

21 21 21

22 22 22

23 23 23

24 24 24

25 25 25

26 26 26

27 27 27

28 28 28

29 29 29

30 30 30

31 31 31

32 32 32

33 33 33

34 34 34

35 35 35

36 36 36

37 37 37

38 38 38

39 39 39

40 40 40

41 41 41

42 42 42

43 43 43

44 44 44

45 45 45

Over

CLIO OUTPUT MEASUREMENT

IA Magnitude

IB Magnitude

IC Magnitude

IN Measured Mag

IN Derived Mag

I Sen Magnitude

I1 Magnitude

I2 Magnitude

I0 Magnitude

IA RMS

IB RMS

IC RMS

VAB Magnitude

VBC Magnitude

VCA Magnitude

VAN Magnitude

VBN Magnitude

VCN Magnitude

VN Measured Mag

VN Derived Mag

V1 Magnitude

V2 Magnitude

V0 Magnitude

VAN RMS

VBN RMS

VCN RMS

Frequency

3 Phase Watts

A Phase Watts

B Phase Watts

C Phase Watts

3 Phase Vars

A Phase Vars

B Phase Vars

C Phase Vars

3 Phase VA

A Phase VA

B Phase VA

C Phase VA

3Ph Power Factor

APh Power Factor

BPh Power Factor

CPh Power Factor

3Ph W Fix Demand

3Ph Vars Fix Dem

IA Fixed Demand

IB Fixed Demand

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 68/170

P341 P342 P343

Model


46 46 46

47 47 47

48 48 48

49 49 49

50 50 50

51 51 51

52 52 52

53 53 53

54 54 54

55 55 55

56 56 56

57

57 58

57 58 59

59 60

60 61

61 62

62 63

63 64

64 65

65 66

66 67

67 68

68 69

58 69 70

59 70 71

60 71 72

61 72 73


Value

0

1

2

3

4

5


Value

0

1

2

3

4


Bit Mask (hex)

0x00000001

0x00000002

0x00000004

0x00000008

0x00000010

GLOBAL OPTO NOMINAL VOLTAGE SELECTION

24-27V

30-34V

48-54V

110-125V

220-250V

Custom

SINGLE OPTO NOMINAL VOLTAGE SELECTION

24-27V

30-34V

48-54V

110-125V

220-250V

CONTROL INPUT STATUS (32 Bits)


Control Input 1 (0 = Reset, 1 = Set)





IC Fixed Demand

3 Ph W Roll Dem

3Ph Vars RollDem

IA Roll Demand

IB Roll Demand

IC Roll Demand

3Ph W Peak Dem

3Ph Var Peak Dem

IA Peak Demand

IB Peak Demand

IC Peak Demand

VN 3rd Harmonic

NPS Thermal

Thermal Overload

RTD 1

RTD 2

RTD 3

RTD 4

RTD 5

RTD 6

RTD 7

RTD 8

RTD 9

RTD 10

CL Input 1

CL Input 2

CL Input 3

CL Input 4

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 69/170

P341 P342 P343

Model


0x00000020

0x00000040

0x00000080

0x00000100

0x00000200

0x00000400

0x00000800

0x00001000

0x00002000

0x00004000

0x00008000

0x00010000

0x00020000

0x00040000

0x00080000

0x00100000

0x00200000

0x00400000

0x00800000

0x01000000

0x02000000

0x04000000

0x08000000

0x10000000

0x20000000

0x40000000

0x80000000


Value

0

1

2


Value

0

1

2

3

4


Value

0

1

2


Value

0

1


Value


























VIRTUAL INPUT

No Operation

Set

Reset

REAR COMMS CARD STATUS

Unsupported

Card not Fitted

EIA(RS)232 OK

K-Bus OK

SECOND REAR COMMUNICATIONS PORT CONFIGURATION (model option)

10-bit no parity

CS103 BLOCKING

EIA(RS)232

EIA(RS)485

K-Bus

COMMS MODE (IEC60870-5-2)



EIA(RS)232 OK

IEC60870 FT1.2

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 70/170

P341 P342 P343

Model


0

1

2


Bit Mask (hex)

0x00000001

0x00000002

0x00000004

0x00000008

0x00000010

0x00000020

0x00000040

0x00000080

0x00000100

0x00000200

0x00000400

0x00000800

0x00001000

0x00002000

0x00004000

0x00008000

0x00010000

0x00020000

0x00040000

0x00080000

0x00100000

0x00200000

0x00400000

0x00800000

0x01000000

0x02000000

0x04000000

0x08000000

0x10000000

0x20000000

0x40000000

0x80000000

Battery Fail

Field Volt Fail



Disabled

Monitor Blocking

Command Blocking

Unused

GOOSE IED Absent

NIC not fitted

NIC no response

NIC fatal error

NIC Software Reload

Bad TCP/IP Configuration

Bad OSI Configuration

NIC Link Fail

NIC SW-Mismatch

IP addr conflict

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Unused

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 71/170

P341 P342 P343

0 Unused Unused Unused

1 see 4B01 see 4B01 see 4B01









10 see 4B0A see 4B0A see 4B0A

11 see 4B0B see 4B0B see 4B0B

12 see 4B0C see 4B0C see 4B0C

13 see 4B0D see 4B0D see 4B0D

14 see 4B0E see 4B0E see 4B0E

15 see 4B0F see 4B0F see 4B0F










25 see 4A01 see 4A01 see 4B19

26 see 4A02 see 4A02 see 4B1A

27 see 4A03 see 4A03 see 4B1B

28 see 4A04 see 4A04 see 4B1C

29 see 4A05 see 4A05 see 4B1D

30 see 4A06 see 4A06 see 4B1E

31 see 4A07 see 4A07 see 4B1F

32 see 4A08 see 4A08 see 4B20

33 see 4A09 see 4A09 see 4A01

34 see 4A0A see 4A0A see 4A02

35 see 4A0B see 4A0B see 4A03

36 see 4A0C see 4A0C see 4A04

37 see 4A0D see 4A0D see 4A05

38 see 4A0E see 4A0E see 4A06

39 see 4A0F see 4A0F see 4A07



42 see 4A12 see 4A12 see 4A0A

43 see 4A13 see 4A13 see 4A0B

44 see 4A14 see 4A14 see 4A0C

45 see 4A15 see 4A15 see 4A0D

46 see 4A16 see 4A16 see 4A0E

47 see 4A17 see 4A17 see 4A0F

G32 Digital Channel Assignment Selector

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 72/170

P341 P342 P343


49 LED 1 LED 1 see 4A11








57 SG-opto Invalid SG-opto Invalid see 4A19

58 Prot'n Disabled Prot'n Disabled see 4A1A

59 VT Fail Alarm VT Fail Alarm see 4A1B

60 CT Fail Alarm CT Fail Alarm see 4A1C

61 CB Fail Alarm CB Fail Alarm see 4A1D

62 I^ Maint Alarm I^ Maint Alarm see 4A1E

63 I^ Lockout Alarm I^ Lockout Alarm see 4A1F

64 CB Ops Maint CB Ops Maint see 4A20

65 CB Ops Lockout CB Ops Lockout LED 1

66 CB Op Time Maint CB Op Time Maint LED 2

67 CB Op Time Lock CB Op Time Lock LED 3

68 Fault Freq Lock Fault Freq Lock LED 4

69 CB Status Alarm CB Status Alarm LED 5

70 Man CB Trip Fail Man CB Trip Fail LED 6

71 Man CB Cls Fail Man CB Cls Fail LED 7

72 Man CB Unhealthy Man CB Unhealthy LED 8

73 F out of Range NPS Alarm SG-opto Invalid

74 Thermal Alarm Thermal Alarm Prot'n Disabled

75 Freq Prot Alm V/Hz Alarm VT Fail Alarm

76 Voltage Prot Alm Field Fail Alarm CT Fail Alarm

77 CL Card I/P Fail RTD Thermal Alm CB Fail Alarm

78 CL Card O/P Fail RTD Open Cct I^ Maint Alarm

79 CL Input 1 Alarm RTD short Cct I^ Lockout Alarm

80 CL Input 2 Alarm RTD Data Error CB Ops Maint

81 CL Input 3 Alarm RTD Board Fail CB Ops Lockout

82 CL Input 4 Alarm Freq Prot Alm CB Op Time Maint

83 CLI1 I< Fail Alm Voltage Prot Alm CB Op Time Lock

84 CLI2 I< Fail Alm CL Card I/P Fail Fault Freq Lock

85 CLI3 I< Fail Alm CL Card O/P Fail CB Status Alarm

86 CLI4 I< Fail Alm CL Input 1 Alarm Man CB Trip Fail

87 MR User Alarm 16 CL Input 2 Alarm Man CB Cls Fail

88 MR User Alarm 15 CL Input 3 Alarm Man CB Unhealthy

89 MR User Alarm 14 CL Input 4 Alarm NPS Alarm

90 MR User Alarm 13 CLI1 I< Fail Alm Thermal Alarm

91 MR User Alarm 12 CLI2 I< Fail Alm V/Hz Alarm

92 MR User Alarm 11 CLI3 I< Fail Alm Field Fail Alarm

93 MR User Alarm 10 CLI4 I< Fail Alm RTD Thermal Alm

94 MR User Alarm 9 MR User Alarm 16 RTD Open Cct

95 MR User Alarm 8 MR User Alarm 15 RTD short Cct

96 MR User Alarm 7 MR User Alarm 14 RTD Data Error

97 MR User Alarm 6 MR User Alarm 13 RTD Board Fail

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 73/170

P341 P342 P343

98 MR User Alarm 5 MR User Alarm 12 Freq Prot Alm

99 SR User Alarm 4 MR User Alarm 11 Voltage Prot Alm

100 SR User Alarm 3 MR User Alarm 10 CL Card I/P Fail

101 SR User Alarm 2 MR User Alarm 9 CL Card O/P Fail

102 SR User Alarm 1 MR User Alarm 8 CL Input 1 Alarm

103 df/dt Trip MR User Alarm 7 CL Input 2 Alarm

104 V Shift Trip MR User Alarm 6 CL Input 3 Alarm

105 IN>1 Trip MR User Alarm 5 CL Input 4 Alarm

106 IN>2 Trip SR User Alarm 4 CLI1 I< Fail Alm



109 IREF> Trip SR User Alarm 1 CLI4 I< Fail Alm

110 ISEF>1 Trip Field Fail1 Trip MR User Alarm 16

111 ISEF>2 Trip Field Fail2 Trip MR User Alarm 15

112 ISEF>3 Trip NPS Trip MR User Alarm 14

113 ISEF>4 Trip V Dep OC Trip MR User Alarm 13

114 VN>1 Trip V Dep OC Trip A MR User Alarm 12

115 VN>2 Trip V Dep OC Trip B MR User Alarm 11

116 V<1 Trip V Dep OC Trip C MR User Alarm 10

117 V<1 Trip A/AB V/Hz Trip MR User Alarm 9

118 V<1 Trip B/BC RTD 1 Trip MR User Alarm 8

119 V<1 Trip C/CA RTD 2 Trip MR User Alarm 7

120 V<2 Trip RTD 3 Trip MR User Alarm 6

121 V<2 Trip A/AB RTD 4 Trip MR User Alarm 5

122 V<2 Trip B/BC RTD 5 Trip SR User Alarm 4

123 V<2 Trip C/CA RTD 6 Trip SR User Alarm 3

124 V>1 Trip RTD 7 Trip SR User Alarm 2

125 V>1 Trip A/AB RTD 8 Trip SR User Alarm 1

126 V>1 Trip B/BC RTD 9 Trip 100% ST EF Trip

127 V>1 Trip C/CA RTD 10 Trip DeadMachine Trip

128 V>2 Trip Any RTD Trip Gen Diff Trip

129 V>2 Trip A/AB IN>1 Trip Gen Diff Trip A

130 V>2 Trip B/BC IN>2 Trip Gen Diff Trip B

131 V>2 Trip C/CA IREF> Trip Gen Diff Trip C

132 F<1 Trip ISEF>1 Trip Field Fail1 Trip

133 F<2 Trip VN>1 Trip Field Fail2 Trip

134 F<3 Trip VN>2 Trip NPS Trip

135 F<4 Trip V<1 Trip V Dep OC Trip

136 F>1 Trip V<1 Trip A/AB V Dep OC Trip A

137 F>2 Trip V<1 Trip B/BC V Dep OC Trip B

138 Power1 Trip V<1 Trip C/CA V Dep OC Trip C

139 Power2 Trip V<2 Trip V/Hz Trip

140 I>1 Trip V<2 Trip A/AB RTD 1 Trip

141 I>1 Trip A V<2 Trip B/BC RTD 2 Trip

142 I>1 Trip B V<2 Trip C/CA RTD 3 Trip

143 I>1 Trip C V>1 Trip RTD 4 Trip

144 I>2 Trip V>1 Trip A/AB RTD 5 Trip

145 I>2 Trip A V>1 Trip B/BC RTD 6 Trip

146 I>2 Trip B V>1 Trip C/CA RTD 7 Trip

147 I>2 Trip C V>2 Trip RTD 8 Trip

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 74/170

P341 P342 P343

148 I>3 Trip V>2 Trip A/AB RTD 9 Trip

149 I>3 Trip A V>2 Trip B/BC RTD 10 Trip

150 I>3 Trip B V>2 Trip C/CA Any RTD Trip

151 I>3 Trip C F<1 Trip IN>1 Trip

152 I>4 Trip F<2 Trip IN>2 Trip

153 I>4 Trip A F<3 Trip IREF> Trip

154 I>4 Trip B F<4 Trip ISEF>1 Trip

155 I>4 Trip C F>1 Trip VN>1 Trip

156 Bfail1 Trip 3ph F>2 Trip VN>2 Trip

157 Bfail2 Trip 3ph Power1 Trip V<1 Trip

158 SPower1 Trip Power2 Trip V<1 Trip A/AB

159 SPower2 Trip I>1 Trip V<1 Trip B/BC

160 Thermal O/L Trip I>1 Trip A V<1 Trip C/CA

161 CL Input 1 Trip I>1 Trip B V<2 Trip

162 CL Input 2 Trip I>1 Trip C V<2 Trip A/AB

163 CL Input 3 Trip I>2 Trip V<2 Trip B/BC

164 CL Input 4 Trip I>2 Trip A V<2 Trip C/CA

165 Any Start I>2 Trip B V>1 Trip

166 VN>1 Start I>2 Trip C V>1 Trip A/AB

167 VN>2 Start Bfail1 Trip 3ph V>1 Trip B/BC

168 V<1 Start Bfail2 Trip 3ph V>1 Trip C/CA

169 V<1 Start A/AB SPower1 Trip V>2 Trip

170 V<1 Start B/BC SPower2 Trip V>2 Trip A/AB

171 V<1 Start C/CA Thermal O/L Trip V>2 Trip B/BC

172 V<2 Start Z<1 Trip V>2 Trip C/CA

173 V<2 Start A/AB Z<1 Trip A F<1 Trip

174 V<2 Start B/BC Z<1 Trip B F<2 Trip

175 V<2 Start C/CA Z<1 Trip C F<3 Trip

176 V>1 Start Z<2 Trip F<4 Trip

177 V>1 Start A/AB Z<2 Trip A F>1 Trip

178 V>1 Start B/BC Z<2 Trip B F>2 Trip

179 V>1 Start C/CA Z<2 Trip C Power1 Trip

180 V>2 Start CL Input 1 Trip Power2 Trip

181 V>2 Start A/AB CL Input 2 Trip I>1 Trip

182 V>2 Start B/BC CL Input 3 Trip I>1 Trip A

183 V>2 Start C/CA CL Input 4 Trip I>1 Trip B

184 Power1 Start Any Start I>1 Trip C

185 Power2 Start VN>1 Start I>2 Trip

186 I>1 Start VN>2 Start I>2 Trip A

187 I>1 Start A V<1 Start I>2 Trip B

188 I>1 Start B V<1 Start A/AB I>2 Trip C

189 I>1 Start C V<1 Start B/BC Bfail1 Trip 3ph

190 I>2 Start V<1 Start C/CA Bfail2 Trip 3ph

191 I>2 Start A V<2 Start SPower1 Trip

192 I>2 Start B V<2 Start A/AB SPower2 Trip

193 I>2 Start C V<2 Start B/BC PSlipz Z1 Trip

194 I>3 Start V<2 Start C/CA PSlipz Z2 Trip

195 I>3 Start A V>1 Start Thermal O/L Trip

196 I>3 Start B V>1 Start A/AB Z<1 Trip

197 I>3 Start C V>1 Start B/BC Z<1 Trip A

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 75/170

P341 P342 P343

198 I>4 Start V>1 Start C/CA Z<1 Trip B

199 I>4 Start A V>2 Start Z<1 Trip C

200 I>4 Start B V>2 Start A/AB Z<2 Trip

201 I>4 Start C V>2 Start B/BC Z<2 Trip A

202 IN>1 Start V>2 Start C/CA Z<2 Trip B

203 IN>2 Start Power1 Start Z<2 Trip C

204 IN>3 Start Power2 Start CL Input 1 Trip

205 IN>4 Start I>1 Start CL Input 2 Trip

206 ISEF>1 Start I>1 Start A CL Input 3 Trip

207 ISEF>2 Start I>1 Start B CL Input 4 Trip

208 ISEF>3 Start I>1 Start C Any Start

209 ISEF>4 Start I>2 Start VN>1 Start

210 F<1 Start I>2 Start A VN>2 Start

211 F<2 Start I>2 Start B V<1 Start

212 F<3 Start I>2 Start C V<1 Start A/AB

213 F<4 Start IN>1 Start V<1 Start B/BC

214 F>1 Start IN>2 Start V<1 Start C/CA

215 F>2 Start ISEF>1 Start V<2 Start

216 I> BlockStart F<1 Start V<2 Start A/AB

217 IN/SEF>Blk Start F<2 Start V<2 Start B/BC

218 df/dt Start F<3 Start V<2 Start C/CA

219 IA< Start F<4 Start V>1 Start

220 IB< Start F>1 Start V>1 Start A/AB

221 IC< Start F>2 Start V>1 Start B/BC

222 ISEF< Start IA< Start V>1 Start C/CA

223 SPower1 Start IB< Start V>2 Start

224 SPower2 Start IC< Start V>2 Start A/AB

225 CLI1 Alarm Start ISEF< Start V>2 Start B/BC

226 CLI2 Alarm Start IN< Start V>2 Start C/CA

227 CLI3 Alarm Start V/Hz Start Power1 Start

228 CLI4 Alarm Start FFail1 Start Power2 Start

229 CLI1 Trip Start FFail2 Start I>1 Start

230 CLI2 Trip Start V Dep OC Start I>1 Start A

231 CLI3 Trip Start V Dep OC Start A I>1 Start B

232 CLI4 Trip Start V Dep OC Start B I>1 Start C

233 VTS Fast Block V Dep OC Start C I>2 Start

234 VTS Slow Block SPower1 Start I>2 Start A

235 CTS Block SPower2 Start I>2 Start B

236 Control Trip Z<1 Start I>2 Start C

237 Control Close Z<1 Start A IN>1 Start

238 Close in Prog Z<1 Start B IN>2 Start

239 Reconnection Z<1 Start C ISEF>1 Start

240 Lockout Alarm Z<2 Start 100% ST EF Start

241 CB Open 3 ph Z<2 Start A F<1 Start

242 CB Closed 3 ph Z<2 Start B F<2 Start

243 Field volts fail Z<2 Start C F<3 Start

244 All Poles Dead CLI1 Alarm Start F<4 Start

245 Any Pole Dead CLI2 Alarm Start F>1 Start

246 Pole Dead A CLI3 Alarm Start F>2 Start

247 Pole Dead B CLI4 Alarm Start IA< Start

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P34x/EN GC/F33

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P341 P342 P343

248 Pole Dead C CLI1 Trip Start IB< Start

249 CLI2 Trip Start IC< Start

250 CLI3 Trip Start ISEF< Start

251 CLI4 Trip Start IN< Start

252 VTS Fast Block V/Hz Start

253 VTS Slow Block FFail1 Start

254 CTS Block FFail2 Start

255 RTD 1 Alarm V Dep OC Start

256 RTD 2 Alarm V Dep OC Start A

257 RTD 3 Alarm V Dep OC Start B

258 RTD 4 Alarm V Dep OC Start C

259 RTD 5 Alarm SPower1 Start

260 RTD 6 Alarm SPower2 Start

261 RTD 7 Alarm PSlipz Z1 Start

262 RTD 8 Alarm PSlipz Z2 Start

263 RTD 9 Alarm PSlipz LensStart

264 RTD 10 Alarm PSlipz BlindStrt

265 Lockout Alarm PSlipz ReactStrt

266 CB Open 3 ph Z<1 Start

267 CB Closed 3 ph Z<1 Start A

268 Field volts fail Z<1 Start B

269 All Poles Dead Z<1 Start C

270 Any Pole Dead Z<2 Start

271 Pole Dead A Z<2 Start A

272 Pole Dead B Z<2 Start B

273 Pole Dead C Z<2 Start C

274 CLI1 Alarm Start




278 CLI1 Trip Start

279 CLI2 Trip Start

280 CLI3 Trip Start

281 CLI4 Trip Start

282 VTS Fast Block

283 VTS Slow Block

284 CTS Block

285 RTD 1 Alarm

286 RTD 2 Alarm

287 RTD 3 Alarm

288 RTD 4 Alarm

289 RTD 5 Alarm

290 RTD 6 Alarm

291 RTD 7 Alarm

292 RTD 8 Alarm

293 RTD 9 Alarm

294 RTD 10 Alarm

295 Lockout Alarm

296 CB Open 3 ph

297 CB Closed 3 ph

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P34x/EN GC/F33

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P341 P342 P343

298 Field volts fail

299 All Poles Dead

300 Any Pole Dead

301 Pole Dead A

302 Pole Dead B

303 Pole Dead C

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P34x/EN GC/F33

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CLIO Output Measurement

Unit Minimum Maximum Step SizeDefault

MinimumDefault

MaximumPri/Sec

Multiplier

IA Magnitude A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IB Magnitude A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IC Magnitude A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IN Measured Mag A 0*I2 16*I2 0.01*I2 0*I2 1.2*I2 M5

IN Derived Mag A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

I Sen Magnitude A 0*I3 16*I3 0.01*I3 0*I3 1.2*I3 M6

I1 Magnitude A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4



IA RMS A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IB RMS A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IC RMS A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

