micom p341

Technical GuideMiCOM P341

Interconnection Protection Relay

Volume 1

Issue Control P341/EN T/C22

MiCOM P341

Manual Issue D Amendments completed 09.12.2004

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Ref.Section Page Description

- - -

Front CoverSoftware version details removed from back of front cover

- - -

ContentsReference to P14x brochure, removed from ApplicationNotes heading

-Throughout

Handling of electronic equipmentCompany name changed

IT Throughout

IntroductionCompany name changed

IT 1. 3

Introduction to MiCOMLast line of section : website address changed

4

Introduction to MiCOM guidesReference to P14x brochure, removed from ApplicationNotes summary

IT 2. 5Reference to P14x brochure, removed from Installationsummary

- 2. -

Safety Section : Installing, commissioning andservicingBefore energising the equipment, the following should bechecked: 2 new points added at the end of the list

- 6. -

Safety Section : Technical specificationsInsulation category : in 1st sentence installation amendedto insulationProduct safety : law voltage directive amended to lowvoltage directive

IT Throughout

Section brought into line with corporate standard.All references to chapters have been replaced with newsubdocument referencesCompany name amended

AP Throughout

Application NotesCompany name changed

AP ThroughoutAll references to chapters replaced with new subdocumentreferences

AP - -

PublicationLatest version (P341/EN BR Cd)

AP 1.2.1 10

Protection features11th bullet point added

AP 1.2.2 10

Non-protection features4th bullet point : 2nd sentence amended

AP 2.1 12

Configuration columnIn the menu text column between Power and Overcurrent :Thermal overload has been added

P341/EN T/C22 Issue Control

MiCOM P341


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AP 2.2 13

CT and VT ratiosData in table amended

AP 2.4 16

Rate of change of frequency protectionDDB information in sentences 1 and 2 : amended

17

Voltage vector shift protection3rd equation : amended

AP 2.5

18

18

Figure 2c : title amendedParagraph 3 : DDB information in 1st sentence amended

AP 2.6 20

Reconnection timerParagraph 3 : DDB information in 1st sentence amended

20

Power protectionParagraph 4 : DDB information in 1st sentence amended

AP 2.7 21 Data in table amended

21

Sensitive power protection function1st sentence amendedParagraph 2 : %Pn changed from 2 to 7

22Paragraph before table : DDB information in 1st sentenceamended

AP 2.7.1 22 - 23 Data in table amended

AP 2.7.4 25

Reverse power protection functionTable number changed from 2 to 11st paragraph after Table 1 : sentences 3 and 4 amended

26

Overcurrent protectionParagraph 6 : DDB information in sentences 1 and 3amended

AP 2.8 28 After table : paragraphs 2 and 3 added

34

Standard earth fault protection elementParagraph 3 : DDB information in sentences 1 and 3amended

AP 2.10.1 35 Data in table amended

36

Sensitive earth fault protection element (SEF)Paragraph 2 : DDB information in sentences 1 and 3amended

AP 2.10.2 37 Data in table amended

AP 2.11.2 39

Negative sequence polarisationParagraph 3 : added

AP 2.11.3 40

General setting guidelines for DEFParagraph 2 : amendedLast 2 angle settings added

AP 2.12 49

Operation of sensitive earth fault elementΙtem 3 of list : addedParagraph 2 : 1st sentence amended


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AP 2.13.1 51

Calculation of required relay settingsParagraph 3 : last sentence amended

AP 2.14 52

Restricted earth fault protectionParagraph 5 : DDB information in 1st sentence amended

AP 2.14.1 53

High impedance restricted earth fault protectionFigure 13 : where k = 0.5 changed to where k = 1

AP 2.14.2

55

57

Setting guidelines for high impedance REF1st equation on page amendedSections last list changed from numbers 4 and 5 tonumbers 1 and 2

AP 2.15 60

Residual over voltage/neutral voltagedisplacement protectionDDB information in paragraph before table amendedData in table amended