VAB Magnitude V 0*V1 200*V1 0.1*V1 0*V1 140*V1 M1

VBC Magnitude V 0*V1 200*V1 0.1*V1 0*V1 140*V1 M1

VCA Magnitude V 0*V1 200*V1 0.1*V1 0*V1 140*V1 M1

VAN Magnitude V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

VBN Magnitude V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

VCN Magnitude V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

VN Measured Mag V 0*V3 200*V3 0.1*V3 0*V3 80*V3 M3

VN Derived Mag V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

V1 Magnitude V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1



VAN RMS V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

VBN RMS V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

VCN RMS V 0*V1 200*V1 0.1*V1 0*V1 80*V1 M1

Frequency Hz 0 70 0.01 45 65

3 Phase Watts W -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

A Phase Watts W -2000*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

B Phase Watts W -2000*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

C Phase Watts W -2000*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

3 Phase Vars Var -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

A Phase Vars Var -2000*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

B Phase Vars Var -2000*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

Measurements Range for Each G155 Selection

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P34x/EN GC/F33

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MinimumDefault

MaximumPri/Sec

Multiplier

C Phase Vars Var -2000*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

3 Phase VA VA 0*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

A Phase VA VA 0*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

B Phase VA VA 0*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

C Phase VA VA 0*V1*I1 2000*V1*I1 1*V1*I1 0*V1*I1 100*V1*I1 M1*M4

3Ph Power Factor -1 1 0.01 0 1

APh Power Factor -1 1 0.01 0 1

BPh Power Factor -1 1 0.01 0 1

CPh Power Factor -1 1 0.01 0 1

3Ph W Fix Demand W -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

3Ph Vars Fix Dem Var -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

IA Fixed Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IB Fixed Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IC Fixed Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

3 Ph W Roll Dem W -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

3Ph Vars RollDem Var -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

IA Roll Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IB Roll Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IC Roll Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

3Ph W Peak Dem W -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

3Ph Var Peak Dem Var -6000*V1*I1 6000*V1*I1 1*V1*I1 0*V1*I1 300*V1*I1 M1*M4

IA Peak Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IB Peak Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

IC Peak Demand A 0*I1 16*I1 0.01*I1 0*I1 1.2*I1 M4

VN 3rd Harmonic V 0*V3 200*V3 0.1*V3 0*V3 80*V3 M3

NPS Thermal % 0 200 0.01 0 120

Thermal Overload % 0 200 0.01 0 120

RTD 1 °C -40 300 0.1 0 200

RTD 2 °C -40 300 0.1 0 200

RTD 3 °C -40 300 0.1 0 200

RTD 4 °C -40 300 0.1 0 200

RTD 5 °C -40 300 0.1 0 200

RTD 6 °C -40 300 0.1 0 200

RTD 7 °C -40 300 0.1 0 200

RTD 8 °C -40 300 0.1 0 200

RTD 9 °C -40 300 0.1 0 200

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P34x/EN GC/F33

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MinimumDefault

MaximumPri/Sec

Multiplier

RTD 10 °C -40 300 0.1 0 200

CL Input 1 -9999 9999 0.1 0 9999

CL Input 2 -9999 9999 0.1 0 9999

CL Input 3 -9999 9999 0.1 0 9999

CL Input 4 -9999 9999 0.1 0 9999

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P34x/EN GC/F33

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DDB No. Source DescriptionEnglish Text

0123456789ABCDEFP341 P342 P343

0 Output Condition Output Relay 1 see 4B01 * * *









9 Output Condition Output Relay 10 see 4B0A * * *

10 Output Condition Output Relay 11 see 4B0B * * *

11 Output Condition Output Relay 12 see 4B0C * * *

12 Output Condition Output Relay 13 see 4B0D * * *

13 Output Condition Output Relay 14 see 4B0E * * *

14 Output Condition Output Relay 15 see 4B0F * * *










24 Output Condition Output Relay 25 see 4B19 *

25 Output Condition Output Relay 26 see 4B1A *

26 Output Condition Output Relay 27 see 4B1B *

27 Output Condition Output Relay 28 see 4B1C *

28 Output Condition Output Relay 29 see 4B1D *

29 Output Condition Output Relay 30 see 4B1E *

30 Output Condition Output Relay 31 see 4B1F *

31 Output Condition Output Relay 32 see 4B20 *

32 OPTO Opto Isolator Input 1 (setting group selector) see 4A01 * * *

33 OPTO Opto Isolator Input 2 (setting group selector) see 4A02 * * *

34 OPTO Opto Isolator Input 3 see 4A03 * * *







41 OPTO Opto Isolator Input 10 see 4A0A * * *

42 OPTO Opto Isolator Input 11 see 4A0B * * *

43 OPTO Opto Isolator Input 12 see 4A0C * * *

44 OPTO Opto Isolator Input 13 see 4A0D * * *

45 OPTO Opto Isolator Input 14 see 4A0E * * *

46 OPTO Opto Isolator Input 15 see 4A0F * * *


Digital Data Bus

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0123456789ABCDEFP341 P342 P343









56 OPTO Opto Isolator Input 25 see 4A19 *

57 OPTO Opto Isolator Input 26 see 4A1A *

58 OPTO Opto Isolator Input 27 see 4A1B *

59 OPTO Opto Isolator Input 28 see 4A1C *

60 OPTO Opto Isolator Input 29 see 4A1D *

61 OPTO Opto Isolator Input 30 see 4A1E *

62 OPTO Opto Isolator Input 31 see 4A1F *

63 OPTO Opto Isolator Input 32 see 4A20 *

64 Output Condition LED 1 LED 1 * * *








72 UNUSED

73 UNUSED

74 UNUSED

75 UNUSED

76 UNUSED

77 UNUSED

78 UNUSED

79 UNUSED

80 PSL LED Conditioner IN 1 LED Cond IN 1 * * *








88 UNUSED

89 UNUSED

90 UNUSED

91 UNUSED

92 UNUSED

93 UNUSED

94 UNUSED

95 UNUSED

96 UNUSED

97 UNUSED

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

98 UNUSED

99 UNUSED

100 UNUSED

101 UNUSED

102 UNUSED

103 UNUSED

104 UNUSED

105 UNUSED

106 UNUSED

107 UNUSED

108 UNUSED

109 UNUSED

110 UNUSED

111 UNUSED

112 UNUSED

113 UNUSED

114 UNUSED

115 UNUSED

116 UNUSED

117 UNUSED

118 UNUSED

119 UNUSED

120 UNUSED

121 UNUSED

122 UNUSED

123 UNUSED

124 UNUSED

125 UNUSED

126 UNUSED

127 UNUSED

128 UNUSED

129 UNUSED

130 UNUSED

131 UNUSED

132 UNUSED

133 UNUSED

134 UNUSED

135 UNUSED

136 UNUSED

137 UNUSED

138 UNUSED

139 UNUSED

140 UNUSED

141 UNUSED

142 UNUSED

143 UNUSED

144 UNUSED

145 UNUSED

146 UNUSED

147 UNUSED

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0123456789ABCDEFP341 P342 P343

148 UNUSED

149 UNUSED

150 UNUSED

151 UNUSED

152 UNUSED

153 UNUSED

154 UNUSED

155 UNUSED

156 UNUSED

157 UNUSED

158 UNUSED

159 UNUSED

160 PSL Relay Conditioner 1 Relay Cond 1 * * *


162 PSL Relay Conditioner 3 - Any Trip Any Trip * * *






















184 PSL Relay Conditioner 25 Relay Cond 25 *








192 UNUSED

193 UNUSED

194 UNUSED

195 UNUSED

196 UNUSED

197 UNUSED

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0123456789ABCDEFP341 P342 P343

198 UNUSED

199 UNUSED

200 UNUSED

201 UNUSED

202 UNUSED

203 UNUSED

204 UNUSED

205 UNUSED

206 UNUSED

207 UNUSED

208 UNUSED

209 UNUSED

210 UNUSED

211 UNUSED

212 UNUSED

213 UNUSED

214 UNUSED

215 UNUSED

216 UNUSED

217 UNUSED

218 UNUSED

219 UNUSED

220 UNUSED

221 UNUSED

222 UNUSED

223 UNUSED

224 PSL Timer in 1 Timer in 1 * * *








232 UNUSED

233 UNUSED

234 UNUSED

235 UNUSED

236 UNUSED

237 UNUSED

238 UNUSED

239 UNUSED

240 UNUSED

241 UNUSED

242 UNUSED

243 UNUSED

244 UNUSED

245 UNUSED

246 UNUSED

247 UNUSED

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

248 UNUSED

249 UNUSED

250 UNUSED

251 UNUSED

252 UNUSED

253 UNUSED

254 UNUSED

255 UNUSED

256 Auxiliary Timer Timer out 1 Timer out 1 * * *








264 UNUSED

265 UNUSED

266 UNUSED

267 UNUSED

268 UNUSED

269 UNUSED

270 UNUSED

271 UNUSED

272 UNUSED

273 UNUSED

274 UNUSED

275 UNUSED

276 UNUSED

277 UNUSED

278 UNUSED

279 UNUSED

280 UNUSED

281 UNUSED

282 UNUSED

283 UNUSED

284 UNUSED

285 UNUSED

286 UNUSED

287 UNUSED

288 PSL Fault Record Trigger Input Fault REC TRIG * * *

289 UNUSED

290 Group Selection Setting Group via Opto Invalid SG-opto Invalid * * *

291 Commission Test Test Mode Enabled Prot'n Disabled * * *

292 VT Supervision VTS Indication VT Fail Alarm * * *

293 CT Supervision CTS Indication CT Fail Alarm * * *

294 Breaker Fail Breaker Fail Any Trip CB Fail Alarm * * *

295 CB Monitoring Broken Current Maintenance Alarm I^ Maint Alarm * * *

296 CB Monitoring Broken Current Lockout Alarm I^ Lockout Alarm * * *

297 CB Monitoring Number of CB Operations Maintenance Alarm CB Ops Maint * * *

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

298 CB Monitoring Number of CB Operations Maintenance Lockout CB Ops Lockout * * *

299 CB Monitoring Excessive CB Operation Time Maintenance Alarm CB Op Time Maint * * *

300 CB Monitoring Excessive CB Operation Time Lockout Alarm CB Op Time Lock * * *

301 CB Monitoring Excessive Fault Frequency Lockout Alarm Fault Freq Lock * * *

302 CB Status CB Status Alarm CB Status Alarm * * *

303 CB Control CB Failed to Trip Man CB Trip Fail * * *

304 CB Control CB Failed to Close Man CB Cls Fail * * *

305 CB Control Control CB Unhealthy Man CB Unhealthy * * *

306 Frequency Tracking Frequency Out of Range F out of Range *

306 NPS Thermal Negative Phase Sequence Alarm NPS Alarm * *

307 Thermal Overload Thermal Overload Alarm Thermal Alarm * * *

308 Overfluxing Volts Per Hz Alarm V/Hz Alarm * *

309 Field Failure Field Failure Alarm Field Fail Alarm * *

310 RTD Thermal RTD Thermal Alarm RTD Thermal Alm * *

311 RTD Thermal RTD Open Circuit Failure RTD Open Cct * *

312 RTD Thermal RTD Short Circuit Failure RTD short Cct * *

313 RTD Thermal RTD Data Inconsistency Error RTD Data Error * *

314 RTD Thermal RTD Board Failure RTD Board Fail * *

315 PSL Frequency Protection Alarm Freq Prot Alm * * *

316 PSL Voltage Protection Alarm Voltage Prot Alm * * *

317 UNUSED

318 UNUSED

319 UNUSED

320 Current Loop Inputs CLIO Input Board Failure CL Card I/P Fail * * *

321 Current Loop Outputs CLIO Output Board Failure CL Card O/P Fail * * *

322 Current Loop Inputs Current Loop Input 1 Alarm CL Input 1 Alarm * * *




326 Current Loop Inputs Current Loop Input 1 Undercurrent Fail Alarm CLI1 I< Fail Alm * * *




330 UNUSED

331 UNUSED

332 UNUSED

333 UNUSED

334 UNUSED

335 UNUSED

336 PSL User Definable Alarm 16 (Manual Reset) MR User Alarm 16 * * *











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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343


348 PSL User Definable Alarm 4 (Self Reset) SR User Alarm 4 * * *




352 PSL Block Voltage Dependant Overcurrent time delay VDepOC Timer Blk * *

353 PSL Block Under Impedance time delay UnderZ Timer Blk * *

354 PSL Block Phase Overcurrent Stage 1 time delay I>1 Timer Block * * *

355 PSL Block Phase Overcurrent Stage 2 time delay I>2 Timer Block * * *

356 PSL Block Phase Overcurrent Stage 3 time delay I>3 Timer Block *

357 PSL Block Phase Overcurrent Stage 4 time delay I>4 Timer Block *

358 PSL Block Earth Fault Stage 1 time delay IN>1 Timer Blk * * *

359 PSL Block Earth Fault Stage 2 time delay IN>2 Timer Blk * * *

360 PSL Block Earth Fault Stage 3 time delay IN>3 Timer Blk *

361 PSL Block Earth Fault Stage 4 time delay IN>4 Timer Blk *

362 PSL Block SEF Stage 1 time delay ISEF>1 Timer Blk * * *

363 PSL Block SEF Stage 2 time delay ISEF>2 Timer Blk *



366 PSL Logic Input Trip CB Init Trip CB *

367 PSL Logic Input Close CB Init Close CB *

368 PSL Block Residual Overvoltage Stage 1 time delay VN>1 Timer Blk * * *

369 PSL Block Residual Overvoltage Stage 2 time delay VN>2 Timer Blk * * *

370 PSL Block Phase Undervoltage Stage 1 time delay V<1 Timer Block * * *

371 PSL Block Phase Undervoltage Stage 2 time delay V<2 Timer Block * * *

372 PSL Block Phase Overvoltage Stage 1 time delay V>1 Timer Block * * *

373 PSL Block Phase Overvoltage Stage 2 time delay V>2 Timer Block * * *

374 PSL Block Underfrequency Stage 1 Timer F<1 timer Block * * *

375 PSL Block Underfrequency Stage 2 Timer F<2 Timer Block * * *



378 PSL Block Overfrequency Stage 1 Timer F>1 Timer Block * * *

379 PSL Block Overfrequency Stage 2 Timer F>2 Timer Block * * *

380 PSL External Trip 3ph Ext. Trip 3ph * * *

381 PSL 52-A (3 phase) CB Aux 3ph(52-A) * * *

382 PSL 52-B (3 phase) CB Aux 3ph(52-B) * * *

383 PSL CB Healthy CB Healthy * * *

384 PSL MCB/VTS opto MCB/VTS * * *

385 PSL Reset Manual CB Close Time Delay Reset Close Dly * * *

386 PSL Reset Latched Relays & LED’s Reset Relays/LED * * *

387 PSL Reset Lockout Opto Input Reset Lockout * * *

388 PSL Reset CB Maintenance Values Reset All Values * * *

389 PSL Reset NPS Thermal State Reset I2 Thermal * *

390 PSL Reset Thermal Overload State Reset ThermalO/L * * *

391 PSL IEC60870-5-103 Monitor Blocking Monitor Blocked * * *

392 PSL IEC60870-5-103 Command Blocking Command Blocked * * *

393 PSL Block Current Loop Input 1 protection CL Input 1 Blk * * *




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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

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 UNUSED

413 UNUSED

414 UNUSED

415 PSL Initiate Test Mode Test Mode * * *

416 100% Stator Earth Fault 100% Stator Earth Fault Trip 100% ST EF Trip *

417 Dead Machine Dead Machine Protection Trip DeadMachine Trip *

418 Generator Differential Generator Differential Trip 3ph Gen Diff Trip *

419 Generator Differential Generator Differential Trip A Gen Diff Trip A *

420 Generator Differential Generator Differential Trip B Gen Diff Trip B *

421 Generator Differential Generator Differential Trip C Gen Diff Trip C *

422 Field Failure Field Failure Stage 1 Trip Field Fail1 Trip * *

423 Field Failure Field Failure Stage 2 Trip Field Fail2 Trip * *

424 NPS Thermal Negative Phase Sequence Trip NPS Trip * *

425 System Backup Voltage Dependant Overcurrent Trip 3ph V Dep OC Trip * *

426 System Backup Voltage Dependant Overcurrent Trip A V Dep OC Trip A * *

427 System Backup Voltage Dependant Overcurrent Trip B V Dep OC Trip B * *

428 System Backup Voltage Dependant Overcurrent Trip C V Dep OC Trip C * *

429 Overfluxing Volts per Hz Trip V/Hz Trip * *

430 RTD Thermal RTD 1 Trip RTD 1 Trip * *










440 RTD Thermal Any RTD Trip Any RTD Trip * *

440 df/dt Rate Of Change Of Frequency Trip df/dt Trip *

441 Voltage Vector Shift Voltage Vector Shift Trip V Shift Trip *

442 Earth Fault 1st Stage EF Trip IN>1 Trip * * *

443 Earth Fault 2nd Stage EF Trip IN>2 Trip * * *

444 Earth Fault 3rd Stage EF Trip IN>3 Trip *

445 Earth Fault 4th Stage EF Trip IN>4 Trip *

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

446 Restricted Earth Fault REF Trip IREF> Trip * * *

447 Sensitive Earth Fault 1st Stage SEF Trip ISEF>1 Trip * * *

448 Sensitive Earth Fault 2nd Stage SEF Trip ISEF>2 Trip *

449 Sensitive Earth Fault 3rd Stage SEF Trip ISEF>3 Trip *

450 Sensitive Earth Fault 4th Stage SEF Trip ISEF>4 Trip *

451 Neutral Displacement 1st Stage Residual O/V Trip VN>1 Trip * * *

452 Neutral Displacement 2nd Stage Residual O/V Trip VN>2 Trip * * *

453 Under Voltage 1st Stage Phase U/V Trip 3ph V<1 Trip * * *

454 Under Voltage 1st Stage Phase U/V Trip A/AB V<1 Trip A/AB * * *

455 Under Voltage 1st Stage Phase U/V Trip B/BC V<1 Trip B/BC * * *

456 Under Voltage 1st Stage Phase U/V Trip C/CA V<1 Trip C/CA * * *

457 Under Voltage 2nd Stage Phase U/V Trip 3ph V<2 Trip * * *

458 Under Voltage 2nd Stage Phase U/V Trip A/AB V<2 Trip A/AB * * *

459 Under Voltage 2nd Stage Phase U/V Trip B/BC V<2 Trip B/BC * * *

460 Under Voltage 2nd Stage Phase U/V Trip C/CA V<2 Trip C/CA * * *

461 Over Voltage 1st Stage Phase O/V Trip 3ph V>1 Trip * * *

462 Over Voltage 1st Stage Phase O/V Trip A/AB V>1 Trip A/AB * * *

463 Over Voltage 1st Stage Phase O/V Trip B/BC V>1 Trip B/BC * * *

464 Over Voltage 1st Stage Phase O/V Trip C/CA V>1 Trip C/CA * * *

465 Over Voltage 2nd Stage Phase O/V Trip 3ph V>2 Trip * * *

466 Over Voltage 2nd Stage Phase O/V Trip A/AB V>2 Trip A/AB * * *

467 Over Voltage 2nd Stage Phase O/V Trip B/BC V>2 Trip B/BC * * *

468 Over Voltage 2nd Stage Phase O/V Trip C/CA V>2 Trip C/CA * * *

469 Under Frequency Under Frequency Stage 1 Trip F<1 Trip * * *




473 Over Frequency Over Frequency Stage 1 Trip F>1 Trip * * *

474 Over Frequency Over Frequency Stage 2 Trip F>2 Trip * * *

475 Power Power Stage 1 Trip Power1 Trip * * *

476 Power Power Stage 2 Trip Power2 Trip * * *

477 Over Current 1st Stage O/C Trip 3ph I>1 Trip * * *

478 Over Current 1st Stage O/C Trip A I>1 Trip A * * *

479 Over Current 1st Stage O/C Trip B I>1 Trip B * * *

480 Over Current 1st Stage O/C Trip C I>1 Trip C * * *

481 Over Current 2nd Stage O/C Trip 3ph I>2 Trip * * *

482 Over Current 2nd Stage O/C Trip A I>2 Trip A * * *

483 Over Current 2nd Stage O/C Trip B I>2 Trip B * * *

484 Over Current 2nd Stage O/C Trip C I>2 Trip C * * *

485 Over Current 3rd Stage O/C Trip 3ph I>3 Trip *

486 Over Current 3rd Stage O/C Trip A I>3 Trip A *

487 Over Current 3rd Stage O/C Trip B I>3 Trip B *

488 Over Current 3rd Stage O/C Trip C I>3 Trip C *

489 Over Current 4th Stage O/C Trip 3ph I>4 Trip *

490 Over Current 4th Stage O/C Trip A I>4 Trip A *

491 Over Current 4th Stage O/C Trip B I>4 Trip B *

492 Over Current 4th Stage O/C Trip C I>4 Trip C *

493 Breaker failure tBF1 Trip 3ph Bfail1 Trip 3ph * * *

494 Breaker failure tBF2 Trip 3ph Bfail2 Trip 3ph * * *

495 Sensitive Power Sensitive A Phase Power Stage 1 Trip SPower1 Trip * * *

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MiCOM P342, P343

P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

496 Sensitive Power Sensitive A Phase Power Stage 2 Trip SPower2 Trip * * *

497 Z based Pole Slipping Pole Slip (Impedance) Zone1 Trip PSlipz Z1 Trip *

498 Z based Pole Slipping Pole Slip (Impedance) Zone2 Trip PSlipz Z2 Trip *

499 Thermal Overload Thermal Overload Trip Thermal O/L Trip * * *

500 System Backup Underimpedance 3Phase Stage 1 Trip Z<1 Trip * *

501 System Backup Underimpedance Phase A Stage 1 Trip Z<1 Trip A * *

502 System Backup Underimpedance Phase B Stage 1 Trip Z<1 Trip B * *

503 System Backup Underimpedance Phase C Stage 1 Trip Z<1 Trip C * *

504 System Backup Underimpedance 3Phase Stage 2 Trip Z<2 Trip * *

505 System Backup Underimpedance Phase A Stage 2 Trip Z<2 Trip A * *

506 System Backup Underimpedance Phase B Stage 2 Trip Z<2 Trip B * *

507 System Backup Underimpedance Phase C Stage 2 Trip Z<2 Trip C * *

508 Current Loop Inputs Current Loop Input 1 Trip CL Input 1 Trip * * *




512 UNUSED

513 UNUSED

514 UNUSED

515 UNUSED

516 UNUSED

517 UNUSED

518 UNUSED

519 UNUSED

520 UNUSED

521 UNUSED

522 UNUSED

523 UNUSED

524 UNUSED

525 UNUSED

526 UNUSED

527 UNUSED

528 UNUSED

529 UNUSED

530 UNUSED

531 UNUSED

532 UNUSED

533 UNUSED

534 UNUSED

535 UNUSED

536 UNUSED

537 UNUSED

538 UNUSED

539 UNUSED

540 UNUSED

541 UNUSED

542 UNUSED

543 UNUSED

544 UNUSED

545 UNUSED

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MiCOM P342, P343

P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

546 UNUSED

547 UNUSED

548 UNUSED

549 UNUSED

550 UNUSED

551 UNUSED

552 UNUSED

553 UNUSED

554 UNUSED

555 UNUSED

556 UNUSED

557 UNUSED

558 UNUSED

559 UNUSED

560 UNUSED

561 UNUSED

562 UNUSED

563 UNUSED

564 UNUSED

565 UNUSED

566 UNUSED

567 UNUSED

568 UNUSED

569 UNUSED

570 UNUSED

571 UNUSED

572 UNUSED

573 UNUSED

574 UNUSED

575 UNUSED

576 All protection Any Start Any Start * * *

577 Neutral displacement 1st Stage Residual O/V Start VN>1 Start * * *

578 Neutral displacement 2nd Stage Residual O/V Start VN>2 Start * * *

579 Under Voltage 1st Stage Phase U/V Start 3ph V<1 Start * * *

580 Under Voltage 1st Stage Phase U/V Start A/AB V<1 Start A/AB * * *

581 Under Voltage 1st Stage Phase U/V Start B/BC V<1 Start B/BC * * *

582 Under Voltage 1st Stage Phase U/V Start C/CA V<1 Start C/CA * * *

583 Under Voltage 2nd Stage Phase U/V Start 3ph V<2 Start * * *

584 Under Voltage 2nd Stage Phase U/V Start A/AB V<2 Start A/AB * * *

585 Under Voltage 2nd Stage Phase U/V Start B/BC V<2 Start B/BC * * *

586 Under Voltage 2nd Stage Phase U/V Start C/CA V<2 Start C/CA * * *

587 Over Voltage 1st Stage Phase O/V Start 3ph V>1 Start * * *

588 Over Voltage 1st Stage Phase O/V Start A/AB V>1 Start A/AB * * *

589 Over Voltage 1st Stage Phase O/V Start B/BC V>1 Start B/BC * * *

590 Over Voltage 1st Stage Phase O/V Start C/CA V>1 Start C/CA * * *

591 Over Voltage 2nd Stage Phase O/V Start 3ph V>2 Start * * *

592 Over Voltage 2nd Stage Phase O/V Start A/AB V>2 Start A/AB * * *

593 Over Voltage 2nd Stage Phase O/V Start B/BC V>2 Start B/BC * * *

594 Over Voltage 2nd Stage Phase O/V Start C/CA V>2 Start C/CA * * *

595 Power Power Stage 1 Start Power1 Start * * *

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

596 Power Power Stage 2 Start Power2 Start * * *

597 Over Current 1st Stage O/C Start 3ph I>1 Start * * *

598 Over Current 1st Stage O/C Start A I>1 Start A * * *

599 Over Current 1st Stage O/C Start B I>1 Start B * * *

600 Over Current 1st Stage O/C Start C I>1 Start C * * *

601 Over Current 2nd Stage O/C Start 3ph I>2 Start * * *

602 Over Current 2nd Stage O/C Start A I>2 Start A * * *

603 Over Current 2nd Stage O/C Start B I>2 Start B * * *

604 Over Current 2nd Stage O/C Start C I>2 Start C * * *

605 Over Current 3rd Stage O/C Start 3ph I>3 Start *

606 Over Current 3rd Stage O/C Start A I>3 Start A *

607 Over Current 3rd Stage O/C Start B I>3 Start B *

608 Over Current 3rd Stage O/C Start C I>3 Start C *

609 Over Current 4th Stage O/C Start 3ph I>4 Start *

610 Over Current 4th Stage O/C Start A I>4 Start A *

611 Over Current 4th Stage O/C Start B I>4 Start B *

612 Over Current 4th Stage O/C Start C I>4 Start C *

613 Earth Fault 1st Stage EF Start IN>1 Start * * *

614 Earth Fault 2nd Stage EF Start IN>2 Start * * *

615 Earth Fault 3rd Stage EF Start IN>3 Start *

616 Earth Fault 4th Stage EF Start IN>4 Start *

617 Sensitive Earth Fault 1st Stage SEF Start ISEF>1 Start * * *

618 Sensitive Earth Fault 2nd Stage SEF Start ISEF>2 Start *

619 Sensitive Earth Fault 3rd Stage SEF Start ISEF>3 Start *

620 Sensitive Earth Fault 4th Stage SEF Start ISEF>4 Start *

621 100% Stator Earth Fault 100% Stator Earth Fault Start 100% ST EF Start *

622 Under Frequency Under Frequency Stage 1 Start F<1 Start * * *




626 Over Frequency Over Frequency Stage 1 Start F>1 Start * * *

627 Over Frequency Over Frequency Stage 2 Start F>2 Start * * *

628 Over Current I> Blocked O/C Start I> BlockStart *

629 Over Current IN/ISEF> Blocked O/C Start IN/SEF>Blk Start *

630 df/dt Rate Of Change Of Frequency Start df/dt Start *

631 Under Current IA< Operate IA< Start * * *

632 Under Current IB< Operate IB< Start * * *

633 Under Current IC< Operate IC< Start * * *

634 Under Current ISEF< Operate ISEF< Start * * *

635 Under Current IN< Operate IN< Start * *

636 Overfluxing Volts per Hz Start V/Hz Start * *

637 Field Failure Field Failure Stage 1 Start FFail1 Start * *

638 Field Failure Field Failure Stage 2 Start FFail2 Start * *

639 System Backup Voltage Dependant Overcurrent Start 3Ph V Dep OC Start * *

640 System Backup Voltage Dependant Overcurrent Start A V Dep OC Start A * *

641 System Backup Voltage Dependant Overcurrent Start B V Dep OC Start B * *

642 System Backup Voltage Dependant Overcurrent Start C V Dep OC Start C * *

643 Sensitive Power Sensitive A Phase Power Stage 1 Start SPower1 Start * * *

644 Sensitive Power Sensitive A Phase Power Stage 2 Start SPower2 Start * * *

645 Z based Pole Slipping Pole Slip (Impedance) Zone1 Start PSlipz Z1 Start *

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MiCOM P342, P343

P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

646 Z based Pole Slipping Pole Slip (Impedance) Zone2 Start PSlipz Z2 Start *

647 Z based Pole Slipping Pole Slip (impedance) Lens Start PSlipz LensStart *

648 Z based Pole Slipping Pole Slip (impedance) Blinder Start PSlipz BlindStrt *

649 Z based Pole Slipping Pole Slip (impedance) Reactance Line Start PSlipz ReactStrt *

650 System Backup Underimpedance 3Phase Stage 1 Start Z<1 Start * *

651 System Backup Underimpedance Phase A Stage 1 Start Z<1 Start A * *

652 System Backup Underimpedance Phase B Stage 1 Start Z<1 Start B * *

653 System Backup Underimpedance Phase C Stage 1 Start Z<1 Start C * *

654 System Backup Underimpedance 3Phase Stage 2 Start Z<2 Start * *

655 System Backup Underimpedance Phase A Stage 2 Start Z<2 Start A * *

656 System Backup Underimpedance Phase B Stage 2 Start Z<2 Start B * *

657 System Backup Underimpedance Phase C Stage 2 Start Z<2 Start C * *

658 Current Loop Inputs Current Loop Input 1 Alarm Start CLI1 Alarm Start * * *




662 Current Loop Inputs Current Loop Input 1 Trip Start CLI1 Trip Start * * *




666 UNUSED

667 UNUSED

668 UNUSED

669 UNUSED

670 UNUSED

671 UNUSED

672 UNUSED

673 UNUSED

674 UNUSED

675 UNUSED

676 UNUSED

677 UNUSED

678 UNUSED

679 UNUSED

680 UNUSED

681 UNUSED

682 UNUSED

683 UNUSED

684 UNUSED

685 UNUSED

686 UNUSED

687 UNUSED

688 UNUSED

689 UNUSED

690 UNUSED

691 UNUSED

692 UNUSED

693 UNUSED

694 UNUSED

695 UNUSED

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

696 UNUSED

697 UNUSED

698 UNUSED

699 UNUSED

700 UNUSED

701 UNUSED

702 UNUSED

703 UNUSED

704 UNUSED

705 UNUSED

706 UNUSED

707 UNUSED

708 UNUSED

709 UNUSED

710 UNUSED

711 UNUSED

712 UNUSED

713 UNUSED

714 UNUSED

715 UNUSED

716 UNUSED

717 UNUSED

718 UNUSED

719 UNUSED

720 UNUSED

721 UNUSED

722 UNUSED

723 UNUSED

724 UNUSED

725 UNUSED

726 UNUSED

727 UNUSED

728 UNUSED

729 UNUSED

730 UNUSED

731 UNUSED

732 UNUSED

733 UNUSED

734 UNUSED

735 UNUSED

736 VT Supervision VTS Fast Block VTS Fast Block * * *

737 VT Supervision VTS Slow Block VTS Slow Block * * *

738 CT Supervision CTS Block CTS Block * * *

739 CB Control Control Trip Control Trip *

740 CB Control Control Close Control Close *

741 CB Control Control Close in Progress Close in Prog *

742 Reconnection Reconnection Time Delay Output Reconnection *

743 RTD Thermal RTD 1 Alarm RTD 1 Alarm * *



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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343








753 CB Monitoring Composite Lockout Alarm Lockout Alarm * * *

754 CB Status Monitor 3 ph CB Open CB Open 3 ph * * *

755 CB Status Monitor 3 ph CB Closed CB Closed 3 ph * * *

756 Field Voltage Monitor Field Voltage Failure Field volts fail * * *

757 Poledead All Poles Dead All Poles Dead * * *

758 Poledead Any Pole Dead Any Pole Dead * * *

759 Poledead Phase A Pole Dead Pole Dead A * * *

760 Poledead Phase B Pole Dead Pole Dead B * * *

761 Poledead Phase C Pole Dead Pole Dead C * * *

762 VT Supervision VTS Accelerate Ind VTS Acc Ind * * *

763 VT Supervision Any Voltage Dependent VTS Volt Dep * * *

764 VT Supervision Ia Over Threshold VTS IA> * * *

765 VT Supervision Ib Over Threshold VTS IB> * * *

766 VT Supervision Ic Over Threshold VTS IC> * * *

767 VT Supervision Va Over Threshold VTS VA> * * *

768 VT Supervision Vb Over Threshold VTS VB> * * *

769 VT Supervision Vc Over Threshold VTS VC> * * *

770 VT Supervision I2 Over Threshold VTS I2> * * *

771 VT Supervision V2 Over Threshold VTS V2> * * *

772 VT Supervision Superimposed Ia Over Threshold VTS IA delta> * * *

773 VT Supervision Superimposed Ib Over Threshold VTS IB delta> * * *

774 VT Supervision Superimposed Ic Over Threshold VTS IC delta> * * *

775 CB Failure CBF Current Prot SEF Stage Trip BFail SEF Trip-1 * * *

776 CB Failure CBF Non Current Prot Stage Trip BFail Non I Tr-1 * * *

777 CB Failure CBF Current Prot SEF Trip BFail SEF Trip * * *

778 CB Failure CBF Non Current Prot Trip BFail Non I Trip * * *

779 Frequency tracking Freq High Freq High * * *

780 Frequency tracking Freq Low Freq Low * * *

781 Frequency tracking Freq Not Found Freq Not found * * *

782 Frequency tracking Stop Freq Track Stop Freq Track * * *

783 Reconnection Reconnect LOM (Unqualified) Recon LOM-1 *

784 Reconnection Reconnect Disable (Unqualified) Recon Disable-1 *

785 Reconnection Reconnect LOM Recon LOM *

786 Reconnection Reconnect Disable Recon Disable *

787 UNUSED

788 UNUSED

789 UNUSED

790 UNUSED

791 UNUSED

792 UNUSED

793 UNUSED

794 UNUSED

795 UNUSED

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

796 UNUSED

797 UNUSED

798 UNUSED

799 UNUSED

800 UNUSED

801 UNUSED

802 UNUSED

803 UNUSED

804 UNUSED

805 UNUSED

806 UNUSED

807 UNUSED

808 UNUSED

809 UNUSED

810 UNUSED

811 UNUSED

812 UNUSED

813 UNUSED

814 UNUSED

815 UNUSED

816 UNUSED

817 UNUSED

818 UNUSED

819 UNUSED

820 UNUSED

821 UNUSED

822 UNUSED

823 UNUSED

824 UNUSED

825 UNUSED

826 UNUSED

827 UNUSED

828 UNUSED

829 UNUSED

830 UNUSED

831 UNUSED

832 CONTROL Control Input 1 Control Input 1 * * *














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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343



















864 UNUSED

865 UNUSED

866 UNUSED

867 UNUSED

868 UNUSED

869 UNUSED

870 UNUSED

871 UNUSED

872 UNUSED

873 UNUSED

874 UNUSED

875 UNUSED

876 UNUSED

877 UNUSED

878 UNUSED

879 UNUSED

880 UNUSED

881 UNUSED

882 UNUSED

883 UNUSED

884 UNUSED

885 UNUSED

886 UNUSED

887 UNUSED

888 UNUSED

889 UNUSED

890 UNUSED

891 UNUSED

892 UNUSED

893 UNUSED

894 UNUSED

895 UNUSED

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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343

896 UNUSED

897 UNUSED

898 UNUSED

899 UNUSED

900 UNUSED

901 UNUSED

902 UNUSED

903 UNUSED

904 UNUSED

905 UNUSED

906 UNUSED

907 UNUSED

908 UNUSED

909 UNUSED

910 UNUSED

911 UNUSED

912 UNUSED

913 UNUSED

914 UNUSED

915 UNUSED

916 UNUSED

917 UNUSED

918 UNUSED

919 UNUSED

920 UNUSED

921 UNUSED

922 UNUSED

923 UNUSED

924 UNUSED

925 UNUSED

926 UNUSED

927 UNUSED

928 PSLINT PSL Int. 1 * * *


















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P34x/EN GC/F33

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0123456789ABCDEFP341 P342 P343



















































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P34x/EN GC/F33

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MiCOM P342, P343

P34x/EN GC/F33

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Courier Events: Cell Ref. Text Value (Binary Flag)Opto Input Events: 0020 Logic inputs 32 bit binary flag valueContact Events: 0021 32 bit binary flag value

Not Used 0022 0Not Used 0022 1SG-opto Invalid 0022 2Prot'n Disabled 0022 3VT Fail Alarm 0022 4CTS Fail Alarm 0022 5CB Fail 0022 6I^ Maint Alarm 0022 7I^ Maint Lockout 0022 8CB OPs Maint 0022 9CB OPs Lock 0022 10CB Time Maint 0022 11CB Time Lockout 0022 12Fault Freq Lock 0022 13CB Status Alarm 0022 14CB Trip Fail 0022 15CB Close Fail 0022 16Man CB Unhealthy 0022 17F out of Range Model 1 only 0022 18NPS Alarm Models 2 & 3 only 0022 18Thermal Alarm 0022 19V/Hz Alarm 0022 20Field Fail Alarm 0022 21RTD Thermal Alm 0022 22RTD Open Cct 0022 23RTD short Cct 0022 24RTD Data Error 0022 25RTD Board Fail 0022 26Freq Prot Alm 0022 27Voltage Prot Alm 0022 28Not Used 0022 29Not Used 0022 30Not Used 0022 31

CL Card I/P Fail 0051 0CL Card O/P Fail 0051 1CL Input 1 Alarm 0051 2CL Input 2 Alarm 0051 3CL Input 3 Alarm 0051 4CL Input 4 Alarm 0051 5CLI1 I< Fail Alm 0051 6CLI2 I< Fail Alm 0051 7CLI3 I< Fail Alm 0051 8CLI4 I< Fail Alm 0051 9Not Used 0051 10Not Used 0051 11Not Used 0051 12Not Used 0051 13Not Used 0051 14Not Used 0051 15MR User Alarm 16 0051 16MR User Alarm 15 0051 17MR User Alarm 14 0051 18MR User Alarm 13 0051 19MR User Alarm 12 0051 20MR User Alarm 11 0051 21MR User Alarm 10 0051 22MR User Alarm 9 0051 23MR User Alarm 8 0051 24MR User Alarm 7 0051 25MR User Alarm 6 0051 26MR User Alarm 5 0051 27SR User Alarm 4 0051 28SR User Alarm 3 0051 29SR User Alarm 2 0051 30SR User Alarm 1 0051 31

Battery Fail 0052 0Field Volt Fail 0052 1Not Used 0052 2GOOSE IED Absent 0052 3NIC not fitted 0052 4NIC no response 0052 5NIC fatal error 0052 6

000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000

Alarm Name + ON/OFF

Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF


Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF

Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF

Alarm Name + ON/OFFAlarm Name + ON/OFF


Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF



Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF

00000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000

0000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000000

00000000000000000000000000000001Alarm Status 2 Events (Alarms 33 - 64):

Alarm Name + ON/OFF00000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000000

Alarm Status 3 Events (Alarms 65 - 96):Alarm Name + ON/OFF

00000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000

This sheet contains all the text used in Events and all other messages

Output ContactsAlarm Status 1 Events (Alarms 1 - 32):

Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF

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P34x/EN GC/F33

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Alarm Status 3 Events (Alarms 65 - 96):NIC Software Reload 0052 7Bad TCP/IP Configuration 0052 8Bad OSI Configuration 0052 9NIC Link Fail 0052 10NIC SW-Mismatch 0052 11IP addr conflict 0052 12Not Used 0052 13Not Used 0052 14Not Used 0052 15Not Used 0052 16Not Used 0052 17Not Used 0052 18Not Used 0052 19Not Used 0052 20Not Used 0052 21Not Used 0052 22Not Used 0052 23Not Used 0052 24Not Used 0052 25Not Used 0052 26Not Used 0052 27Not Used 0052 28Not Used 0052 29Not Used 0052 30Not Used 0052 31

Protection Events: Cell Ref. Text0F26 - 0F3F DDB Signal Name ON/OFF

Fault Records: Cell Ref. Text Value Record Number0100 Fault Record 0 16bit UINT

Self Monitoring:(List is not exhaustive)Bus Check Failure FFFF Bus Failure 1 16bit UINTSRAM Failure FFFF SRAM Failure 2BB RAM Failure FFFF BB RAM Failure 3LCD Failure FFFF LCD Failure 4Watchdog 1 Failure (Fast) FFFF Watchdog 1 Fail 5Watchdog 2 Failure (Slow) FFFF Watchdog 2 Fail 6Field Voltage Failure FFFF Field Volt Fail 7Flash EPROM Failure FFFF FlashEEPROM Fail 8EEPROM Failure FFFF EEPROM Fail 9Cal EEPROM Failure FFFF Cal EEPROM Fail 10Incorrect Hardware Configuration FFFF Invalid H/W 11Power Up Boot FFFF Power Up Boot 12Soft Reboot FFFF Soft Reboot 13Setting Changes: Cell Ref. Text ValueC & S Change FFFF Settings Updated 0Group 1 Change 0905 Group 1 Updated 1Group 2 Change 0905 Group 2 Updated 2Group 3 Change 0905 Group 3 Updated 3Group 4 Change 0905 Group 4 Updated 4Disturbance Recorder 0C01 Disturbance Settings 0Active Group Change 0904 Active Group Changed (UINT of New Active Group)

General Events:Time SyncPassword Unlocked 0002 Password Unlocked [New Access Level]Password Invalid 0002 Password Invalid 0Password Modified level 1 00D2 Password 1 Edit 0Password Modified level 2 00D3 Password 2 Edit 0Password Expired 0002 Password Expired [ Password Level]IRIG-B Active 0803 IRIG-B Active 1IRIG-B Inactive 0803 IRIG-B Inactive 0

Cell Ref. Text

Event Extraction Column

Value32bit Binary Flag of the revelant packed DDB

Event Extraction Column

B100

Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF

Alarm Name + ON/OFFAlarm Name + ON/OFFAlarm Name + ON/OFF



Alarm Name + ON/OFF

0000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000000100000000000000000000000

001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000000

00000001000000000000000000000000000000100000000000000000000000000000010000000000000000000000000000001000000000000000000000000000

Value (32bit UINT) Record Number

B000

00010000000000000000000000000000

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MiCOM P342, P343

P34x/EN GC/F33

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Vendor Name:

Device Name:

Models Covered:

Compatibility Level:

2

Electrical Interface: EIA(RS)485

Number of Loads:

Optical Interface (Order Option)

Plastic fibre BFOC/2.5 type connector

Transmission Speed:

1 2 3 4 5 6

8 10 255 0 End of General Interrogration * * *

6 8 255 0 Time Synchronisation * * *

5 3 224 2 Reset FCB * * *

5 4 224 3 Reset CU * * *

5 5 224 4 Start/Restart * * *

5 6 224 5 Power On * * *

1 1,7,9,11,12,20,21 224 16 Auto-recloser active *

1 1,7,9,11,12,20,21 224 17 Tele-protection active *

1 1,7,9,11,12,20,21 224 18 Protection active *

1 1,7,11,12,20, 21 224 19 LED Reset * * * Reset Indications

1 9,11 224 20 Monitor direction blocked * * * * 391

1 9,11 224 21 Test mode * * * * Protection Disabled 291

1 9,11 224 22 Local parameter setting *

1 1,7,9,11,12,20,21 224 23 Characteristic 1 * * * * PG1 Changed




1 1,7,9,11 224 27 Auxillary input 1 * * * * Opto Input 1 32




1 1,7,9 224 32 Measurand supervision I *

1 1,7,9 224 33 Measurand supervision V *

1 1,7,9 224 35 Phase sequence supervision *

1 1,7,9 224 36 Trip circuit supervision *

1 1,7,9 224 37 I>> back-up supervision *

1 1,7,9 224 38 VT fuse failure * * * * VTS Indication 292

1 1,7,9 224 39 Teleprotection disturbed *

1 1,7,9 224 46 Group warning *

1 1,7,9 224 47 Group alarm *

1 1,7,9 224 48 Earth Fault L1 *

1 1,7,9 224 49 Earth Fault L2 *

1 1,7,9 224 50 Earth Fault L3 *

1 1,7,9 224 51 Earth Fault Fwd *

Physical Layer

1 for one protection equipment

System Functions

GIFUN DescriptionInf. No.

DDB Ordinal

9600 or 19200bps (User Setting)

Common Address of ASDU = Link Address

IEC60870-5-103: Device ProfileAlstom T&D - Energy, Automation & Information

P340 Generator Protection

P341****3**07**

P342****3**07**

P343****3**07**

Note: Indentification message in ASDU 5: "ALSTOM P" + 16bit model + 8bit major version + 1 character minor version e.g. "ALSTOM P" + 343 + 06 + 'A'

Supervision Indications

Earth Fault Indications

Status Indications

Application Layer

Compatible Range Information Numbers in Monitor Direction

InterpretationModel Number

ASDU TYPE COT

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P34x/EN GC/F33

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1 2 3 4 5 6GIFUN Description

Inf. No.