61

Under voltage protectionParagraph 4 : DDB information amendedNote added after 4th paragraph

AP 2.16 62 Data in table amended

63

Over voltage protectionParagraph 4 : DDB information amended

AP 2.17

64

64

Note added after 4th paragraphData in table amended

AP 2.18 66

Under frequency protectionDDB information in 1st two sentences of paragraph beforetable amended

AP 2.19 68

Over frequency protection functionDDB information in 1st two sentences of paragraph beforetable amended

AP 2.20 69 - 73

Thermal overload protectionNew section added

AP 2.21.2 75

Reset mechanisms for breaker fail timersData in 2nd table amendedParagraph after 2nd table : 1st sentence amended and 3rd

sentence added

AP 2.22.1 76

Breaker fail timer settingsData in table amendedParagraph 2 : 1st sentence amended

AP 2.22.2 77

Breaker fail undercurrent settingsFigure 17 : CB fail logic diagram added

AP 4.1 79

Voltage transformer supervision (VTS)Minor amendment in last paragraph


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AP 4.1.1 79

Loss of all three phase voltages under loadconditionsMinor amendments in paragraph 2

AP 4.1.2 80 - 81

Absence of three phase voltages upon lineenergisationSentence and bullet points added after figure 19

AP 4.1.2.1 81

InputsNew section added

AP 4.1.2.2 82

OutputsNew section added

AP 4.1.3 82

Menu settingsBullet points after table amended1st two paragraphs after bullet points added

AP 4.2.1 83

The CT supervision featureParagraph 1 : amendedParagraph 2 : addedParagraph 3 : sentence 1 amended and sentence 3 addedParagraph 4 : amendedFigure 20 : amended

AP 4.3.1

8485

86

Circuit breaker state monitoring features1st sentence added to paragraph after 2nd group of bulletpointsLast sentence added to paragraph before tableFigure 21 : added

AP 4.4 86

Circuit breaker controlSection deleted

AP 4.5 86 - 87

Pole dead logicNew section added

AP 4.6 87 - 90

Circuit breaker condition monitoringNew section added

AP 4.8 92 - 96

Trip circuit supervision (TCS)New section added

AP 4.9.1.3 98

Relay alarm conditionsTable : replaced

AP 4.9.1.6 99

Fault recordsParagraph 4 : added

AP 4.9.4 101

Event filteringMinor amendments made to 2nd paragraph after table

AP 4.10 102

Disturbance recorderParagraph 1 : re-writtenParagraph 3 : last sentence added


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AP 4.13 106

Control inputsNew section added

AP 4.14 107

CT connectionsNew section added

AP 4.15 107 - 108

Auto reset of trip LED indicationNew section added

AP 5.5.4 109

Directional instantaneous SEF protection(residually connected)Only 1st equation remains, rest of section deleted

AP 5.6 110

High impedance restricted earth fault protection1st equation : amended

AP 5.7.2 111

Metering class current transformersTable : replaced

AP 5.9 112

Converting IEC185 current transformer standardprotection classification to an ANSI/IEEE standardvoltage ratingNew section added

AP 6. 112 - 115

Commissioning test menuNew section added

HW ThroughoutAll references to chapters replaced with new subdocumentreferences

HW 1.1.3 3

Power supply moduleRS485 reference changed to EIA(RS)485

HW 2.3.2 7

Input boardFigure 2 : amendedLast 2 paragraphs deleted

HW 2.3.3 7 - 8

Universal opto isolated logic inputsNew section added

HW 2.4.1

8

9

Power supply board (including EIA(RS)485communication interfaceHeading : amended2nd paragraph after table : all RS485 reference changed toEIA(RS)485