DDB OrdinalInterpretationModel Number

ASDU TYPE COT

1 1,7,9 224 52 Earth Fault Rev *

2 1,7,9 224 64 Start /pickup L1 * * * * 1st Stage O/C Start A 598

2 1,7,9 224 65 Start /pickup L2 * * * * 1st Stage O/C Start B 599

2 1,7,9 224 66 Start /pickup L3 * * * * 1st Stage O/C Start C 600

2 1,7,9 224 67 Start /pickup N * * * * 1st Stage EF Start 613

2 1,7 224 68 General Trip * * * Any Trip 162

2 1,7 224 69 Trip L1 * * * 1st Stage O/C Trip A 478

2 1,7 224 70 Trip L2 * * * 1st Stage O/C Trip B 479

2 1,7 224 71 Trip L3 * * * 1st Stage O/C Trip C 480

2 1,7 224 72 Trip I>> (back up)

4 1,7 224 73 Fault Location in ohms

2 1,7 224 74 Fault forward

2 1,7 224 75 Fault reverse

2 1,7 224 76 Teleprotection signal sent

2 1,7 224 77 Teleprotection signal received

2 1,7 224 78 Zone 1

2 1,7 224 79 Zone 2

2 1,7 224 80 Zone 3

2 1,7 224 81 Zone 4

2 1,7 224 82 Zone 5

2 1,7 224 83 Zone 6

2 1,7,9 224 84 General Start * * * * Any Start 576

2 1,7 224 85 Breaker Failure * * * Breaker Fail Any Trip 294

2 1,7 224 86 Trip measuring system L1



2 1,7 224 89 Trip measuring system E

2 1,7 224 90 Trip I> * * * 1st Stage O/C Trip 3ph 477

2 1,7 224 91 Trip I>> * * * 2nd Stage O/C Trip 3ph 481

2 1,7 224 92 Trip IN> * * * 1st Stage EF Trip 442

2 1,7 224 93 Trip IN>> * * * 2nd Stage EF Trip 443

1 1,7 224 128 CB 'on' by A/R

1 1,7 224 129 CB 'on' by long time A/R

1 1,7,9 224 130 AR blocked *

3.1 2,7 224 144 Measurand I

3.2 2,7 224 145 Measurands I,V

3.3 2,7 224 146 Measurands I,V,P,Q

3.4 2,7 224 147 Measurands IN,VEN

9 2,7 224 148Measurands IL1,2,3,VL1,2,3,P,Q,f

* * * Note unavailable measurands sent as invalid

10 42,43 224 240 Read Headings

10 42,43 224 241Read attributes of all entries of a group

10 42,43 224 243 Read directory of entry

101,2,7,9,11,12,

42,43224 244 Real attribute of entry *

10 10 224 245 End of GGI

10 41,44 224 249 Write entry with confirm

10 40,41 224 250 Write entry with execute

10 40 224 251 Write entry aborted

Fault Indications

Auto-Reclose Indications

Measurands

Generic Functions

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 106/170


Inf. No.


ASDU TYPE COT

1 2 3 4 5 6

7 9 255 0 Init General Interrogation * * *

6 8 255 0 Time Synchronisation * * *

20 20 224 16 Auto-recloser on/off Autoreclose in Service

20 20 224 17 Teleprotection on/off

20 20 224 18 Protection on/off

20 20 224 19 LED Reset * * * Reset Indications and Latches

20 20 224 23 Activate characteristic 1 * * * Activate Setting Group 1




21 42 224 240Read headings of all defined groups

21 42 224 241Read single attribute of all entries of a group

21 42 224 243 Read directory of single entry

21 42 224 244 Read attribute of sngle entry

21 9 224 245Generic General Interrogation (GGI)

10 40 224 248 Write entry

10 40 224 249 Write with confirm

10 40 224 250 Write with execute

10 40 224 251 Write entry abort

* * * * *

Blocking of monitor direction * * * * *

* * * * *

* *

* * * * *

*

*

*

*

*

*

*

*

*

1 2 3 4 5 6

1 1,7,9 226 0 Contact 1 * * * * Output Relay 1 0










DDB Ordinal

Voltage L2-E

Voltage L3-E

Compatible Range Information Numbers in Control Direction

DDB Ordinal

Basic Application Functions

General Commands

System Functions

Test Mode

Model NumberASDU TYPE COT FUN Description

Generic Functions

GIInf. No.

Interpretation

Max. MVAL = times rated value

DDB Signal DescriptionGIInf. No.

Private Range Information Numbers in Monitor Direction

Voltage L1-L2

1.2 2.4

Reactive Power Q

Frequency F

Disturbance data

Generic services

Active Power P

Current L3

Voltage L1-E

Private data

Miscellaneous

Current L1

Current L2

Measurands

FUN Display Text (English)ASDU TYPE COTModel Number

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 107/170


Inf. No.


ASDU TYPE COT















1 1,7,9 226 24 Contact 25 * * Output Relay 25 24








1 1,7,9,11 224 27 Opto 1 * * * * Opto Input 1 32

1 1,7,9,11 224 28 Opto 2 * * * * Opto Input 2 33

1 1,7,9,11 224 29 Opto 3 * * * * Opto Input 3 34

1 1,7,9,11 224 30 Opto 4 * * * * Opto Input 4 35

1 1,7,9,11 226 36 Opto 5 * * * * Opto Input 5 36

1 1,7,9,11 226 37 Opto 6 * * * * Opto Input 6 37

1 1,7,9,11 226 38 Opto 7 * * * * Opto Input 7 38

1 1,7,9,11 226 39 Opto 8 * * * * Opto Input 8 39

1 1,7,9,11 226 40 Opto 9 * * * * Opto Input 9 40

1 1,7,9,11 226 41 Opto 10 * * * * Opto Input 10 41

1 1,7,9,11 226 42 Opto 11 * * * * Opto Input 11 42

1 1,7,9,11 226 43 Opto 12 * * * * Opto Input 12 43

1 1,7,9,11 226 44 Opto 13 * * * * Opto Input 13 44

1 1,7,9,11 226 45 Opto 14 * * * * Opto Input 14 45

1 1,7,9,11 226 46 Opto 15 * * * * Opto Input 15 46

1 1,7,9,11 226 47 Opto 16 * * * * Opto Input 16 47

1 1,7,9,11 226 48 Opto 17 * * * * Opto Input 17 48

1 1,7,9,11 226 49 Opto 18 * * * * Opto Input 18 49

1 1,7,9,11 226 50 Opto 19 * * * * Opto Input 19 50

1 1,7,9,11 226 51 Opto 20 * * * * Opto Input 20 51

1 1,7,9,11 226 52 Opto 21 * * * * Opto Input 21 52

1 1,7,9,11 226 53 Opto 22 * * * * Opto Input 22 53

1 1,7,9,11 226 54 Opto 23 * * * * Opto Input 23 54

1 1,7,9,11 226 55 Opto 24 * * * * Opto Input 24 55

1 1,7,9,11 226 56 Opto 25 * * Opto Input 25 56

1 1,7,9,11 226 57 Opto 26 * * Opto Input 26 57

1 1,7,9,11 226 58 Opto 27 * * Opto Input 27 58

1 1,7,9,11 226 59 Opto 28 * * Opto Input 28 59

1 1,7,9,11 226 60 Opto 29 * * Opto Input 29 60

1 1,7,9,11 226 61 Opto 30 * * Opto Input 30 61

1 1,7,9,11 226 62 Opto 31 * * Opto Input 31 62

1 1,7,9,11 226 63 Opto 32 * * Opto Input 32 63

226 64 LED 1 * * * Programmable LED 1 64





Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 108/170


Inf. No.


ASDU TYPE COT




226 72 72

226 73 73

226 74 74

226 75 75

226 76 76

226 77 77

226 78 78

226 79 79

226 80 LED Cond IN 1 * * *Input to LED Output Condition

80


81


82


83


84


85


86


87

226 88 88

226 89 89

226 90 90

226 91 91

226 92 92

226 93 93

226 94 94

226 95 95

226 96 96

226 97 97

226 98 98

226 99 99

226 100 100

226 101 101

226 102 102

226 103 103

226 104 104

226 105 105

226 106 106

226 107 107

226 108 108

226 109 109

226 110 110

226 111 111

226 112 112

226 113 113

226 114 114

226 115 115

226 116 116

226 117 117

226 118 118

226 119 119

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 109/170


Inf. No.


ASDU TYPE COT

226 120 120

226 121 121

226 122 122

226 123 123

226 124 124

226 125 125

226 126 126

226 127 127

226 128 128

226 129 129

226 130 130

226 131 131

226 132 132

226 133 133

226 134 134

226 135 135

226 136 136

226 137 137

226 138 138

226 139 139

226 140 140

226 141 141

226 142 142

226 143 143

226 144 144

226 145 145

226 146 146

226 147 147

226 148 148

226 149 149

226 150 150

226 151 151

226 152 152

226 153 153

226 154 154

226 155 155

226 156 156

226 157 157

226 158 158

226 159 159

226 160 Relay Cond 1 * * *Input to Relay Output Condition

160


161

2 1,7 224 68 Any Trip * * *Input to Relay Output Condition

162


163


164


165


166


167


168

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 110/170


Inf. No.


ASDU TYPE COT


169


170


171


172


173


174


175


176


177


178


179


180


181


182


183

226 184 Relay Cond 25 *Input to Relay Output Condition

184


185


186


187


188


189


190


191

226 192 192

226 193 193

226 194 194

226 195 195

226 196 196

226 197 197

226 198 198

226 199 199

226 200 200

226 201 201

226 202 202

226 203 203

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 111/170


Inf. No.


ASDU TYPE COT

226 204 204

226 205 205

226 206 206

226 207 207

226 208 208

226 209 209

226 210 210

226 211 211

226 212 212

226 213 213

226 214 214

226 215 215

226 216 216

226 217 217

226 218 218

226 219 219

226 220 220

226 221 221

226 222 222

226 223 223

226 224 Timer in 1 * * * Input to Auxiliary Timer 1 224








226 232 232

226 233 233

226 234 234

226 235 235

226 236 236

226 237 237

226 238 238

226 239 239

226 240 240

226 241 241

226 242 242

226 243 243

226 244 244

226 245 245

226 246 246

226 247 247

226 248 248

226 249 249

226 250 250

226 251 251

226 252 252

226 253 253

226 254 254

226 255 255

227 0 Timer out 1 * * * Output from Auxiliary Timer 1 256







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MiCOM P342, P343

P34x/EN GC/F33

Page 112/170


Inf. No.


ASDU TYPE COT


227 8 264

227 9 265

227 10 266

227 11 267

227 12 268

227 13 269

227 14 270

227 15 271

227 16 272

227 17 273

227 18 274

227 19 275

227 20 276

227 21 277

227 22 278

227 23 279

227 24 280

227 25 281

227 26 282

227 27 283

227 28 284

227 29 285

227 30 286

227 31 287

227 32 Fault REC TRIG * * * Trigger for Fault Recorder 288

227 33 289

1 1,7,9 227 34 SG-opto Invalid * * * * Setting Group via opto invalid 290

1 9,11 224 21 Prot'n Disabled * * * * Test Mode Enabled Alarm 291

1 1,7,9 224 38 VT Fail Alarm * * * * VTS Indication 292

1 1,7,9 227 37 CT Fail Alarm * * * * CTS Indication 293

2 1,7 224 85 CB Fail Alarm * * * Breaker Fail Any Trip 294

1 1,7,9 227 39 I^ Maint Alarm * * * *Broken Current Maintenance Alarm

295

1 1,7,9 227 40 I^ Lockout Alarm * * * *Broken Current Lockout Alarm

296

1 1,7,9 227 41 CB Ops Maint * * * *No of CB Ops Maintenance Alarm

297

1 1,7,9 227 42 CB Ops Lockout * * * *No of CB Ops Maintenance Lockout

298

1 1,7,9 227 43 CB Op Time Maint * * * *Excessive CB Op Time Maintenance Alarm

299

1 1,7,9 227 44 CB Op Time Lock * * * *Excessive CB Op Time Lockout Alarm

300

1 1,7,9 227 45 Fault Freq Lock * * * *Excessive Fault Frequency Lockout Alarm

301

1 1,7,9 227 46 CB Status Alarm * * * *CB Status Alarm (Invalid CB auxilliary contacts)

302

1 1,7 227 47 Man CB Trip Fail * * * CB Failed to Trip Alarm 303

1 1,7 227 48 Man CB Cls Fail * * * CB Failed to Close Alarm 304

1 1,7 227 49 Man CB Unhealthy * * *CB Unhealthy on Control Close Alarm

305

1 1,7,9 227 50 F out of Range * * Frequency out of range 306

1 1,7,9 227 50 NPS Alarm * * *Negative Phase Sequence Alarm

306

1 1,7,9 227 51 Thermal Alarm * * * * Thermal Overload Alarm 307

1 1,7,9 227 52 V/Hz Alarm * * * Volts Per Hz Alarm 308

1 1,7,9 227 53 Field Fail Alarm * * * Field failure Alarm 309

1 1,7,9 227 54 RTD Thermal Alm * * * RTD thermal Alarm 310

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 113/170


Inf. No.


ASDU TYPE COT

1 1,7,9 227 55 RTD Open Cct * * * RTD open circuit failure 311

1 1,7,9 227 56 RTD short Cct * * * RTD short circuit failure 312

1 1,7,9 227 57 RTD Data Error * * * RTD data inconsistency error 313

1 1,7,9 227 58 RTD Board Fail * * * RTD Board failure 314

1 1,7,9 227 59 Freq Prot Alm * * * * Frequency protection alarm 315

1 1,7,9 227 60 Voltage Prot Alm * * * * Voltage protection alarm 316

227 61 317

227 62 318

227 63 319

1 1,7,9 227 64 CL Card I/P Fail * * * * CLIO Card Input Failure 320

1 1,7,9 227 65 CL Card O/P Fail * * * * CLIO Card Output Failure 321

1 1,7,9 227 66 CL Input 1 Alarm * * * * Current Loop Input 1 Alarm 322




1 1,7,9 227 70 CLI1 I< Fail Alm * * * *Current Loop Input 1 Undercurrent Fail Alarm

326


327


328


329

227 74 330

227 75 331

227 76 332

227 77 333

227 78 334

227 79 335

1 1,7,9 227 80 MR User Alarm 16 * * * *User Definable Alarm 16 (Manual Reset)

336


337


338


339


340


341


342


343


344


345


346


347

1 1,7,9 227 92 SR User Alarm 4 * * * *User Definable Alarm 4 (Self Reset)

348


349

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MiCOM P342, P343

P34x/EN GC/F33

Page 114/170


Inf. No.


ASDU TYPE COT


350


351

227 96 VDepOC Timer Blk * *Block Voltage Dependent time delay

352

227 97 UnderZ Timer Blk * *Block Under Impedance time delay

353

227 98 I>1 Timer Block * * *Block Phase Overcurrent Stage 1 time delay

354

227 99 I>2 Timer Block * * *Block Phase Overcurrent Stage 2 time delay

355

227 100 I>3 Timer Block * Block Phase Overcurrent Stage 3 time delay

356

227 101 I>4 Timer Block * Block Phase Overcurrent Stage 4 time delay

357

227 102 IN>1 Timer Blk * * *Block Earth Fault Stage 1 time delay

358

227 103 IN>2 Timer Blk * * *Block Earth Fault Stage 2 time delay

359

227 104 IN>3 Timer Blk * Block Earth Fault Stage 3 time delay

360

227 105 IN>4 Timer Blk * Block Earth Fault Stage 4 time delay

361

227 106 ISEF>1 Timer Blk * * * Block SEF Stage 1 time delay 362

227 107 ISEF>2 Timer Blk * Block SEF Stage 2 time delay 363



227 110 Init Trip CB * Logic Input Trip CB 366

227 111 Init Close CB * Logic Input Close CB 367

227 112 VN>1 Timer Blk * * *Block Residual Overvoltage Stage 1 time delay

368

227 113 VN>2 Timer Blk * * *Block Residual Overvoltage Stage 2 time delay

369

227 114 V<1 Timer Block * * *Block Phase Undervoltage Stage 1 time delay

370

227 115 V<2 Timer Block * * *Block Phase Undervoltage Stage 2 time delay

371

227 116 V>1 Timer Block * * *Block Phase Overvoltage Stage 1 time delay

372

227 117 V>2 Timer Block * * *Block Phase Overvoltage Stage 2 time delay

373

227 118 F<1 timer Block * * *Block Underfrequency Stage 1 Timer

374

227 119 F<2 Timer Block * * *Block Underfrequency Stage 2 Timer

375


376


377

227 122 F>1 Timer Block * * *Block Overfrequency Stage 1 Timer

378

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 115/170


Inf. No.


ASDU TYPE COT

227 123 F>2 Timer Block * * *Block Overfrequency Stage 2 Timer

379

227 124 Ext. Trip 3ph * * * External Trip 3ph 380

227 125 CB Aux 3ph(52-A) * * * 52-A (3 phase) 381

227 126 CB Aux 3ph(52-B) * * * 52-B (3 phase) 382

227 127 CB Healthy * * * CB Healthy 383

227 128 MCB/VTS * * * MCB/VTS opto 384

227 129 Reset Close Dly * * *Reset Manual CB Close Time Delay

385

227 130 Reset Relays/LED * * * Reset Latched Relays & LED’s 386

227 131 Reset Lockout * * * Reset Lockout Opto Input 387

227 132 Reset All Values * * * Reset CB Maintenance Values 388

227 133 Reset I2 Thermal * * Reset NPS Thermal State 389

227 134 Reset ThermalO/L * * * Reset Overload Thermal State 390

1 9, 11 224 20 Monitor Blocked * * * *IEC60870-5-103 Monitor Blocking

391

1 9, 11 227 136 Command Blocked * * * *IEC60870-5-103 Command Blocking

392

227 137 CL Input 1 Blk * * *Block Current Loop Input 1 protection

393


394


395


396

227 141 397

227 142 398

227 143 399

227 144 400

227 145 401

227 146 402

227 147 403

227 148 404

227 149 405

227 150 406

227 151 407

227 152 408

227 153 409

227 154 410

227 155 411

227 156 412

227 157 413

227 158 414

227 159 Test Mode * * * Input To Initiate Test Mode 415

2 1,7 227 160 100% ST EF Trip * 100% Stator Earth Fault Trip 416

2 1,7 227 161 DeadMachine Trip * Dead machine protection Trip 417

2 1,7 227 162 Gen Diff Trip *Generator Differential trip 3ph

418

2 1,7 227 163 Gen Diff Trip A * Generator Differential Trip A 419

2 1,7 227 164 Gen Diff Trip B * Generator Differential Trip B 420

2 1,7 227 165 Gen Diff Trip C * Generator Differential Trip C 421

2 1,7 227 166 Field Fail1 Trip * * Field Failure Stage 1 Trip 422

2 1,7 227 167 Field Fail2 Trip * * Field Failure Stage 2 Trip 423

2 1,7 227 168 NPS Trip * *Negative Phase Sequence Trip

424

2 1,7 227 169 V Dep OC Trip * *Voltage Dependent O/C Trip 3ph

425

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 116/170


Inf. No.


ASDU TYPE COT

2 1,7 227 170 V Dep OC Trip A * *Voltage Dependent O/C Trip A

426

2 1,7 227 171 V Dep OC Trip B * *Voltage Dependent O/C Trip B

427

2 1,7 227 172 V Dep OC Trip C * *Voltage Dependent O/C Trip C

428

2 1,7 227 173 V/Hz Trip * * Volts per Hz Trip 429

2 1,7 227 174 RTD 1 Trip * * RTD 1 TRIP 430

2 1,7 227 175 RTD 2 Trip * * RTD 2 TRIP 431

2 1,7 227 176 RTD 3 Trip * * RTD 3 TRIP 432

2 1,7 227 177 RTD 4 Trip * * RTD 4 TRIP 433

2 1,7 227 178 RTD 5 Trip * * RTD 5 TRIP 434

2 1,7 227 179 RTD 6 Trip * * RTD 6 TRIP 435

2 1,7 227 180 RTD 7 Trip * * RTD 7 TRIP 436

2 1,7 227 181 RTD 8 Trip * * RTD 8 TRIP 437

2 1,7 227 182 RTD 9 Trip * * RTD 9 TRIP 438

2 1,7 227 183 RTD 10 Trip * * RTD 10 TRIP 439

2 1,7 227 184 Any RTD Trip * * Any RTD Trip 440

2 1,7 227 184 df/dt Trip *Rate of change of frequency Trip

440

2 1,7 227 185 V Shift Trip * Voltage vector shift trip 441

2 1,7 224 92 IN>1 Trip * * * 1st Stage EF Trip 442

2 1,7 224 93 IN>2 Trip * * * 2nd Stage EF Trip 443

2 1,7 227 188 IN>3 Trip * 3rd Stage EF Trip 444

2 1,7 227 189 IN>4 Trip * 4th Stage EF Trip 445

2 1,7 227 190 IREF> Trip * * * REF Trip 446

2 1,7 227 191 ISEF>1 Trip * * * 1st Stage SEF Trip 447

2 1,7 227 192 ISEF>2 Trip * 2nd Stage SEF Trip 448

2 1,7 227 193 ISEF>3 Trip * 3rd Stage SEF Trip 449

2 1,7 227 194 ISEF>4 Trip * 4th Stage SEF Trip 450

2 1,7 227 195 VN>1 Trip * * * 1st Stage Residual O/V Trip 451

2 1,7 227 196 VN>2 Trip * * * 2nd Stage Residual O/V Trip 452

2 1,7 227 197 V<1 Trip * * * 1st Stage Phase U/V Trip 3ph 453

2 1,7 227 198 V<1 Trip A/AB * * *1st Stage Phase U/V Trip A/AB

454

2 1,7 227 199 V<1 Trip B/BC * * *1st Stage Phase U/V Trip B/BC

455

2 1,7 227 200 V<1 Trip C/CA * * *1st Stage Phase U/V Trip C/CA

456

2 1,7 227 201 V<2 Trip * * *2nd Stage Phase U/V Trip 3ph

457

2 1,7 227 202 V<2 Trip A/AB * * *2nd Stage Phase U/V Trip A/AB

458

2 1,7 227 203 V<2 Trip B/BC * * *2nd Stage Phase U/V Trip B/BC

459

2 1,7 227 204 V<2 Trip C/CA * * *2nd Stage Phase U/V Trip C/CA

460

2 1,7 227 205 V>1 Trip * * * 1st Stage Phase O/V Trip 3ph 461

2 1,7 227 206 V>1 Trip A/AB * * *1st Stage Phase O/V Trip A/AB

462

2 1,7 227 207 V>1 Trip B/BC * * *1st Stage Phase O/V Trip B/BC

463

2 1,7 227 208 V>1 Trip C/CA * * *1st Stage Phase O/V Trip C/CA

464

2 1,7 227 209 V>2 Trip * * *2nd Stage Phase O/V Trip 3ph

465

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 117/170


Inf. No.


ASDU TYPE COT

2 1,7 227 210 V>2 Trip A/AB * * *2nd Stage Phase O/V Trip A/AB

466

2 1,7 227 211 V>2 Trip B/BC * * *2nd Stage Phase O/V Trip B/BC

467

2 1,7 227 212 V>2 Trip C/CA * * *2nd Stage Phase O/V Trip C/CA

468

2 1,7 227 213 F<1 Trip * * * Under frequency Stage 1 trip 469




2 1,7 227 217 F>1 Trip * * * Over frequency Stage 1 Trip 473

2 1,7 227 218 F>2 Trip * * * Over frequency Stage 2 Trip 474

2 1,7 227 219 Power1 Trip * * * Power stage 1 trip 475

2 1,7 227 220 Power2 Trip * * * Power stage 2 trip 476

2 1,7 224 90 I>1 Trip * * * 1st Stage O/C Trip 3ph 477

2 1,7 224 69 I>1 Trip A * * * 1st Stage O/C Trip A 478

2 1,7 224 70 I>1 Trip B * * * 1st Stage O/C Trip B 479

2 1,7 224 71 I>1 Trip C * * * 1st Stage O/C Trip C 480

2 1,7 224 91 I>2 Trip * * * 2nd Stage O/C Trip 3ph 481

2 1,7 227 226 I>2 Trip A * * * 2nd Stage O/C Trip A 482

2 1,7 227 227 I>2 Trip B * * * 2nd Stage O/C Trip B 483

2 1,7 227 228 I>2 Trip C * * * 2nd Stage O/C Trip C 484

2 1,7 227 229 I>3 Trip * 3rd Stage O/C Trip 3ph 485

2 1,7 227 230 I>3 Trip A * 3rd Stage O/C Trip A 486

2 1,7 227 231 I>3 Trip B * 3rd Stage O/C Trip B 487

2 1,7 227 232 I>3 Trip C * 3rd Stage O/C Trip C 488

2 1,7 227 233 I>4 Trip * 4th Stage O/C Trip 3ph 489

2 1,7 227 234 I>4 Trip A * 4th Stage O/C Trip A 490

2 1,7 227 235 I>4 Trip B * 4th Stage O/C Trip B 491

2 1,7 227 236 I>4 Trip C * 4th Stage O/C Trip C 492

2 1,7 227 237 Bfail1 Trip 3ph * * * tBF1 Trip 3Ph 493

2 1,7 227 238 Bfail2 Trip 3ph * * * tBF2 Trip 3Ph 494

2 1,7 227 239 SPower1 Trip * * *Sensitive A Phase Power Stage1 Trip

495

2 1,7 227 240 SPower2 Trip * * *Sensitive A Phase Power Stage2 Trip

496

2 1,7 227 241 PSlipz Z1 Trip *Pole Slip (Impedance) Zone1 Trip

497

2 1,7 227 242 PSlipz Z2 Trip *Pole Slip (Impedance) Zone2 Trip

498

2 1,7 227 243 Thermal O/L Trip * * * Thermal Overload Trip 499

2 1,7 227 244 Z<1 Trip * *Under Impedance Stage 1 Trip 3 Ph

500

2 1,7 227 245 Z<1 Trip A * *Under Impedance Stage 1 Trip A

501

2 1,7 227 246 Z<1 Trip B * *Under Impedance Stage 1 Trip B

502

2 1,7 227 247 Z<1 Trip C * *Under Impedance Stage 1 Trip C

503

2 1,7 227 248 Z<2 Trip * *Under Impedance Stage 2 Trip 3 Ph

504

2 1,7 227 249 Z<2 Trip A * *Under Impedance Stage 2 Trip A

505

2 1,7 227 250 Z<2 Trip B * *Under Impedance Stage 2 Trip B

506

2 1,7 227 251 Z<2 Trip C * *Under Impedance Stage 2 Trip C

507

2 1,7 227 252 CL Input 1 Trip * * * Current Loop Input 1 Trip 508

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 118/170


Inf. No.


ASDU TYPE COT




228 0 512

228 1 513

228 2 514

228 3 515

228 4 516

228 5 517

228 6 518

228 7 519

228 8 520

228 9 521

228 10 522

228 11 523

228 12 524

228 13 525

228 14 526

228 15 527

228 16 528

228 17 529

228 18 530

228 19 531

228 20 532

228 21 533

228 22 534

228 23 535

228 24 536

228 25 537

228 26 538

228 27 539

228 28 540

228 29 541

228 30 542

228 31 543

228 32 544

228 33 545

228 34 546

228 35 547

228 36 548

228 37 549

228 38 550

228 39 551

228 40 552

228 41 553

228 42 554

228 43 555

228 44 556

228 45 557

228 46 558

228 47 559

228 48 560

228 49 561

228 50 562

228 51 563

228 52 564

228 53 565

228 54 566

228 55 567

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 119/170


Inf. No.


ASDU TYPE COT

228 56 568

228 57 569

228 58 570

228 59 571

228 60 572

228 61 573

228 62 574

228 63 575

2 1,7,9 224 84 Any Start * * * * Any Start 576

2 1,7,9 228 65 VN>1 Start * * * * 1st Stage Residual O/V Start 577

2 1,7,9 228 66 VN>2 Start * * * * 2nd Stage Residual O/V Start 578

2 1,7,9 228 67 V<1 Start * * * * 1st Stage Phase U/V Start 3ph 579

2 1,7,9 228 68 V<1 Start A/AB * * * *1st Stage Phase U/V Start A/AB

580

2 1,7,9 228 69 V<1 Start B/BC * * * *1st Stage Phase U/V Start B/BC

581

2 1,7,9 228 70 V<1 Start C/CA * * * *1st Stage Phase U/V Start C/CA

582

2 1,7,9 228 71 V<2 Start * * * *2nd Stage Phase U/V Start 3ph

583

2 1,7,9 228 72 V<2 Start A/AB * * * *2nd Stage Phase U/V Start A/AB

584

2 1,7,9 228 73 V<2 Start B/BC * * * *2nd Stage Phase U/V Start B/BC

585

2 1,7,9 228 74 V<2 Start C/CA * * * *2nd Stage Phase U/V Start C/CA

586

2 1,7,9 228 75 V>1 Start * * * *1st Stage Phase O/V Start 3ph

587

2 1,7,9 228 76 V>1 Start A/AB * * * *1st Stage Phase O/V Start A/AB

588

2 1,7,9 228 77 V>1 Start B/BC * * * *1st Stage Phase O/V Start B/BC

589

2 1,7,9 228 78 V>1 Start C/CA * * * *1st Stage Phase O/V Start C/CA

590

2 1,7,9 228 79 V>2 Start * * * *2nd Stage Phase O/V Start 3ph

591

2 1,7,9 228 80 V>2 Start A/AB * * * *2nd Stage Phase O/V Start A/AB

592

2 1,7,9 228 81 V>2 Start B/BC * * * *2nd Stage Phase O/V Start B/BC

593

2 1,7,9 228 82 V>2 Start C/CA * * * *2nd Stage Phase O/V Start C/CA

594

2 1,7,9 228 83 Power1 Start * * * * Power Stage 1 start 595

2 1,7,9 228 84 Power2 Start * * * * Power stage 1 start 596

2 1,7,9 228 85 I>1 Start * * * * 1st Stage O/C Start 3ph 597

2 1,7,9 224 64 I>1 Start A * * * * 1st Stage O/C Start A 598

2 1,7,9 224 65 I>1 Start B * * * * 1st Stage O/C Start B 599

2 1,7,9 224 66 I>1 Start C * * * * 1st Stage O/C Start C 600

2 1,7,9 228 89 I>2 Start * * * * 2nd Stage O/C Start 3ph 601

2 1,7,9 228 90 I>2 Start A * * * * 2nd Stage O/C Start A 602

2 1,7,9 228 91 I>2 Start B * * * * 2nd Stage O/C Start B 603

2 1,7,9 228 92 I>2 Start C * * * * 2nd Stage O/C Start C 604

2 1,7,9 228 93 I>3 Start * * 3rd Stage O/C Start 3ph 605

2 1,7,9 228 94 I>3 Start A * * 3rd Stage O/C Start A 606

2 1,7,9 228 95 I>3 Start B * * 3rd Stage O/C Start B 607

2 1,7,9 228 96 I>3 Start C * * 3rd Stage O/C Start C 608

2 1,7,9 228 97 I>4 Start * * 4th Stage O/C Start 3ph 609

2 1,7,9 228 98 I>4 Start A * * 4th Stage O/C Start A 610

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 120/170


Inf. No.


ASDU TYPE COT

2 1,7,9 228 99 I>4 Start B * * 4th Stage O/C Start B 611

2 1,7,9 228 100 I>4 Start C * * 4th Stage O/C Start C 612

2 1,7,9 224 67 IN>1 Start * * * * 1st Stage EF Start 613

2 1,7,9 228 102 IN>2 Start * * * * 2nd Stage EF Start 614

2 1,7,9 228 103 IN>3 Start * * 3rd Stage EF Start 615

2 1,7,9 228 104 IN>4 Start * * 4th Stage EF Start 616

2 1,7,9 228 105 ISEF>1 Start * * * * 1st Stage SEF Start 617

2 1,7,9 228 106 ISEF>2 Start * * 2nd Stage SEF Start 618

2 1,7,9 228 107 ISEF>3 Start * * 3rd Stage SEF Start 619

2 1,7,9 228 108 ISEF>4 Start * * 4th Stage SEF Start 620

2 1,7,9 228 109 100% ST EF Start * * 100% Stator Earth Fault Start 621

2 1,7,9 228 110 F<1 Start * * * *Under frequency Stage 1 START

622


623


624


625

2 1,7,9 228 114 F>1 Start * * * *Over frequency Stage 1 START

626

2 1,7,9 228 115 F>2 Start * * * *Over frequency Stage 2 START

627

2 1,7,9 228 116 I> BlockStart * * I> Blocked O/C Start, inhibited by CB Fail

628

2 1,7,9 228 117 IN/SEF>Blk Start * * IN/ISEF> Blocked O/C Start, inhibited by CB Fail

629

2 1,7,9 228 118 df/dt Start * *Rate of change of frequency Start

630

228 119 IA< Start * * * * IA< operate 631

228 120 IB< Start * * * * IB< operate 632

228 121 IC< Start * * * * IC< operate 633

228 122 ISEF< Start * * * * ISEF< operate 634

228 123 IN< Start * * * IN< operate 635

2 1,7,9 228 124 V/Hz Start * * * Volts per Hz Start 636

2 1,7,9 228 125 FFail1 Start * * * Field failure Stage 1 start 637

2 1,7,9 228 126 FFail2 Start * * * Field failure Stage 2 start 638

2 1,7,9 228 127 V Dep OC Start * * *Voltage Dependent Overcurrent Start

639

2 1,7,9 228 128 V Dep OC Start A * * *Voltage Dependent Overcurrent Start A

640

2 1,7,9 228 129 V Dep OC Start B * * *Voltage Dependent Overcurrent Start B

641

2 1,7,9 228 130 V Dep OC Start C * * *Voltage Dependent Overcurrent Start C

642

2 1,7,9 228 131 SPower1 Start * * * *Sensitive A Phase Power Stage1 Start

643

2 1,7,9 228 132 SPower2 Start * * * *Sensitive A Phase Power Stage2 Start

644

2 1,7,9 228 133 PSlipz Z1 Start * *Pole Slip (Impedance) Zone1 Start

645

2 1,7,9 228 134 PSlipz Z2 Start * *Pole Slip (Impedance) Zone2 Start

646

2 1,7,9 228 135 PSlipz LensStart * *Pole Slip (impedance) Lens Start

647

2 1,7,9 228 136 PSlipz BlindStrt * *Pole Slip (impedance) Blinder Start

648

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 121/170


Inf. No.


ASDU TYPE COT

2 1,7,9 228 137 PSlipz ReactStrt * *Pole Slip (impedance) Reactance Line Start

649

2 1,7,9 228 138 Z<1 Start * * *Under Impedance Stage 1 Start

650

2 1,7,9 228 139 Z<1 Start A * * *Under Impedance Stage 1 Start A

651

2 1,7,9 228 140 Z<1 Start B * * *Under Impedance Stage 1 Start B

652

2 1,7,9 228 141 Z<1 Start C * * *Under Impedance Stage 1 Start C

653

2 1,7,9 228 142 Z<2 Start * * *Under Impedance Stage 2 Start

654

2 1,7,9 228 143 Z<2 Start A * * *Under Impedance Stage 2 Start A

655

2 1,7,9 228 144 Z<2 Start B * * *Under Impedance Stage 2 Start B

656

2 1,7,9 228 145 Z<2 Start C * * *Under Impedance Stage 2 Start C

657

2 1,7,9 228 146 CLI1 Alarm Start * * * *Current Loop Input 1 Alarm Start

658


659


660


661

2 1,7,9 228 150 CLI1 Trip Start * * * *Current Loop Input 1 Trip Start

662


663


664


665

228 154 666

228 155 667

228 156 668

228 157 669

228 158 670

228 159 671

228 160 672

228 161 673

228 162 674

228 163 675

228 164 676

228 165 677

228 166 678

228 167 679

228 168 680

228 169 681

228 170 682

228 171 683

228 172 684

228 173 685

228 174 686

228 175 687

228 176 688

228 177 689

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 122/170


Inf. No.


ASDU TYPE COT

228 178 690

228 179 691

228 180 692

228 181 693

228 182 694

228 183 695

228 184 696

228 185 697

228 186 698

228 187 699

228 188 700

228 189 701

228 190 702

228 191 703

228 192 704

228 193 705

228 194 706

228 195 707

228 196 708

228 197 709

228 198 710

228 199 711

228 200 712

228 201 713

228 202 714

228 203 715

228 204 716

228 205 717

228 206 718

228 207 719

228 208 720

228 209 721

228 210 722

228 211 723

228 212 724

228 213 725

228 214 726

228 215 727

228 216 728

228 217 729

228 218 730

228 219 731

228 220 732

228 221 733

228 222 734

228 223 735

228 224 VTS Fast Block * * * VTS Fast Block 736

228 225 VTS Slow Block * * * VTS Slow Block 737

228 226 CTS Block * * * CTS Block 738

1 1,7 228 227 Control Trip * Control Trip 739

1 1,7 228 228 Control Close * Control Close 740

1 1,7 228 229 Close in Prog * Control Close in Progress 741

1 1,7 228 230 Reconnection *Reconnection Time Delay Output

742

1 1,7,9 228 231 RTD 1 Alarm * * * RTD 1 Alarm 743





Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 123/170


Inf. No.


ASDU TYPE COT






228 241 Lockout Alarm * * * * Composite lockout alarm 753

1 1,7,9 228 242 CB Open 3 ph * * * * 3 ph CB Open 754

1 1,7,9 228 243 CB Closed 3 ph * * * * 3 ph CB Closed 755

1 1,7,9 228 244 Field volts fail * * * *Field Voltage Failure (Alarm 66)

756

228 245 All Poles Dead * * * All Poles Dead 757

228 246 Any Pole Dead * * * Any Pole Dead 758

228 247 Pole Dead A * * * Phase A Pole Dead 759

228 248 Pole Dead B * * * Phase B Pole Dead 760

228 249 Pole Dead C * * * Phase C Pole Dead 761

228 250 VTS Acc Ind * * * Accelerate Ind 762

228 251 VTS Volt Dep * * * Any Voltage Dependent 763

228 252 VTS IA> * * * Ia over threshold 764

228 253 VTS IB> * * * Ib over threshold 765

228 254 VTS IC> * * * Ic over threshold 766

228 255 VTS VA> * * * Va over threshold 767

229 0 VTS VB> * * * Vb over threshold 768

229 1 VTS VC> * * * Vc over threshold 769

229 2 VTS I2> * * * I2 over threshold 770

229 3 VTS V2> * * * V2 over threshold 771

229 4 VTS IA delta> * * *Superimposed Ia over threshold

772

229 5 VTS IB delta> * * *Superimposed Ib over threshold

773

229 6 VTS IC delta> * * *Superimposed Ic over threshold

774

229 7 BFail SEF Trip-1 * * *CBF current prot SEF stage trip

775

229 8 BFail Non I Tr-1 * * *CBF non current prot stage trip

776

229 9 BFail SEF Trip * * * CBF current Prot SEF Trip 777

229 10 BFail Non I Trip * * * CBF Non Current Prot Trip 778

229 11 Freq High * * * Freq High 779

229 12 Freq Low * * * Freq Low 780

229 13 Freq Not found * * * Freq Not found 781

229 14 Stop Freq Track * * * Stop Freq Track 782

1 1,7 229 15 Recon LOM-1 * Reconnect LOM (unqualified) 783

1 1,7 229 16 Recon Disable-1 * Reconnect Disable (unqualified)

784

1 1,7 229 17 Recon LOM * Reconnect LOM 785

1 1,7 229 18 Recon Disable * Reconnect Disable 786

229 19 787

229 20 788

229 21 789

229 22 790

229 23 791

229 24 792

229 25 793

229 26 794

229 27 795

229 28 796

229 29 797

229 30 798

229 31 799

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 124/170


Inf. No.


ASDU TYPE COT

229 32 800

229 33 801

229 34 802

229 35 803

229 36 804

229 37 805

229 38 806

229 39 807

229 40 808

229 41 809

229 42 810

229 43 811

229 44 812

229 45 813

229 46 814

229 47 815

229 48 816

229 49 817

229 50 818

229 51 819

229 52 820

229 53 821

229 54 822

229 55 823

229 56 824

229 57 825

229 58 826

229 59 827

229 60 828

229 61 829

229 62 830

229 63 831

1 9,11,12,20,21 229 64 Control Input 1 * * * * Control Input 832



























Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 125/170


Inf. No.


ASDU TYPE COT






229 96 GOOSE VIP 1 864

229 97 GOOSE VIP 2 865

229 98 GOOSE VIP 3 866

229 99 GOOSE VIP 4 867

229 100 GOOSE VIP 5 868

229 101 GOOSE VIP 6 869

229 102 GOOSE VIP 7 870

229 103 GOOSE VIP 8 871

229 104 GOOSE VIP 9 872

229 105 GOOSE VIP 10 873

229 106 GOOSE VIP 11 874

229 107 GOOSE VIP 12 875

229 108 GOOSE VIP 13 876

229 109 GOOSE VIP 14 877

229 110 GOOSE VIP 15 878

229 111 GOOSE VIP 16 879

229 112 GOOSE VIP 17 880

229 113 GOOSE VIP 18 881

229 114 GOOSE VIP 19 882

229 115 GOOSE VIP 20 883

229 116 GOOSE VIP 21 884

229 117 GOOSE VIP 22 885

229 118 GOOSE VIP 23 886

229 119 GOOSE VIP 24 887

229 120 GOOSE VIP 25 888

229 121 GOOSE VIP 26 889

229 122 GOOSE VIP 27 890

229 123 GOOSE VIP 28 891

229 124 GOOSE VIP 29 892

229 125 GOOSE VIP 30 893

229 126 GOOSE VIP 31 894

229 127 GOOSE VIP 32 895

229 128 GOOSE VOP 1 896

229 129 GOOSE VOP 2 897

229 130 GOOSE VOP 3 898

229 131 GOOSE VOP 4 899

229 132 GOOSE VOP 5 900

229 133 GOOSE VOP 6 901

229 134 GOOSE VOP 7 902

229 135 GOOSE VOP 8 903

229 136 InterLogic I/P 1 904








229 144 InterLogic O/P 1 912






Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 126/170


Inf. No.


ASDU TYPE COT



229 152 Direct Ctrl 1 920








229 160 PSL Int. 1 * * * PSL Internal Node 1 928

















































Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 127/170


Inf. No.


ASDU TYPE COT















































1 1,7 229 255 Battery Fail * * * (Alarm 65)

230 0 Unused (Alarm 67)

1 1,7 230 1 GOOSE IED Absent * * * (Alarm 68)

1 1,7 230 2 NIC not fitted * * * (Alarm 69)

1 1,7 230 3 NIC no response * * * (Alarm 70)

1 1,7 230 4 NIC fatal error * * * (Alarm 71)

1 1,7 230 5 NIC Software Reload * * * (Alarm 72)

1 1,7 230 6 Bad TCP/IP Configuration * * * (Alarm 73)

1 1,7 230 7 Bad OSI Configuration * * * (Alarm 74)

1 1,7 230 8 NIC Link Fail * * * (Alarm 75)

1 1,7 230 9 NIC SW-Mismatch * * * (Alarm 76)

1 1,7 230 10 IP addr conflict * * * (Alarm 77)


Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 128/170


Inf. No.


ASDU TYPE COT



















1 2 3 4 5 6

20 20 229 64 Control Input 1 * * * Control Input 832
































DDB Ordinal

Private Range Information Numbers in Control Direction

ASDU TYPE COT DDB Signal DescriptionFUNInf. No.

Display Text (English)Model Number

GI

Relay Menu Database

MiCOM P342, P343

P34x/EN GC/F33

Page 129/170


Inf. No.


ASDU TYPE COT

ACC Standard

0 Global Null Channel

1 IL1

2 IL2

3 IL3

4 IN

5 VL1E

6 VL2E

7 VL3E

8 VEN

64 - IN Sensitive

65 -

66 -

67 -

245 - SampleTime

Disturbance Data Actual Channel Identifiers

IB

IA

Interpretation

IN

IC

IC-2

IB-2

IA-2

VBN

VAN

VN

VCN


Page 130/170 MiCOM P342, P343

1. INTRODUCTION

The purpose of this document is to describe the specific implementation of theDistributed Network Protocol (DNP) version 3.0 within P340 MiCOM relays.

The MiCOM P340 uses the Triangle MicroWorks, Inc. DNP 3.0 Slave Source CodeLibrary version 2.31.

This document, in conjunction with the DNP 3.0 Basic 4 Document Set, and the DNPSubset Definitions Document, provides complete information on how to communicatewith P340 relays with the DNP 3.0 protocol.

This implementation of DNP 3.0 is fully compliant with DNP 3.0 Subset DefinitionLevel 2. It also contains many Subset Level 3 and above features.

2. DNP V3.0 DEVICE PROFILE

The following table provides a “Device Profile Document” in the standard formatdefined in the DNP 3.0 Subset Definitions Document. While it is referred to in theDNP 3.0 Subset Definitions as a “Document”, it is only a component of a totalinteroperability guide. This table, in combination with the following should provide acomplete interoperability/configuration guide for the P340 range of MiCOM relays:

• The Implementation Table provided in Section §3

• The Point List Tables provided in Section §4


MiCOM P342, P343 Page 131/170

DNP 3.0Device Profile Document

Vendor Name: ALSTOM T&D Ltd – Energy Automation and Information

Device Name: MiCOM P340 Generator Protection

Models Covered: • P341****4*0070*• P342****4*0070*• P343****4*0070*

Highest DNP Level Supported:For Requests: Level 2For Responses: Level 2

Device Function: Master Slave

Notable objects, functions, and/or qualifiers supported in addition to the highest DNP levelssupported (the complete list is described in the DNP 3.0 Implementation Table):• For static (non-change event) object requests, request qualifier codes 00

and 01 (start-stop), 07 and 08 (limited quantity), and 17 and 28 (index) aresupported in addition to the request qualifier code 06 (no range (allpoints)).

• Static object requests sent with qualifiers 00, 01, 06, 07, or 08 will beresponded with qualifiers 00 or 01.

• Static object requests sent with qualifiers 17 or 28 will be responded withqualifiers 17 or 28.

• For change-event object requests, qualifiers 17 or 28 are always responded.• 16-bit and 32-bit analog change events with time may be requested.• The read function code for Object 50 (time and date) variation 1 is

supported.