HW 2.4.2 9

Output relay boardSection re-written

HW 2.5 9

IRIG-B boardParagraph 2 : RS485 reference changed to EIA(RS)485

HW 3.4.3.1 13

PSL dataNew section added

HW 4.2 16

Continuous self-testing4th bullet point amended


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TD ThroughoutAll references to chapters replaced with new subdocumentreferences

TD 1.5 8

‘Universal’ logic inputs (P340 range)Section re-written

TD 1.6 8 - 9

Output relay contactsSection re-written

TD 2.3 10

Auxiliary supply2nd table : replaced

TD 2.4 10

Optically-isolated inputsParagraph 1 : deleted

TD 10.9 32

Reverse power/low forward power/over power(32R / 32L / 32O)Data in table amended

TD 10.14 35

Thermal overload (49)New section added

TD 10.2.2 22

Accuracy

DT operation setting amended to ±2% or 50ms whicheveris greater

TD 13.2.2 37

PerformanceData in table amended

TD 15.2.4 39

Undercurrent accuracyData in table amended

TD 19. 41

Local and remote communicationsNew section added

CT Throughout

SCADA CommunicationsCompany name changed

CT ThroughoutSection brought into line with corporate standard.All references to chapters replaced with new subdocumentreferences

GC - -

Relay menu databaseAmended to reflect latest relay software

CO - -

External connection diagramsNew diagrams

VC - -

Hardware/software version history andcompatibilityAmended to reflect latest relay software

Technical Guide P341/EN T/D22

MiCOM P341

INTERCONNECTION PROTECTION RELAY

MiCOM P341

CONTENT

Issue Control

Handling of Electronic Equipment

Safety Instructions

Introduction P341/EN IT/D22

Application Notes P341/EN AP/D22

Relay Description P341/EN HW/D22

Technical Data P341/EN TD/D22

SCADA Communications P341/EN CT/D22

Relay Menu Database P341/EN GC/D22

External Connection Diagrams P341/EN CO/D22

Hardware / Software Version History andCompatibility P341/EN VC/C22

P341/EN T/D22 Technical Guide

MiCOM P341

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 products are immune to the relevant levels ofelectrostatic discharge when housed in their cases. Do not expose them to the risk ofdamage by withdrawing 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 4

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)

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 of equipment, unless otherwise stated in the technical datasection of the product documentation.

Insulation class: IEC 601010-1 : 1990/A2 : 1995Class IEN 61010-1 : 1993/A2 : 1995Class I

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

InsulationCategory(Overvoltage):

IEC 601010-1 : 1990/A2 : 1995Category IIIEN 61010-1 : 1993/A2 : 1995Category III

Distribution level, fixedinstallation. 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 : 1993/A2 : 1995Pollution degree 2

Compliance is demonstratedby reference to generic safetystandards.

Product Safety: 72/23/EEC

EN 61010-1 : 1993/A2 : 1995EN 60950 : 1992/A11 : 1997

Compliance with the EuropeanCommission Law VoltageDirective.

Compliance is demonstratedby reference to generic safetystandards.


MiCOM P341

INTRODUCTION

P341/EN IT/D22 Introduction

MiCOM P341


MiCOM P341 Page 1/24

CONTENT

1. INTRODUCTION TO MiCOM 1

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 10

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 22

3.8.4 DNP 3.0 communication 23


Page 2/24 MiCOM P341

Figure 1: Relay front view 6

Figure 2: Relay rear view 8

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



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

http://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

P341/EN IT Introduction

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

P341/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.

P341/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.

P341/EN TD Technical Data

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

P341/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.



P341/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.

P341/EN CO External Connection Diagrams

All external wiring connections to the relay.

P341/EN VC Hardware / Software Version History and Compatibility

Volume 2 Operation Guide


Safety Section

P341/EN IT Introduction

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

P341/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.

P341/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.

P341/EN PR Problem Analysis

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

P341/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.

P341/EN CO External Connection Diagrams

All external wiring connections to the relay.

P341/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 Appendix B for complete connection details.