Maximum Data Link Frame Size (octets):Transmitted: 292Received: 292

Maximum Application Fragment Size (octets)Transmitted: 2048Received: 249

Maximum Data Link Retries: None Fixed at 2 Configurable

Maximum Application Layer Retries: None Configurable

Requires Data Link Layer Confirmation: Never Always Sometimes Configurable

Requires Application Layer Confirmation: Never Always When reporting event data When sending multi-fragment

responses Sometimes Configurable


Page 132/170 MiCOM P342, P343

Timeouts while waiting for:

Data Link Confirm: None Fixed at 100ms

Variable Configurable

Complete Appl. Fragment: None Fixed at ___ Variable Configurable

Application Confirm: None Fixed at 1s

Variable Configurable

Complete Appl. Response: None Fixed at ___ Variable Configurable

Others:

Inter-character Delay: 4 character times at selected baud rate

Select/Operate Arm Timeout: Default 10s

Need Time Interval: Configurable, 0 or 30min

Sends/Executes Control Operations:

Write Binary Outputs: Never Always Sometimes Configurable

Select/Operate: Never Always Sometimes Configurable

Direct Operate: Never Always Sometimes Configurable

Direct Operate – No Ack: Never Always Sometimes Configurable

Count > 1 Never Always Sometimes Configurable

Pulse On/NUL/Trip/Close Never Always Sometimes Configurable

Pulse Off/NUL/Trip/Close Never Always Sometimes Configurable

Latch On/NUL Never Always Sometimes Configurable

Latch Off/NUL Never Always Sometimes Configurable

Queue Never Always Sometimes Configurable

Clear Queue Never Always Sometimes ConfigurableNote: The applicability of the Pulse On, Latch On, & Latch Off control operations is specified in the Object10/12 point list table in section §4.2.

Reports Binary Input Change Events when nospecific variation requested: Never Only time-tagged variation 2 Only non-time-tagged Configurable

Reports time-tagged Binary Input ChangeEvents when no specific variation requested: Never Binary input change with time Binary input change with relative time Configurable

Sends Unsolicited Responses: Never Configurable Certain objects only Sometimes Enable/Disable unsolicited functions

codes supported

Sends Static Data in Unsolicited Responses: Never When device restarts When status flags changes

No other options are permitted.


MiCOM P342, P343 Page 133/170

Default Counter Object/Variation: No counters reported Configurable Default object: 20 Default variation: 5 Point-by-point list attached

Counters Roll Over at: No counters reported Configurable 16 bits 32 bits Other value: _____ Point-by-point list attached

Sends multi-fragment responses: Yes No

3. IMPLEMENTATION TABLE

The following table identifies the variations, function codes, and qualifiers supportedby the P340 in both request and response messages.

For static (non-change-event) objects, requests sent with qualifiers 00, 01, 06, 07, or08, will be responded with qualifiers 00 or 01. Static object requests sent withqualifiers 17 or 28 will be responded with qualifiers 17 or 28. For change-eventobjects, qualifiers 17 or 28 are always responded.

Object Request Response

ObjectNumber

VariationNumber

DescriptionFunction Codes

(dec)Qualifier Codes

(hex)Function

Codes (dec)Qualifier Codes

(hex)

1 0 Binary Input (Variation 0is used to request defaultvariation)

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

1 1

(default –see note 1)

Binary Input without Flag 1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)

(index –see note 2)

1 2 Binary Input with Flag 1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


2 0 Binary Input Change(Variation 0 is used torequest default variation)

1 (read) 06

07, 08

(no range, or all)

(limited qty)

2 1 Binary Input Changewithout Time

1 (read) 06

07, 08

(no range, or all)

(limited qty)

129 (response) 17, 28 (index)

2 2


Binary Input Change withTime

1 (read) 06

07, 08

(no range, or all)

(limited qty)


10 0 Binary Output Status(Variation 0 is used torequest default variation)

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

10 2


Binary Output Status 1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)



Page 134/170 MiCOM P342, P343


ObjectNumber

VariationNumber



(hex)Function


(hex)

12 1 Control Relay OutputBlock

3

4

5

6

(select)

(operate)

(direct op)

(dir. op, no ack)

00, 01

06

07, 08

17, 28

(start-stop)

(limited qty)

(index)

129 (response) echo of request

20 0 Binary Counter (Variation0 is used to requestdefault variation)

1

7

8

9

10

(read)

(freeze)

(freeze no ack)

(freeze clear)

(frz. cl. no ack)

00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

20 1 32-Bit Binary Counterwith Flag

1

7

8

9

10

(read)

(freeze)

(freeze no ack)

(freeze clear)

(frz. cl. no ack)

00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


20 2 16-Bit Binary Counterwith Flag

1

7

8

9

10

(read)

(freeze)

(freeze no ack)

(freeze clear)

(frz. cl. no ack)

00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


20 5


32-Bit Binary Counterwithout Flag

1

7

8

9

10

(read)

(freeze)

(freeze no ack)

(freeze clear)

(frz. cl. no ack)

00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


20 6 16-Bit Binary Counterwithout Flag

1

7

8

9

10

(read)

(freeze)

(freeze no ack)

(freeze clear)

(frz. cl. no ack)

00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


21 0 Frozen Counter(Variation 0 is used torequest default variation)

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

21 1 32-Bit Frozen Counterwith Flag

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


21 2 16-Bit Frozen Counterwith Flag

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


21 9


32-Bit Frozen Counterwithout Flag

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


21 10 16-Bit Frozen Counterwithout Flag

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)



MiCOM P342, P343 Page 135/170


ObjectNumber

VariationNumber



(hex)Function


(hex)

30 0 Analog Input (Variation 0is used to request defaultvariation)

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

30 1 32-Bit Analog Input 1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


30 2


16-Bit Analog Input 1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


30 3 32-Bit Analog Inputwithout Flag

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


30 4 16-Bit Analog Inputwithout Flag

1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


32 0 Analog Change Event(Variation 0 is used torequest default variation)

1 (read) 06

07, 08

(no range, or all)

(limited qty)

32 1 32-Bit Analog ChangeEvent without Time

1 (read) 06

07, 08

(no range, or all)

(limited qty)


32 2


16-Bit Analog ChangeEvent without Time

1 (read) 06

07, 08

(no range, or all)

(limited qty)


32 3 32-Bit Analog ChangeEvent with Time

1 (read) 06

07, 08

(no range, or all)

(limited qty)


32 4 16-Bit Analog ChangeEvent with Time

1 (read) 06

07, 08

(no range, or all)

(limited qty)


50 0 Time and Date 1 (read) 00, 01

06

07, 08

17, 28

(start-stop)

(no range, or all)

limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


50 1


Time and Date 1

2

(read)

(write)

00, 01

06

07

08

17, 28

(start-stop)

(no range, or all)

(limited qty = 1)

(limited qty)

(index)

129 (response) 00, 01

17, 28

(start-stop)


52 2 Time Delay Fine 129 (response) 07 (limitedqty)

(qty = 1)

60 0 Class 0, 1, 2, and 3Data

1 (read) 06 (no range, or all)

60 1 Class 0 Data 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)

60 2 Class 1 Data 1 (read) 06

07, 08

(no range, or all)

(limited qty)



07, 08

(no range, or all)

(limited qty)



07, 08

(no range, or all)

(limited qty)



Page 136/170 MiCOM P342, P343


ObjectNumber

VariationNumber



(hex)Function


(hex)

80 1 Internal Indications 1 (write) 00 (start–stop)(index must = 7)

No Object (function codeonly)

13 (cold restart)


1 (warm restart)


1 (delay meas.)

Notes:

1. A Default variation refers to the variation responded when variation 0 isrequested and/or in class 0, 1, 2, or 3 scans.

2. For static (non-change-event) objects, qualifiers 17 or 28 are only respondedwhen a request is sent with qualifiers 17 or 28, respectively. Otherwise, staticobject requests sent with qualifiers 00, 01, 06, 07, or 08, will be respondedwith qualifiers 00 or 01. (For change-event objects, qualifiers 17 or 28 arealways responded.)

4. POINT LIST

The tables in the following sections identify all the individual data points provided bythis implementation of DNP 3.0.

4.1 Binary input points

The Binary Input objects (1 & 2) provide read-only access to a sub-set of the P340’sdigital data bus (DDB).

By default, all the static object (object 1) points belong to the Class 0 data set. Thedefault allocation of the points in the change-event object (object 2) to a change-event class (1, 2, 3) is indicated in the point-list table below. The MiCOM S1 settingsupport software may be used to alter both of these assignments. However,deselecting a point from class 0 also has the effect of removing the point from thepoint-list of objects 1 & 2 and renumbering the remaining points to ensure the pointindices are contiguous.

The validity of each point is reported through the “online” bit in the “flag”, which issupplied for each point with the “with flag” object variations. Points reported asbeing offline, will typically be points that are invalid for the relay’s currentconfiguration, which is a product of its model number and current settings.


MiCOM P342, P343 Page 137/170

Binary Input PointsStatic (Steady-State) Object Number: 1Change Event Object Number: 2Request Function Codes supported: 1 (read)Static Variation reported when variation 0 requested: 1 (Binary Input without status)Change Event Variation reported when variation 0 requested: 2 (Binary Input Change with Time)

P341PointIndex

P342PointIndex

P343PointIndex

Name/DescriptionDDBNO

DefaultChange

Event Class(1, 2, 3, or

none)

InitialValue

Output Relay Status

0 0 0 Output Relay 1 0 2 False
























24 Output Relay 25 24 2 False









Page 138/170 MiCOM P342, P343


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

Opto Isolator Input Status

24 24 32 Opto Isolator Input 1 32 2 False
























56 Opto Isolator Input 25 56 2 False









MiCOM P342, P343 Page 139/170


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

Alarm & Event Indications

48 48 64 Setting Group via Opto Invalid 290 2 False

49 49 65 Test Mode Enabled 291 2 False

50 50 66 VTS Indication 292 2 False

51 51 67 CTS Indication 293 2 False

52 52 68 Breaker Fail Any Trip 294 2 False

53 53 69 Broken Current Maintenance Alarm 295 2 False

54 54 70 Broken Current Lockout Alarm 296 2 False

55 55 71 Number of CB Operations Maintenance Alarm 297 2 False

56 56 72Number of CB Operations MaintenanceLockout 298 2 False

57 57 73Excessive CB Operation Time MaintenanceAlarm

299 2 False

58 58 74 Excessive CB Operation Time Lockout Alarm 300 2 False

59 59 75 Excessive Fault Frequency Lockout Alarm 301 2 False

60 60 76 CB Status Alarm 302 2 False

61 CB Failed to Trip 303 2 False

62 CB Failed to Close 304 2 False

63 Control CB Unhealthy 305 2 False

64 Frequency Out of Range 306 2 False

61 77 Negative Phase Sequence Alarm 306 2 False

65 62 78 Thermal Overload Alarm 307 2 False

63 79 Volts Per Hz Alarm 308 2 False

64 80 Field Failure Alarm 309 2 False

65 81 RTD Thermal Alarm 310 2 False

66 82 RTD Open Circuit Failure 311 2 False

67 83 RTD Short Circuit Failure 312 2 False

68 84 RTD Data Inconsistency Error 313 2 False

69 85 RTD Board Failure 314 2 False

66 70 86 Frequency Protection Alarm 315 2 False

67 71 87 Voltage Protection Alarm 316 2 False

68 72 88 User Definable Alarm 1 (Self Reset) 351 2 False




Page 140/170 MiCOM P342, P343


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

75 91 RTD 1 Alarm 743 2 False










71 85 101 Composite Lockout Alarm 753 2 False

72 86 102 Field Voltage Failure 756 2 False

Miscellaneous Indications

73 87 103 Battery Status N/A 2 False

74 88 104 IRIG-B Status N/A 2 False

Protection Operation Signals

75 89 105 Any Trip 162 2 False

76 90 106 External Trip 3ph 380 2 False

107 100% Stator Earth Fault Trip 416 2 False

108 Dead Machine Protection Trip 417 2 False

109 Generator Differential Trip 3ph 418 2 False

110 Generator Differential Trip A 419 2 False

111 Generator Differential Trip B 420 2 False

112 Generator Differential Trip C 421 2 False

91 113 Field Failure Stage 1 Trip 422 2 False

92 114 Field Failure Stage 2 Trip 423 2 False

93 115 Negative Phase Sequence Trip 424 2 False

94 116 Voltage Dependant Over Current Trip 3ph 425 2 False

95 117 Voltage Dependant Over Current Trip A 426 2 False

96 118 Voltage Dependant Over Current Trip B 427 2 False

97 119 Voltage Dependant Over Current Trip C 428 2 False

98 120 Volts per Hz Trip 429 2 False

99 121 RTD 1 Trip 430 2 False



MiCOM P342, P343 Page 141/170


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue








108 130 RTD 10 Trip 439 2 False

109 131 Any RTD Trip 440 2 False

77 Rate Of Change Of Frequency Trip 440 2 False

78 Voltage Vector Shift Trip 441 2 False

79 110 132 1st Stage EF Trip 442 2 False

80 111 133 2nd Stage EF Trip 443 2 False

81 3rd Stage EF Trip 444 2 False

82 4th Stage EF Trip 445 2 False

83 112 134 REF Trip 446 2 False

84 113 135 1st Stage SEF Trip 447 2 False

85 2nd Stage SEF Trip 448 2 False

86 3rd Stage SEF Trip 449 2 False

87 4th Stage SEF Trip 450 2 False

88 114 136 1st Stage Residual O/V Trip 451 2 False

89 115 137 2nd Stage Residual O/V Trip 452 2 False

90 116 138 1st Stage Phase U/V Trip 3ph 453 2 False

91 117 139 1st Stage Phase U/V Trip A/AB 454 2 False

92 118 140 1st Stage Phase U/V Trip B/BC 455 2 False

93 119 141 1st Stage Phase U/V Trip C/CA 456 2 False

94 120 142 2nd Stage Phase U/V Trip 3ph 457 2 False

95 121 143 2nd Stage Phase U/V Trip A/AB 458 2 False

96 122 144 2nd Stage Phase U/V Trip B/BC 459 2 False

97 123 145 2nd Stage Phase U/V Trip C/CA 460 2 False

98 124 146 1st Stage Phase O/V Trip 3ph 461 2 False

99 125 147 1st Stage Phase O/V Trip A/AB 462 2 False

100 126 148 1st Stage Phase O/V Trip B/BC 463 2 False

101 127 149 1st Stage Phase O/V Trip C/CA 464 2 False


Page 142/170 MiCOM P342, P343


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

102 128 150 2nd Stage Phase O/V Trip 3ph 465 2 False

103 129 151 2nd Stage Phase O/V Trip A/AB 466 2 False

104 130 152 2nd Stage Phase O/V Trip B/BC 467 2 False

105 131 153 2nd Stage Phase O/V Trip C/CA 468 2 False

106 132 154 Under Frequency Stage 1 Trip 469 2 False




110 136 158 Over Frequency Stage 1 Trip 473 2 False

111 137 159 Over Frequency Stage 2 Trip 474 2 False

112 138 160 Power Stage 1 Trip 475 2 False

113 139 161 Power Stage 2 Trip 476 2 False

114 140 162 1st Stage O/C Trip 3ph 477 2 False

115 141 163 1st Stage O/C Trip A 478 2 False

116 142 164 1st Stage O/C Trip B 479 2 False

117 143 165 1st Stage O/C Trip C 480 2 False

118 144 166 2nd Stage O/C Trip 3ph 481 2 False

119 145 167 2nd Stage O/C Trip A 482 2 False

120 146 168 2nd Stage O/C Trip B 483 2 False

121 147 169 2nd Stage O/C Trip C 484 2 False

122 3rd Stage O/C Trip 3ph 485 2 False

123 3rd Stage O/C Trip A 486 2 False

124 3rd Stage O/C Trip B 487 2 False

125 3rd Stage O/C Trip C 488 2 False

126 4th Stage O/C Trip 3ph 489 2 False

127 4th Stage O/C Trip A 490 2 False

128 4th Stage O/C Trip B 491 2 False

129 4th Stage O/C Trip C 492 2 False

130 148 170 tBF1 Trip 3ph 493 2 False

131 149 171 tBF2 Trip 3ph 494 2 False

132 150 172 Sensitive A Phase Power Stage 1 Trip 495 2 False

133 151 173 Sensitive A Phase Power Stage 2 Trip 496 2 False

174 Pole Slip (Impedance) Zone1 Trip 497 2 False

175 Pole Slip (Impedance) Zone2 Trip 498 2 False


MiCOM P342, P343 Page 143/170


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

134 152 176 Thermal Overload Trip 499 2 False

153 177 Under Impedance 3 Phase Stage 1 Trip 500 2 False

154 178 Under Impedance Phase A Stage 1 Trip 501 2 False

155 179 Under Impedance Phase B Stage 1 Trip 502 2 False

156 180 Under Impedance Phase C Stage 1 Trip 503 2 False

157 181 Under Impedance 3 Phase Stage 2 Trip 504 2 False

158 182 Under Impedance Phase A Stage 2 Trip 505 2 False

159 183 Under Impedance Phase B Stage 2 Trip 506 2 False

160 184 Under Impedance Phase C Stage 2 Trip 507 2 False

135 161 185 Any Start 576 2 False

136 162 186 1st Stage Residual O/V Start 577 2 False

137 163 187 2nd Stage Residual O/V Start 578 2 False

138 164 188 1st Stage Phase U/V Start 3ph 579 2 False

139 165 189 1st Stage Phase U/V Start A/AB 580 2 False

140 166 190 1st Stage Phase U/V Start B/BC 581 2 False

141 167 191 1st Stage Phase U/V Start C/CA 582 2 False

142 168 192 2nd Stage Phase U/V Start 3ph 583 2 False

143 169 193 2nd Stage Phase U/V Start A/AB 584 2 False

144 170 194 2nd Stage Phase U/V Start B/BC 585 2 False

145 171 195 2nd Stage Phase U/V Start C/CA 586 2 False

146 172 196 1st Stage Phase O/V Start 3ph 587 2 False

147 173 197 1st Stage Phase O/V Start A/AB 588 2 False

148 174 198 1st Stage Phase O/V Start B/BC 589 2 False

149 175 199 1st Stage Phase O/V Start C/CA 590 2 False

150 176 200 2nd Stage Phase O/V Start 3ph 591 2 False

151 177 201 2nd Stage Phase O/V Start A/AB 592 2 False

152 178 202 2nd Stage Phase O/V Start B/BC 593 2 False

153 179 203 2nd Stage Phase O/V Start C/CA 594 2 False

154 180 204 Power Stage 1 Start 595 2 False

155 181 205 Power Stage 2 Start 596 2 False

156 182 206 1st Stage O/C Start 3ph 597 2 False

157 183 207 1st Stage O/C Start A 598 2 False

158 184 208 1st Stage O/C Start B 599 2 False

159 185 209 1st Stage O/C Start C 600 2 False


Page 144/170 MiCOM P342, P343


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

160 186 210 2nd Stage O/C Start 3ph 601 2 False

161 187 211 2nd Stage O/C Start A 602 2 False

162 188 212 2nd Stage O/C Start B 603 2 False

163 189 213 2nd Stage O/C Start C 604 2 False

164 3rd Stage O/C Start 3ph 605 2 False

165 3rd Stage O/C Start A 606 2 False

166 3rd Stage O/C Start B 607 2 False

167 3rd Stage O/C Start C 608 2 False

168 4th Stage O/C Start 3ph 609 2 False

169 4th Stage O/C Start A 610 2 False

170 4th Stage O/C Start B 611 2 False

171 4th Stage O/C Start C 612 2 False

172 190 214 1st Stage EF Start 613 2 False

173 191 215 2nd Stage EF Start 614 2 False

174 3rd Stage EF Start 615 2 False

175 4th Stage EF Start 616 2 False

176 192 216 1st Stage SEF Start 617 2 False

177 2nd Stage SEF Start 618 2 False

178 3rd Stage SEF Start 619 2 False

179 4th Stage SEF Start 620 2 False

217 100% Stator Earth Fault Start 621 2 False

180 193 218 Under Frequency Stage 1 Start 622 2 False




184 197 222 Over Frequency Stage 1 Start 626 2 False

185 198 223 Over Frequency Stage 2 Start 627 2 False

186 I> Blocked O/C Start 628 2 False

187 IN/ISEF> Blocked O/C Start 629 2 False

188 Rate Of Change Of Frequency Start 630 2 False

199 224 Volts per Hz Start 636 2 False

200 225 Field Failure Stage 1 Start 637 2 False

201 226 Field Failure Stage 2 Start 638 2 False

202 227 Voltage Dependant Over Current Start 3Ph 639 2 False


MiCOM P342, P343 Page 145/170


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

203 228 Voltage Dependant Over Current Start A 640 2 False

204 229 Voltage Dependant Over Current Start B 641 2 False

205 230 Voltage Dependant Over Current Start C 642 2 False

189 206 231 Sensitive A Phase Power Stage 1 Start 643 2 False

190 207 232 Sensitive A Phase Power Stage 2 Start 644 2 False

233 Pole Slip (Impedance) Zone1 Start 645 2 False

234 Pole Slip (Impedance) Zone2 Start 646 2 False

235 Pole Slip (impedance) Lens Start 647 2 False

236 Pole Slip (impedance) Blinder Start 648 2 False

237 Pole Slip (impedance) Reactance Line Start 649 2 False

208 238 Under Impedance 3Phase Stage 1 Start 650 2 False

209 239 Under Impedance Phase A Stage 1 Start 651 2 False

210 240 Under Impedance Phase B Stage 1 Start 652 2 False

211 241 Under Impedance Phase C Stage 1 Start 653 2 False

212 242 Under Impedance 3Phase Stage 2 Start 654 2 False

213 243 Under Impedance Phase A Stage 2 Start 655 2 False

214 244 Under Impedance Phase B Stage 2 Start 656 2 False

215 245 Under Impedance Phase C Stage 2 Start 657 2 False

191 216 246 VTS Fast Block 736 2 False

192 217 247 VTS Slow Block 737 2 False

193 218 248 CTS Block 738 2 False

194 Control Trip 739 2 False

195 Control Close 740 2 False

196 Control Close in Progress 741 2 False

197 Reconnection Time Delay Output 742 2 False

CB Status

198 219 249 3 ph CB Open 754 2 False

199 220 250 3 ph CB Closed 755 2 False

200 221 251 IA< Operate 631 2 False

201 222 252 IB< Operate 632 2 False

202 223 253 IC< Operate 633 2 False

203 224 254 ISEF< Operate 634 2 False

225 255 IN< Operate 635 2 False

204 226 256 All Poles Dead 757 2 False


Page 146/170 MiCOM P342, P343


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

205 227 257 Any Pole Dead 758 2 False

206 228 258 Phase A Pole Dead 759 2 False

207 229 259 Phase B Pole Dead 760 2 False

208 230 260 Phase C Pole Dead 761 2 False

New in software version 07

Alarm Signals

209 231 261 CLIO Input Board Failure 320 2 False

210 232 262 CLIO Output Board Failure 321 2 False

211 233 263 Current Loop Input 1 Alarm 322 2 False




215 237 267 Current Loop Input 1 Undercurrent Fail Alarm 326 2 False




219 241 271 User Definable Alarm 16 (Manual Reset) 336 2 False













Trip Signals

232 254 284 Current Loop Input 1 Trip 508 2 False





MiCOM P342, P343 Page 147/170


P341PointIndex

P342PointIndex

P343PointIndex


DefaultChange


none)

InitialValue

Start Signals

236 258 288 Current Loop Input 1 Alarm Start 658 2 False




240 262 292 Current Loop Input 1 Trip Start 662 2 False




4.2 Binary output status points and control relay output block

The following table lists both the Binary Output Status Points (Object 10) and theControl Relay Output Block (Object 12).

Binary Output Status points are included in Class 0 data set. (Since there is not achange-event object for the binary outputs, the binary output points are not part ofthe class 1, 2, or 3 data sets). It is not possible to configure the class 0 membershipof this object with MiCOM S1.


The Control Relay Output Block (CROB) implementation is compliant with the DNPtechnical bulletin TB2000-006, which rescinds CROB behaviours specified in theoriginal four document set and addendum sub-set documents.

The following text is a brief summary of DNP technical bulletin TB2000-006:

Each control point in the CROB may be either a "complimentary control function" or a"single function".

Examples of complimentary control functions are:

• Trip and close

• On and Off

Examples of single-function controls are:

• Trip

• Activate


Page 148/170 MiCOM P342, P343

A point index cannot support both complimentary and single-function methods ofoperation.

Complimentary control function points require the use of a complementary control-code pair. The CROB provides two sets of control pairs:

• Code 0316 "Latch On" and code 0416 "Latch Off"

• Code 4116 "Pulse On/Close" and code 8116 "Pulse On/Trip"

In DNP there is no significance to these codes; they do the same thing. Acomplimentary-control point may "permit" either or both of these pairs. If a pointpermits both pairs of codes then:

• Latch On and Pulse Close must perform the same function

• Latch Off and Pulse Trip must perform the same function

Single-function control points may permit one or more of the following control codes:

• Code 0116 "Pulse On"

• Code 0316 "Latch On"

• Code 0416 "Latch Off"

• Code 4116 "Pulse On/Close

• Code 8116 "Pulse On/Trip"

There is no significance to these codes; they do the same thing. Each of thepermitted single-function codes must perform the same function on a given single-function point index.

The original DNP 3.0 specification for the CROB "exposes the details of the devicehardware to the protocol stack. This is unnecessary and creates interoperabilityissues". Moreover, "some IED vendors have implemented points that do differentthings based on the control code that is sent. " E.g. a point latches for the latch codesand pulses for the pulse codes. "This perverts the original intent of the CROB andmakes it impossible for masters that statically configure control codes to beinteroperable with such [IEDs]. This type of implementation is also not transportableacross legacy protocol boundaries."

In the following table, point indices that are marked as “unpaired” will accept thecorrespondingly marked control codes and treat them identically as a “trigger” for thecommand action associated with the point. Unpaired points do not have a statevalue that can be read and a read request, whilst completing successfully, will alwaysreturn a value of zero.

Points that are marked as “paired” behave as complimentary-controls and have astate value that can be read. The Latch On and Pulse On/Close control-codes set thespecified output status point whilst the Latch Off and Pulse On/Trip codes reset it.

The Count field is not supported and must be either zero or one. The On-time, andOff-time fields are ignored. The Queue and Clear bits in the Control-Code field arenot supported and must be zero. The “Pulse Off” control-code code is not supported.


MiCOM P342, P343 Page 149/170

Binary Output Status PointsObject Number: 10Request Function Code supported: 1 (read)Default Variation reported when variation 0 requested: 2 (Binary Output Status)Control Relay Output Blocks (CROB)Object Number: 12Request Function Code supported: 3 (select), 4 (operate), 5 (direct operate), 6 (direct operate, no ack)

Supported CROB Fields

P341PointIndex

P342PointIndex

P343PointIndex

Name/Description

Pa

ired

Un

pa

ired

Latc

h O

n

Latc

h O

ff

Pu

lse O

n

Pu

lse O

n/C

lose

Pu

lse O

n/T

rip

Setting Group Control:

0 0 0 Activate Setting Group 1 * * * * *




Control Commands:

4 Initiate CB Trip * * * * * *

5 Initiate CB Close * * * * * *

6 4 4 Reset Indication * * * * *

7 5 5 Reset Demand * * * * *

6 6 Reset Negative Phase Sequence Thermal Replica * * * * *

8 7 7 Reset Thermal Overload Replica * * * * *

9 8 8 Clear Event Records * * * * *

10 9 9 Clear Fault Records * * * * *

11 10 10 Clear Maintenance Records * * * * *

12 11 11 Test LEDs * * * * *

13 12 12 Reset Lockout * * * * *

14 13 13 Reset CB Data * * * * *

14 14 Reset RTD Flags * * * * *

Scheme Logic Control Input Signals:

15 15 15 Control Input 1 * * * * *

16 16 16 Control Input 2 * * * * *

17 17 17 Control Input 3 * * * * *

18 18 18 Control Input 4 * * * * *

19 19 19 Control Input 5 * * * * *

20 20 20 Control Input 6 * * * * *

21 21 21 Control Input 7 * * * * *

22 22 22 Control Input 8 * * * * *

23 23 23 Control Input 9 * * * * *

24 24 24 Control Input 10 * * * * *

25 25 25 Control Input 11 * * * * *


Page 150/170 MiCOM P342, P343

Binary Output Status PointsObject Number: 10Request Function Code supported: 1 (read)Default Variation reported when variation 0 requested: 2 (Binary Output Status)Control Relay Output Blocks (CROB)Object Number: 12Request Function Code supported: 3 (select), 4 (operate), 5 (direct operate), 6 (direct operate, no ack)

Supported CROB Fields

P341PointIndex

P342PointIndex

P343PointIndex

Name/Description

Pa

ired

Un

pa

ired

Latc

h O

n

Latc

h O

ff

Pu

lse O

n

Pu

lse O

n/C

lose

Pu

lse O

n/T

rip

26 26 26 Control Input 12 * * * * *

27 27 27 Control Input 13 * * * * *

28 28 28 Control Input 14 * * * * *

29 29 29 Control Input 15 * * * * *

30 30 30 Control Input 16 * * * * *

31 31 31 Control Input 17 * * * * *

32 32 32 Control Input 18 * * * * *

33 33 33 Control Input 19 * * * * *

34 34 34 Control Input 20 * * * * *

35 35 35 Control Input 21 * * * * *

36 36 36 Control Input 22 * * * * *

37 37 37 Control Input 23 * * * * *

38 38 38 Control Input 24 * * * * *

39 39 39 Control Input 25 * * * * *

40 40 40 Control Input 26 * * * * *

41 41 41 Control Input 27 * * * * *

42 42 42 Control Input 28 * * * * *

43 43 43 Control Input 29 * * * * *

44 44 44 Control Input 30 * * * * *

45 45 45 Control Input 31 * * * * *

46 46 46 Control Input 32 * * * * *

4.3 Counters

The following table lists both Binary Counters (Object 20) and Frozen Counters(Object 21). When a freeze function is performed on a Binary Counter point, thefrozen value is available in the corresponding Frozen Counter point.

By default the Binary Counters (object 20) and Frozen Counters (object 21) areincluded in class 0 polls. The MiCOM S1 setting support software may be used toalter both of these assignments. (Since there is not a change-event object for theBinary Counters or Frozen Counters, the counter points are not part of the class 1, 2,or 3 data sets). However, deselecting a point from class 0 also has the effect ofremoving the point from the point-list of the associated object (20 or 21) andrenumbering the remaining points to ensure the point indices are contiguous.


MiCOM P342, P343 Page 151/170

Moreover, if a point is deselected from the running counter object (20) then it is alsodeselected from the frozen counter object (21).


Binary Counter PointsStatic (Steady-State) Object Number: 20Request Function Code supported: 1(read), 7(freeze), 8(freeze no ack), 9(freeze and clear),

10(freeze and clear, no ack)Static Variation reported when variation 0 requested: 5 (32-Bit Binary Counter without Flag)Change Event Variation reported when variation 0 requested: none – not supportedFrozen Counter PointsStatic (Steady State) Object Number: 21Request Function Code supported: 1 (read)Static Variation reported when variation 0 requested: 9 (32-Bit Binary Counter without Flag)Change Event Variation reported when variation 0 requested: none – not supported

P341PointIndex

P342PointIndex

P343PointIndex

Name/Description Data Type

0 0 0 3Ph WHours Fwd D10

1 1 1 3Ph WHours Rev D10

2 2 2 3Ph VArHours Fwd D10

3 3 3 3Ph VArHours Rev D10

4 4 4 CB Operations -

4.4 Analog inputs

The following table lists the Analog Inputs (Object 30).

For each point, the “Data Type” code refers to the points scaling information insection §4.5; analog values are provided in a fixed-point integer format derived fromthe relay’s internal per-unit quantities. The scaling information associated with eachdata-type code, in section §4.5, will result in an equivalent secondary (i.e. relay input)value. Additional scaling will be required to produce the primary (i.e. power system)values.

By default, all the static object (object 30) points belong to the Class 0 data set. The“Default Deadband”, and the “Default Change Event Assigned Class” columns areused to represent the absolute amount by which the point must change before ananalog change event will be generated. The default allocation of the points in thechange-event object (object 32) to a change-event class (1, 2, 3) is also indicated.The class 0, deadband, and event class values may be changed with the MiCOM S1setting support software. However, deselecting a point from class 0 also has theeffect of removing the point from the point-list of objects 30 & 32 and renumberingthe remaining points to ensure the point indices are contiguous.



Page 152/170 MiCOM P342, P343

Analog InputsStatic (Steady State) Object Number: 30Change Event Object Number: 32Request Function Codes supported: 1 (read)Static Variation reported when variation 0 requested: 2 (16-Bit Analog Input)Change Event Variation reported when variation 0 requested: 2 (16-Bit Analog Change Event without

Time)

P341PointIndex

P342PointIndex

P343PointIndex

Name/Description DataType Valid Range Default

Deadband

DefaultChange


none)

Active Group

0 0 0 Active Group D9 1…4 1 3

Measurements 1

1 1 IA Magnitude D1 0.000…65.534 0.1 3

2 2 IA Phase Angle D4 -180.00…+180.00 1 3

3 3 IB Magnitude D1 0.000…65.534 0.1 3

4 4 IB Phase Angle D4 -180.00…+180.00 1 3

5 5 IC Magnitude D1 0.000…65.534 0.1 3

6 6 IC Phase Angle D4 -180.00…+180.00 1 3

1 IA-1 Magnitude D1 0.000…65.534 0.1 3

2 IA-1 Phase Angle D4 -180.00…+180.00 1 3

3 IB-1 Magnitude D1 0.000…65.534 0.1 3

4 IB-1 Phase Angle D4 -180.00…+180.00 1 3

5 IC-1 Magnitude D1 0.000…65.534 0.1 3

6 IC-1 Phase Angle D4 -180.00…+180.00 1 3

7 7 IN Measured Mag D2 0.0000…2.0000 0.01 3

8 8 IN Measured Ang D4 -180.00…+180.00 1 3

7 IN Derived Mag D1 0.000…65.534 0.1 3

8 IN Derived Angle D4 -180.00…+180.00 1 3

9 9 9 I Sen Magnitude D2 0.0000…2.0000 0.01 3

10 10 10 I Sen Angle D4 -180.00…+180.00 1 3

11 11 11 I1 Magnitude D1 0.000…65.534 0.1 3

12 12 12 I2 Magnitude D1 0.000…65.534 0.1 3

13 13 13 I0 Magnitude D1 0.000…65.534 0.1 3

14 14 14 IA RMS D1 0.000…65.534 0.1 3

15 15 15 IB RMS D1 0.000…65.534 0.1 3

16 16 16 IC RMS D1 0.000…65.534 0.1 3

17 17 17 VAB Magnitude D3 0.00…220.00 5 3

18 18 18 VAB Phase Angle D4 -180.00…+180.00 1 3

19 19 19 VBC Magnitude D3 0.00…220.00 5 3

20 20 20 VBC Phase Angle D4 -180.00…+180.00 1 3

21 21 21 VCA Magnitude D3 0.00…220.00 5 3

22 22 22 VCA Phase Angle D4 -180.00…+180.00 1 3

23 23 23 VAN Magnitude D3 0.00…220.00 5 3

24 24 24 VAN Phase Angle D4 -180.00…+180.00 1 3

25 25 25 VBN Magnitude D3 0.00…220.00 5 3


MiCOM P342, P343 Page 153/170


Time)

P341PointIndex

P342PointIndex

P343PointIndex


Deadband

DefaultChange


none)

26 26 26 VBN Phase Angle D4 -180.00…+180.00 1 3

27 27 27 VCN Magnitude D3 0.00…220.00 5 3

28 28 28 VCN Phase Angle D4 -180.00…+180.00 1 3

29 29 29 VN Measured Mag D3 0.00…220.00 5 3

30 30 30 VN Measured Ang D4 -180.00…+180.00 1 3

31 31 31 VN Derived Mag D3 0.00…220.00 5 3

32 32 32 VN Derived Ang D4 -180.00…+180.00 1 3

33 33 33 V1 Magnitude D3 0.00…220.00 5 3

34 34 34 V2 Magnitude D3 0.00…220.00 5 3

35 35 35 V0 Magnitude D3 0.00…220.00 5 3

36 36 36 VAN RMS D3 0.00…220.00 5 3

37 37 37 VBN RMS D3 0.00…220.00 5 3

38 38 38 VCN RMS D3 0.00…220.00 5 3

39 39 39 Frequency D5 5.00…70.00 0.5 3

Measurements 2

40 40 40 A Phase Watts D6 -3150.0…+3150.0 1 3

41 41 41 B Phase Watts D6 -3150.0…+3150.0 1 3

42 42 42 C Phase Watts D6 -3150.0…+3150.0 1 3

43 43 43 A Phase VArs D6 -3150.0…+3150.0 1 3

44 44 44 B Phase VArs D6 -3150.0…+3150.0 1 3

45 45 45 C Phase VArs D6 -3150.0…+3150.0 1 3

46 46 46 A Phase VA D6 -3150.0…+3150.0 1 3

47 47 47 B Phase VA D6 -3150.0…+3150.0 1 3

48 48 48 C Phase VA D6 -3150.0…+3150.0 1 3

49 49 49 3 Phase Watts D6 -3150.0…+3150.0 1 3

50 50 50 3 Phase VArs D6 -3150.0…+3150.0 1 3

51 51 51 3 Phase VA D6 -3150.0…+3150.0 1 3

52 52 52 3Ph Power Factor D8 0.000…1.000 0.1 3

53 53 53 APh Power Factor D8 0.000…1.000 0.1 3

54 54 54 BPh Power Factor D8 0.000…1.000 0.1 3

55 55 55 CPh Power Factor D8 0.000…1.000 0.1 3

56 56 56 3Ph W Fix Demand D6 -3150.0…+3150.0 1 3

57 57 57 3Ph VArs Fix Dem D6 -3150.0…+3150.0 1 3

58 58 58 IA Fixed Demand D1 0.000…65.534 0.1 3

59 59 59 IB Fixed Demand D1 0.000…65.534 0.1 3

60 60 60 IC Fixed Demand D1 0.000…65.534 0.1 3


Page 154/170 MiCOM P342, P343


Time)

P341PointIndex

P342PointIndex

P343PointIndex


Deadband

DefaultChange


none)

61 61 61 3 Ph W Roll Dem D6 -3150.0…+3150.0 1 3

62 62 62 3Ph VArs RollDem D6 -3150.0…+3150.0 1 3

63 63 63 IA Roll Demand D1 0.000…65.534 0.1 3

64 64 64 IB Roll Demand D1 0.000…65.534 0.1 3

65 65 65 IC Roll Demand D1 0.000…65.534 0.1 3

66 66 66 3Ph W Peak Dem D6 -3150.0…+3150.0 1 3

67 67 67 3Ph VAr Peak Dem D6 -3150.0…+3150.0 1 3

68 68 68 IA Peak Demand D1 0.000…65.534 0.1 3

69 69 69 IB Peak Demand D1 0.000…65.534 0.1 3

70 70 70 IC Peak Demand D1 0.000…65.534 0.1 3

Measurements 3

71 IA-2 Magnitude D1 0.000…65.534 0.1 3

72 IA-2 Phase Angle D4 -180.00…+180.00 1 3

73 IB-2 Magnitude D1 0.000…65.534 0.1 3

74 IB-2 Phase Angle D4 -180.00…+180.00 1 3

75 IC-2 Magnitude D1 0.000…65.534 0.1 3

76 IC-2 Phase Angle D4 -180.00…+180.00 1 3

77 IA Differential D1 0.000…65.534 0.1 3

78 IB Differential D1 0.000…65.534 0.1 3

79 IC Differential D1 0.000…65.534 0.1 3

80 IA Bias D1 0.000…65.534 0.1 3

81 IB Bias D1 0.000…65.534 0.1 3

82 IC Bias D1 0.000…65.534 0.1 3

71 83 IREF Diff D2 0.0000…2.0000 0.01 3

72 84 IREF Bias D2 0.0000…2.0000 0.01 3

85 VN 3rd Harmonic D3 0.00…220.00 5 3

73 86 NPS Thermal D7 0.00…327.67 10 3

74 87 RTD 1 D14 -40.0…300.0 1 3

75 88 RTD 2 D14 -40.0…300.0 1 3

76 89 RTD 3 D14 -40.0…300.0 1 3

77 90 RTD 4 D14 -40.0…300.0 1 3

78 91 RTD 5 D14 -40.0…300.0 1 3

79 92 RTD 6 D14 -40.0…300.0 1 3

80 93 RTD 7 D14 -40.0…300.0 1 3

81 94 RTD 8 D14 -40.0…300.0 1 3

82 95 RTD 9 D14 -40.0…300.0 1 3


MiCOM P342, P343 Page 155/170


Time)

P341PointIndex

P342PointIndex

P343PointIndex


Deadband

DefaultChange


none)

83 96 RTD 10 D14 -40.0…300.0 1 3

71 84 97 APh Sen Watts D6 -3150.0…+3150.0 1 3

72 85 98 APh Sen Vars D6 -3150.0…+3150.0 1 3

73 86 99 APh Power Angle D4 -180.00…+180.00 1 3

74 87 100 Thermal Overload D7 0.00…327.67 10 3

New in software version‘06’

75 88 101 I1 Phase Angle D4 -180.00…+180.00 1 3

76 89 102 I2 Phase Angle D4 -180.00…+180.00 1 3

77 90 103 I0 Phase Angle D4 -180.00…+180.00 1 3

78 91 104 V1 Phase Angle D4 -180.00…+180.00 1 3

79 92 105 V2 Phase Angle D4 -180.00…+180.00 1 3

80 93 106 V0 Phase Angle D4 -180.00…+180.00 1 3

New in software version‘07’

81 94 107 CLIO Input 1 D16 -9999.9…+9999.9 10 3

82 95 108 CLIO Input 2 D16 -9999.9…+9999.9 10 3

83 96 109 CLIO Input 3 D16 -9999.9…+9999.9 10 3

84 97 110 CLIO Input 4 D16 -9999.9…+9999.9 10 3


Page 156/170 MiCOM P342, P343

4.5 Data type codesU

nit

s

A A V

Deg

rees

Hz

W/V

Ar/

VA

%

[Non

e]

[Non

e]

Wh/

VArh

/VA

h

S S Min C s

[Use

r]

Sta

nd

ard

Nu

meri

c R

an

ge

0.00

0…65

.534

0.00

00…

2.00

00

0.00

…22

0.00

-180

.00…

+18

0.00

5.00

…70

.00

-315

0.0…

+31

50.0

0.00

…32

7.67

0.00

0…1.

000

1…4

0…231

-1

-7.0

40…

+7.

040

-0.0

220…

+0.

0220

0.00

…32

7.67

-40.

0…30

0.0

0.00

000…

0.32

767

-999

9.9…

+99

99.9

Ch

an

ge E

ven

tD

ea

db

an

d S

TEP

0.01

In

0.00

1 In

0.1

Vn /

110

0.1

0.1

0.1I

n x

Vn /

110

0.1

0.01 1

In x

Vn

/ 11

0

(0.0

1 In

)( 11

0 /

Vn)

(0.0

01 In

)( 11

0 /

Vn)

0.5

0.1

0.00

01

0.1

Ch

an

ge E

ven

tD

ea

db

an

d M

AX

64 In

2 In

220

Vn /

110

180

70

3200

In x

Vn

/ 11

0

320 1 4

3200

0 In

x V

n /

110

32 In

x (

110

/ Vn

)

2 In

x (

110

/ Vn

)

30 300

0.03

9999

Ch

an

ge E

ven

tD

ea

db

an

d M

IN

0.05

In

0.01

In

0.1

Vn /

110

0.1

0.1

0.1I

n .V

n /

110

0.1

0.01 1

In x

Vn

/ 11

0

(0.0

1 In

)( 11

0 /

Vn)

(0.0

01 In

)( 11

0 /

Vn)

1 0.1

0.00

01

0.1

Defa

ult

Ch

an

ge

Even

tD

ea

db

an

d

0.1

0.01 5 1 0.5 1 10 0.1 1 n/a

0.1

0.01 5 1

0.00

1

10

Sca

lin

g

x In

/ 5

00

x In

/ 1

0000

x Vn

/(1

10 x

100

)

x 0.

01

x 0.

01

x 0.

1In

x Vn

/ 1

10

x 0.

01

x 0.

001

x 1

x In

x V

n /

110

x ( I

n /

1000

)( 11

0 /

Vn)

x ( I

n /

1000

0)( 1

10 /

Vn)

x 0.

01

x 0.

1

x 0.

0000

1

x 0.

1

Na

me/

Desc

rip

tion

Stan

dard

Pha

se, R

MS,

& S

eque

nce

Cur

rent

Sens

itive

Cur

rent

Volta

ge

Ang

le

Freq

uenc

y

Pow

er

Perc

enta

ge

Pow

er F

acto

r

Setti

ng G

roup

Ener

gy

Adm

ittan

ce (S

tand

ard

Cur

rent

)

Adm

ittan

ce (S

ensi

tive

Cur

rent

)

Tim

e (M

inut

es)

Tem

pera

ture

(Cel

sius

)

Tim

e (S

econ

ds)

CLI

O In

put V

alue

Da

taTy

pe

D1

D2

D3

D4

D5

D6

D7

D8

D9

D10

D11

D12

D13

D14

D15

D16

Not

es:

1.

In a

nd V

n ar

e th

e re

lay

inpu

t rat

ings

: 1A

or

5A a

nd 1

10V

or 4

40V

resp

ectiv

ely.

2.

The

scal

ing

valu

e re

pres

ents

the

mul

tiplie

r re

quire

d fo

r th

e m

aste

r st

atio

n to

sca

le th

e va

lue

obta

ined

from

the

rela

y to

the

rela

y’s

seco

ndar

y (i.

e. in

put)

term

s. A

dditi

onal

sca

ling

will

be

requ

ired

by th

e m

aste

r st

atio

n to

obt

ain

prim

ary

quan

titie

s.

3.

Type

D6

can

repr

esen

t Wat

ts, V

Ars

or

VA, t

he e

xact

uni

t app

lied

depe

nds

on th

e de

scrip

tion

of th

e ite

m.

4.

The

defa

ult c

hang

e ev

ent d

eadb

and

is u

sed

unle

ss s

peci

fied

othe

rwis

e in

the

poin

t lis

t.

5.

All

quan

titie

s ar

e pr

esen

ted

to th

e re

lay’

s in

tern

al D

NP3

inte

rfac

e as

sig

ned

32-b

it va

lues

. U

se o

f the

16-

bit v

aria

tions

will

req

uire

an

asse

ssm

ent o

n a

poin

t by

poin

t bas

is a

s to

whe

ther

the

valu

e sh

ould

be

trea

ted

as s

igne

d or

uns

igne

d. T

he s

peci

fied

num

eric

ran

ge fo

r ea

ch p

oint

can

be

used

as

a go

od g

uide

to m

akin

g th

is d

ecis

ion.