3.2 Introduction to the user interfaces and settings options

The relay has three user interfaces:

the front panel user interface via the LCD and keypad.

the front port which supports Courier communication.

the rear port which supports one protocol of either Courier, Modbus,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 of allsettings • • •

Digital I/O signal status • • • • •

Display/extraction ofmeasurements • • • • •

Display/extraction of faultrecords • • •

Extraction of disturbancerecords • • • •

Programmable scheme logicsettings •

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 Appendix A of the manual.



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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 0No password required

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

Level 1Password 1 or 2

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.

Password 2 requiredAll other settings

Level 2As level 1 plus:

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 the



passwords 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 level1, preventing write access to the relaysettings without the correct password. The default menu access level is set in the‘Password control’ cell which is found in the ‘System data’ column of the menu (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 valuechanges 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 theand keys. When the desired newvalue has been reached it is confirmed as the new setting value by pressingAlternatively, 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 settingsEnter 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 Appendix B for details of the connectionterminals. The rear port provides K-Bus/EIA(RS)485 serial data communication and isintended for use with a permanently-wired connection to a remote control centre. Ofthe 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 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. Four settings apply to therear 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 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.

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 the Modbusmaster 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 directconnection 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 period30.00 s

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

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

Physical 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’.

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

Function type226

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

http://www.dnp.org/



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.