6.

The

“D16

” un

its a

re d

efin

ed b

y th

e us

er, d

epen

ding

on

the

type

of C

LIO

tran

sduc

er c

onne

cted

.


MiCOM P342, P343 Page 157/170

MiCOM P342 PROGRAMMABLE SCHEME LOGIC (07)

Opto Input and Fault Record Trigger Mappings

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P34x/EN GC/F33 Relay Menu Databases

Page 158/170 MiCOM P342, P343


Output Relay Mappings

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MiCOM P342, P343 Page 159/170



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Page 160/170 MiCOM P342, P343



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MiCOM P342, P343 Page 161/170



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MiCOM P342, P343 Page 163/170


LED Mappings

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Page 164/170 MiCOM P342, P343


Opto Input and Fault Record Trigger Mappings

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MiCOM P342, P343 Page 165/170



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Page 166/170 MiCOM P342, P343



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MiCOM P342, P343 Page 167/170



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Page 168/170 MiCOM P342, P343



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MiCOM P342, P343 Page 169/170



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Page 170/170 MiCOM P342, P343


LED Mappings

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External Connection P34x/EN CO/F33DiagramsMiCOM P342, P343

EXTERNAL CONNECTIONDIAGRAMS

P34x/EN CO/F33 External ConnectionDiagrams

MiCOM P342, P343

External Connection P34x/EN CO/F33DiagramsMiCOM P342, P343 Page 1/36

Figure 1: Comms Options MiCOM Px40 Platform



Figure 2: Generator Protection Relay (40TE) for Small Generator Using VEE ConnectedVT's (8 I/P & 7 O/P)


Figure 3: Generator Protection Relay (40TE) for Small Generator with Sensitive Power(8 I/P & 7 O/P)



Figure 4: Generator Protection Relay (40TE) for Small Generator (8 I/P & 7 O/P & RTD’s)


Figure 5: Generator Protection Relay (40TE) for Small Generator (8 I/P & 7 O/P & RTD’s)



Figure 6: Generator Protection Relay (40TE) for Small Generator (8 I/P & 7 O/P & CLIO)


Figure 7: Generator Protection Relay (40TE) for Small Generator (8 I/P & 15 O/P)








Figure 10: Generator Protection Relay (60TE) for Small Generator (16 I/P & 16 O/P &RTD’s & CLIO)


Figure 11: Generator Protection Relay (60TE) for Small Generator (16 I/P & 16 O/P &RTD’s & CLIO)



Figure 12: Generator Protection Relay (60TE) for Small Generator (24 I/P & 16 O/P &RTD’s)


Figure 13: Generator Protection Relay (60TE) for Small Generator (16 I/P & 24 O/P &RTD’s)



Figure 14: Generator Protection Relay (60TE) with Biased Differential (16 I/P & 14 O/P &RTD’s)


Figure 15: Generator Protection Relay (60TE) (16 I/P & 14 O/P & RTD’s)



Figure 16: Generator Protection Relay (60TE) with High Impedance Differential (16 I/P &14 O/P)


Figure 17: Generator Protection Relay (60TE) with High Impedance Differential (16 I/P &14 O/P)



Figure 18: Generator Protection Relay with Biased Differential Using VEE Connected VT’sand Sensitive Power (16 I/P & 14 O/P)


Figure 19: Generator Protection Relay (60TE) with Biased Differential (16 I/P & 14 O/P &CLIO)



Figure 20: Generator Protection Relay (60TE) with Biased Differential (24 I/P & 14 O/P)


Figure 21: Generator Protection Relay (60TE) with Biased Differential (16 I/P & 22 O/P)



Figure 22: Generator Protection Relay (80TE) with Biased Differential (24 I/P & 24 O/P & RTD’s & CLIO)


Figure 23: Generator Protection Relay (80TE) with Biased Differential (24 I/P & 24 O/P & RTD’s & CLIO)








Figure 26: Generator Protection Relay (80TE) with Biased Differential (32 I/P & 16 O/P &RTD & CLIO)


Figure 27: Generator Protection Relay (80TE) with Biased Differential (16 I/P & 32 O/P &RTD & CLIO)



Figure 28: Assembly P341/2 Generator Protection Relay (40TE) (8 I/P & 7 O/P withOptional I/P & O/P)


Figure 29: Assembly P342 Generator Protection Relay (40TE) (8 I/P & 7 O/P with OptionalRTD & CLIO)



Figure 30: Assembly P342 Generator Protection Relay (60TE) (16 I/P & 16 O/P withOptional I/P & O/P)


Figure 31: Assembly P342 Generator Protection Relay (60TE) (16 I/P & 16 O/P withOptional RTD & CLIO)













Figure 36: Assembly P343 Generator Protection Relay (80TE) (32 I/P & 16 O/P & RTD &CLIO or 16 I/P & 32 O/P & RTD & CLIO)

Hardware/Software Version P34x/EN VC/E33History and CompatibilityMiCOM P342, P343

HARDWARE / SOFTWARE VERSIONHISTORY AND COMPATIBILITY

(Note: Includes versions released and supplied to customers only)

P34x/EN VC/E33 Hardware/Software VersionHistory and Compatibility

MiCOM P342, P343

Hardware/Software Version P34x/EN VC/E33History and CompatibilityMiCOM P342, P343 Page 1/16

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Page 2/16 MiCOM P342, P343R

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it is

the

sam

e as

V<

1

Impr

ovem

ent t

o th

e RT

D s

tart

-up

calib

ratio

n ro

utin

e

Min

or b

ug fi

xes

05

Con

t.

(1) F

A/B

Oct

200

2

IEC

6087

0-5-

103

build

with

spe

cial

priv

ate

code

map

ping

for

ALS

TOM

Pow

er p

roje

ct in

Icel

and.

Inc

lude

spr

ivat

e co

des

and

unco

mpr

esse

d di

stur

banc

e re

cord

er

Cor

rect

ion

to IE

C60

870-

5-10

3 vo

ltage

mea

sure

men

tsfo

r Vn

=38

0/48

0V r

elay

s

Cor

rect

ion

to fo

reig

n la

ngua

ge te

xt fo

r Sy

stem

Bac

kup

prot

ectio

n no

t inc

lude

d in

pre

viou

s 05

sof

twar

e bu

ilds

Cha

nge

to n

eutr

al v

olta

ge d

ispl

acem

ent p

rote

ctio

n an

ddi

rect

iona

l SEF

pro

tect

ion

so th

at th

ey a

re n

ot b

lock

ed b

yth

e VT

sup

ervi

sion

logi

c w

hen

whe

n th

e VN

Inpu

t and

ISEF

>VN

Pol a

re s

elec

ted

as M

easu

red

Impr

ovem

ent t

o th

e RT

D s

tart

-up

calib

ratio

n ro

utin

e

Min

or b

ug fi

xes

IEC

6087

0-5-

103

build

onl

y

V2.0

5 or

Lat

erP3

4x/E

N T

/C11



ela

y ty

pe:

P342

/3 …

Soft

wa

reV

ers

ion

Maj

orM

inor

Ha

rdw

are

Suff

ixO

rig

ina

lD

ate

of

Issu

eD

esc

rip

tion

of

Ch

an

ges

S1C

om

pa

tib

ilit

yTe

chn

ica

lD

ocu

men

tati

on

06

AA

/CA

ug 2

000

Not

rel

ease

d to

pro

duct

ion

Add

ition

al ID

MT

char

acte

ristic

s fo

r ov

ercu

rren

t and

volta

ge d

epen

dent

ove

rcur

rent

pro

tect

ion

(rec

tifie

r an

d RI

curv

e), e

arth

faul

t pro

tect

ion

(RI a

nd ID

G c

urve

) and

sens

itive

ear

th fa

ult p

rote

ctio

n (ID

G c

urve

)

Cha

nge

to ti

me

dial

set

ting

rang

e of

IEEE

and

US

curv

es.

Prev

ious

ly c

urve

s w

ere

base

d on

TD

/7 w

here

TD

= 0

.5-

15.

Now

, cur

ves

are

base

d on

TD

whe

re T

D =

0.0

1-10

0. A

lso,

incl

udes

cha

nge

to U

S ST

Inve

rse

(C02

)cu

rve.

K c

onst

ant a

nd L

con

stan

t mul

tiple

d x

7 be

caus

eof

cha

nge

to T

D, n

ow K

=0.

1675

8 an

d L=

0.11

858

Ang

le m

easu

rem

ents

for

sequ

ence

qua

ntiti

es in

Mea

sure

men

ts 1

men

u ad

ded

Inte

rtur

n pr

otec

tion

adde

d

Opt

iona

l 2nd

rea

r co

mm

unic

atio

n po

rt a

dded

New

pow

er s

uppl

y w

ith in

crea

sed

outp

ut r

atin

g an

dre

duce

d dc

inru

sh c

urre

nt (t

ypic

ally

< 1

0A).

(Mod

elnu

mbe

r ha

rdw

are

chan

ged

to s

uffix

C)

Wid

er s

ettin

g ra

nge

for

Pow

er a

nd S

ensi

tive

Pow

erpr

otec

tion.

P>

1/2

(rev

erse

pow

er) a

nd P

<1/

2 (lo

wfo

rwar

d po

wer

) max

imum

set

ting

chan

ged

from

40I

n to

300I

n W

(Vn=

100/

120V

) and

from

160

In W

to 1

200I

nW

(Vn=

380/

480V

). S

en –

P>1/

2 an

d Se

n P<

1/2

max

imum

set

ting

chan

ged

from

15I

n to

100

In W

(Vn=

100/

120V

) and

from

60I

n to

400

In W

(Vn=

380/

480V

). T

here

is a

lso

an a

dditi

onal

set

ting

for

the

Pow

er a

nd S

ensi

tive

Pow

er p

rote

ctio

n to

sel

ect t

heO

pera

ting

mod

e as

Gen

erat

ing

or M

otor

ing

V2.0

6 or

Lat

erP3

4x/E

N T

/D22


Rela

y ty

pe:

P342

/3 …

Soft

wa

reV

ers

ion

Maj

orM

inor

Ha

rdw

are

Suff

ixO

rig

ina

lD

ate

of

Issu

eD

esc

rip

tion

of

Ch

an

ges

S1C

om

pa

tib

ilit

yTe

chn

ica

lD

ocu

men

tati

on

AA

/CA

ug 2

000

Wid

er s

ettin

g ra

nge

for

the

volta

ge d

epen

dent

over

curr

ent p

rote

ctio

n. V

olt D

ep O

C V

<1

and

V<2

min

imum

set

ting

chan

ged

from

20

to 5

V(V

n=10

0/12

0V) a

nd fr

om 8

0 to

20V

(Vn=

380/

480V

). V

Dep

OC

k S

et m

inim

um s

ettin

g ch

ange

d fr

om 0

.25

to0.

1

Max

imum

ove

rfre

quen

cy p

rote

ctio

n se

tting

incr

ease

dfr

om 6

5 to

68

Hz

Cha

nge

to u

nder

volta

ge s

tage

2 (V

<2)

set

ting

rang

e to

corr

ect a

n er

ror.

The

set

ting

rang

e ha

s be

en in

crea

sed

from

10-

70 V

to 1

0-12

0V (V

n=10

0/12

0V) s

o th

at it

isth

e sa

me

as V

<1

Cha

nge

to n

eutr

al v

olta

ge d

ispl

acem

ent p

rote

ctio

n an

ddi

rect

iona

l SEF

pro

tect

ion

so th

at th

ey a

re n

ow n

otbl

ocke

d by

the

volta

ge tr

ansf

orm

er s

uper

visi

on lo

gic

whe

n th

e VN

Inpu

t and

ISEF

> V

N P

ol a

re s

elec

ted

asM

easu

red

Incl

udes

all

the

impr

ovem

ents

and

cor

rect

ions

in 0

5Fso

ftwar

e ex

cept

for

2 en

hanc

emen

ts s

how

n fo

r 06

B

Min

or b

ug fi

xes

V2.0

6 or

Lat

erP3

4x/E

N T

/D22

06

Con

t.

BA

/CO

ct 2

002

Cor

rect

ion

to u

nder

volta

ge s

tage

2 (V

<2)

set

ting

rang

e.Th

e se

tting

ran

ge h

as b

een

incr

ease

d fr

om 1

0-70

V to

10-1

20V

(Vn=

110/

120V

) so

that

it is

the

sam

e as

V<

1

Impr

ovem

ent t

o th

e RT

D s

tart

-up

calib

ratio

n ro

utin

e

Min

or b

ug fi

xes

V2.0

6 or

Lat

erP3

4x/E

N T

/D22



ela

y ty

pe:

P342

/3 …

Soft

wa

reV

ers

ion

Maj

orM

inor

Ha

rdw

are

Suff

ixO

rig

ina

lD

ate

of

Issu

eD

esc

rip

tion

of

Ch

an

ges

S1C

om

pa

tib

ilit

yTe

chn

ica

lD

ocu

men

tati

on

AA

/CA

pr 2

003

Not

rel

ease

d to

pro

duct

ion

Opt

iona

l add

ition

al 4

ana

logu

e in

puts

and

4 o

utpu

ts(c

urre

nt lo

op in

puts

and

out

puts

– C

LIO

)

Add

ition

al s

ettin

g to

sel

ect t

he c

urre

nt in

puts

(IA

-1, I

B-1,

IC-1

or

IA-2

, IB-

2, IC

-2) u

sed

for

the

brea

ker

fail

unde

rcur

rent

Two

new

har

dwar

e co

nfig

urat

ions

- (1

) 32

Inpu

ts, 1

6O

utpu

ts, R

TD, C

LIO

(2) 1

6 In

puts

, 32

Out

puts

, RTD

,C

LIO

Num

ber

of a

larm

s in

crea

sed

from

64

to 9

6 (N

ew A

larm

Stat

us 3

wor

d -

32 b

it)

Add

ition

al u

ser

alar

ms.

Pre

viou

sly

1 m

anua

l res

et a

nd 2

self

rese

t use

r al

arm

s, n

ow 1

2 m

anua

l res

et a

nd 4

sel

fre

set u

ser

alar

ms

Con

trol

Inpu

t sta

tes

adde

d to

non

vol

atile

mem

ory

Ger

man

lang

uage

text

upd

ated

Cou

rier

and

MO

DBU

S bu

ilds

only

Min

or b

ug fi

xes

V2.0

9 or

Lat

erP3

4x/E

N T

/E33

07

BA

/CO

ct 2

003

Pow

er m

easu

rem

ent l

imits

add

ed to

pre

vent

non

zer

ova

lues

with

no

curr

ent a

nd v

olta

ge.

Als

o po

wer

fact

orm

easu

rem

ents

lim

ited

to +

/-1

In th

e C

omm

issi

onin

g Te

st m

enu

the

DD

B st

atus

has

been

mad

e vi

sibl

e on

the

fron

t pan

el d

ispl

ay

Supp

ort f

or T

rip L

ED S

tatu

s an

d A

larm

Sta

tus

adde

d to

G26

dat

a ty

pe fo

r M

OD

BUS

regi

ster

300

01

V2.0

9 or

Lat

erP3

4x/E

N T

/E33


Rela

y ty

pe:

P342

/3 …

Soft

wa

reV

ers

ion

Maj

orM

inor

Ha

rdw

are

Suff

ixO

rig

ina

lD

ate

of

Issu

eD

esc

rip

tion

of

Ch

an

ges

S1C

om

pa

tib

ilit

yTe

chn

ica

lD

ocu

men

tati

on

07

Con

t.B

A/C

Oct

200

3

Cor

rect

ion

to th

e C

B tr

ip/C

lose

func

tiona

lity

via

MO

DBU

S so

that

loca

l/re

mot

e se

tting

in th

e C

B C

ontr

olm

enu

is n

ot ig

nore

d

Cor

rect

ion

to M

OD

BUS

auto

eve

nt e

xtra

ctio

n w

hich

doe

sno

t wor

k co

rrec

tly in

ver

sion

s 05

and

06

softw

are

Exte

nsio

n of

the

cont

rol i

nput

func

tiona

lity

to s

uppo

rtpu

lse

and

latc

h op

erat

ions

in D

NP

3.0

DN

P 3.

0 ob

ject

10

adde

d to

cla

ss 0

pol

l

Cor

rect

ion

to D

NP

3.0

time

sync

ope

ratio

n so

that

it d

oes

not m

odify

the

seas

on b

it in

the

time

stam

p

Impr

ovem

ent t

o th

e di

ffere

ntia

l pro

tect

ion

perf

orm

ance

at lo

w fr

eque

ncie

s

Cor

rect

ion

to th

e m

anua

l res

et u

ser

alar

ms

so th

at th

eev

ent r

ecor

d sh

ows

the

alar

m tu

rnin

g of

f onl

y w

hen

are

set c

omm

and

has

been

issu

ed.

Prev

ious

ly th

e "a

larm

off"

even

t is

prod

uced

onc

e th

e in

itiat

ing

sign

al is

rem

oved

Cor

rect

ion

to th

e fa

ult r

ecor

der

win

dow

for

curr

ent b

ased

trip

s so

that

it c

an te

rmin

ate

prop

erly

onc

e th

eFA

ULT

_REC

_TRI

G s

igna

l (D

DB

288)

is r

eset

. Pr

evio

usly

itne

eded

to w

ait f

or R

elay

3 to

res

et a

lso

befo

rete

rmin

atio

n

DD

B 64

9 fo

r po

le s

lip r

eact

ance

line

sta

rt r

emov

ed fr

omth

e ev

ent l

ist

Min

or b

ug fi

xes

V2.0

9 or

Lat

erP3

4x/E

N T

/E33


Page 12/16 MiCOM P342, P343Re

lay

Softw

are

Vers

ion

0102

0304

0506

07

01

02

03

04

05

06

07

Setting File Software Version


Rela

y So

ftwar

e Ve

rsio

n

0102

0304

0506

07

01

02

03

04

05

06

07

PSL File Software Version


Page 14/16 MiCOM P342, P343Re

lay

Softw

are

Vers

ion

0102

0304

05A

-E05

F06

07

01

02

03

04

05A

-E

05F

06

07

Menu Text File Software Version

M

enu

text

rem

ains

com

patib

le w

ithin

eac

h so

ftwar

e ve

rsio

n (e

xcep

t 05)

but

is N

OT

com

patib

le a

cros

s di

ffere

nt v

ersi

ons.

Hardware/Software Version P34x /EN VC/E33History and CompatibilityMiCOM P342, P343 Page 15/16

Information Required with Order

MiCOM P342 GENERATOR PROTECTION RELAY NOMENCLATURE

A N N N A X X X A X X N N X A

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Character Type (A=Alpha, N=Numeric,X=Alpha-numeric)

Character Numbering (Maximum = 15)P 3 4 2 * * * * * * 0 * * 0 *

Vx Aux Rating24-48 Vdc48-110 Vdc, 30-100 Vac110-250 Vdc, 100-240 Vac

123

In/Vn RatingIn=1A/5A, Vn=100/120VIn=1A/5A, Vn=380/480V

12

Hardware OptionsNothingIRIG-B onlyFibre Optic Converter OnlyIRIG-B & Fibre Optic ConverterRear Comms Board*Rear Comms + IRIG-B*

123478

Product SpecificSize 40TE Case, No Option (8 Optos + 7 Relays)Size 40TE Case, 8 Optos + 7 Relays + RTDSize 40TE Case, 8 Optos + 7 Relays + CLIO*Size 40TE Case, 16 Optos + 7 Relays*Size 40TE Case, 8 Optos + 15 Relays*Size 40TE Case, 12 Optos + 11 Relays*Size 60TE Case, 16 Optos + 16 Relays*Size 60TE Case, 16 Optos + 16 Relays + RTD*Size 60TE Case, 16 Optos + 16 Relays + CLIO*Size 60TE Case, 24 Optos + 16 Relays*Size 60TE Case, 16 Optos + 24 Relays*Size 60TE Case, 16 Optos + 16 Relays + RTD + CLIO*Size 60TE Case, 24 Optos + 16 Relays + RTD*Size 60TE Case, 16 Optos + 24 Relays + RTD*

ABCDEFGHJKLMNP

Protocol OptionsK-BusMODBUSIEC870DNP3.0

1234

Mounting Panel Mounting A

Software XX

Setting FilesDefaultCustomer

01

Design SuffixOriginalPhase 2 Hardware

AC

Note Design Suffix

A = Original hardware (48V opto inputs only, lower contact rating, no I/O expansion available)C = Latest hardware (Universal Optos, New Relays, New Power Supply)

* Not available in design suffix A relays

Note MountingFor rack mounting assembled single rack frames and blanking plates are available



Information Required with Order

MiCOM P343 GENERATOR PROTECTION RELAY NOMENCLATURE

A N N N A X X X A X X N N X A

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Character Type (A=Alpha, N=Numeric,X=Alpha-numeric)

Character Numbering (Maximum = 15)P 3 4 3 * * * * * * 0 * * 0 *

Vx Aux Rating24-48 Vdc48-110 Vdc, 30-100 Vac110-250 Vdc, 100-240 Vac

123

In/Vn RatingIn=1A/5A, Vn=100/120VIn=1A/5A, Vn=380/480V

12

Hardware OptionsNothingIRIG-B onlyFibre Optic Converter OnlyIRIG-B & Fibre Optic ConverterRear Comms Board*Rear Comms + IRIG-B*

123478

Product SpecificSize 60TE Case, No Option (16 Optos + 14 Relays)Size 60TE Case, 16 Optos + 14 Relays + RTDSize 60TE Case, 16 Optos + 14 Relays + CLIO*Size 60TE Case, 24 Optos + 14 Relays*Size 60TE Case, 16 Optos + 22 Relays*Size 80TE Case, 24 Optos + 24 Relays*Size 80TE Case, 24 Optos + 24 Relays + RTD*Size 80TE Case, 24 Optos + 24 Relays + CLIO*Size 80TE Case, 32 Optos + 24 Relays*Size 80TE Case, 24 Optos + 32 Relays*Size 80TE Case, 24 Optos + 24 Relays + RTD + CLIO*Size 80TE Case, 32 Optos + 24 Relays + RTD*Size 80TE Case, 24 Optos + 32 Relays + RTD*

ABCDEFGHJKLMN

Size 80TE Case, 32 Optos + 16 Relays + RTD + CLIO*Size 80TE Case, 16 Optos + 32 Relays + RTD + CLIO*

PQ

Protocol OptionsK-BusMODBUSIEC870DNP3.0

1234

Mounting Panel MountingRack Mounting (Size 80TE case only)*

AB

Software XX

Setting FilesDefaultCustomer

01

Design SuffixOriginalPhase 2 Hardware

AC

Note Design Suffix

A = Original hardware (48V opto inputs only, lower contact rating, no I/O expansion available)C = Latest hardware (Universal Optos, New Relays, New Power Supply)

* Not available in design suffix A relays

Note MountingFor rack mounting in the 60TE case size assembled single rack frames and blanking plates are available

TRANSMISSION & DISTRIBUTION Energy Automation & Information [email protected] www.areva.com

Documents

P34x_EN_T_F33