MiCOM P341

APPLICATION NOTES

P341/EN AP/D22 Application Notes

MiCOM P341



CONTENT

1. INTRODUCTION 8

1.1 Interconnection protection 9

1.2 MiCOM interconnection protection relay 9

1.2.1 Protection features 10

1.2.2 Non-protection features 10

2. APPLICATION OF INDIVIDUAL PROTECTION FUNCTIONS 11

2.1 Configuration column 11

2.2 CT and VT ratios 13

2.3 Loss of mains protection 13

2.4 Rate of change of frequency protection 15

2.4.1 Setting guidelines for df/dt protection 16

2.5 Voltage vector shift protection 17

2.5.1 Setting guidelines for voltage vector shift protection 19

2.6 Reconnection timer 19

2.6.1 Setting guidelines for the reconnect delay 20

2.7 Power protection 20

2.7.1 Sensitive power protection function 21

2.7.2 Over power protection 23

2.7.2.1 Over power setting guideline 23

2.7.3 Low forward power protection function 24

2.7.3.1 Low forward power setting guideline 24

2.7.4 Reverse power protection function 24

2.7.4.1 Reverse power setting guideline 25

2.8 Overcurrent protection 26

2.8.1 Transformer magnetising inrush 29

2.8.2 Application of timer hold facility 29

2.8.3 Setting guidelines 30

2.9 Directional overcurrent protection 30

2.9.1 Synchronous polarisation 32


2.10 Earth fault protection 34

2.10.1 Standard earth fault protection element 34



2.10.2 Sensitive earth fault protection element (SEF) 36

2.11 Directional earth fault protection (DEF) 38

2.11.1 Residual voltage polarisation 38

2.11.2 Negative sequence polarisation 39

2.11.3 General setting guidelines for DEF 39

2.11.4 Application to insulated systems 40

2.11.5 Setting guidelines – insulated systems 43

2.11.6 Application to petersen coil earthed systems 43

2.12 Operation of sensitive earth fault element 48

2.13 Application considerations 50

2.13.1 Calculation of required relay settings 50

2.13.2 Application of settings to the relay 51

2.14 Restricted earth fault protection 51

2.14.1 High impedance restricted earth fault protection 52

2.14.2 Setting guidelines for high impedance REF 54

2.15 Residual over voltage/neutral voltage displacement protection 57

2.15.1 Setting guidelines for residual over voltage/neutral voltage displacementprotection 60

2.16 Under voltage protection 61

2.16.1 Setting guidelines for under voltage protection 62

2.17 Over voltage protection 63

2.17.1 Setting guidelines for over voltage protection 64

2.18 Under frequency protection 65

2.18.1 Setting guidelines for under frequency protection 66

2.19 Over frequency protection function 68

2.19.1 Setting guidelines for over frequency protection 68

2.20 Thermal overload protection 69

2.20.1 Introduction 69

2.20.2 Thermal replica 70


2.21 Circuit breaker fail protection (CBF) 73

2.21.1 Breaker failure protection configurations 73

2.21.2 Reset mechanisms for breaker fail timers 74

2.22 Typical settings 75

2.22.1 Breaker fail timer settings 75



2.22.2 Breaker fail undercurrent settings 76

3. OTHER PROTECTION CONSIDERATIONS 77

3.1 Blocked overcurrent protection 77

4. APPLICATION OF NON-PROTECTION FUNCTIONS 79

4.1 Voltage transformer supervision (VTS) 79

4.1.1 Loss of all three phase voltages under load conditions 79

4.1.2 Absence of three phase voltages upon line energisation 80

4.1.2.1 Inputs 81

4.1.2.2 Outputs 82

4.1.3 Menu settings 82

4.2 Current transformer supervision 83

4.2.1 The CT supervision feature 83

4.2.2 Setting the CT supervision element 84

4.3 Circuit breaker state monitoring 84

4.3.1 Circuit breaker state monitoring features 84

4.4 Pole dead logic 86

4.5 Circuit breaker condition monitoring 87

4.5.1 Circuit breaker condition monitoring features 88


4.5.2.1 Setting the ^ thresholds 89

4.5.2.2 Setting the number of operations thresholds 89

4.5.2.3 Setting the operating time thresholds 90

4.5.2.4 Setting the excessive fault frequency thresholds 90

4.6 Circuit breaker control 90

4.7 Trip circuit supervision (TCS) 92

4.7.1 TCS scheme 1 93

4.7.1.1 Scheme description 93

4.7.2 Scheme 1 PSL 95









4.8 Event & fault records 97

4.8.1 Types of event 98

4.8.1.1 Change of state of opto-isolated inputs 98

4.8.1.2 Change of state of one or more output relay contacts 99

4.8.1.3 Relay alarm conditions 99

4.8.1.4 Protection element starts and trips 100

4.8.1.5 General events 100

4.8.1.6 Fault records 100

4.8.1.7 Maintenance reports 100

4.8.1.8 Setting changes 101

4.8.2 Resetting of event/fault records 101

4.8.3 Viewing event records via MiCOM S1 support software 101

4.8.4 Event filtering 102

4.9 Disturbance recorder 103

4.10 Measurements 104

4.10.1 Measured voltages and currents 104

4.10.2 Sequence voltages and currents 104

4.10.3 Power and energy quantities 104

4.10.4 Rms. voltages and currents 105

4.10.5 Demand values 105

4.10.5.1 Fixed demand values 105

4.10.5.2 Rolling demand values 105

4.10.5.3 Peak demand values 106

4.10.6 Settings 106

4.10.6.1 Default display 106

4.10.6.2 Local values 106

4.10.6.3 Remote values 106

4.10.6.4 Measurement ref 106

4.10.6.5 Measurement mode 106

4.10.6.6 Fixed demand period 106

4.10.6.7 Rolling sub-period and number of sub-periods 107

4.11 Changing setting groups 107

4.12 Control inputs 107

4.13 VT connections 108

4.13.1 Open delta (vee connected) VT's 108



4.13.2 VT single point earthing 108

4.14 Auto reset of trip LED indication 108

5. CT/VT REQUIREMENTS 109

5.1 Non-directional definite time/IDMT overcurrent & earth fault protection 109

5.1.1 Time-delayed phase overcurrent elements 109

5.1.2 Time-delayed earth fault overcurrent elements 109

5.2 Non-directional instantaneous overcurrent & earth fault protection 109

5.2.1 CT requirements for instantaneous phase overcurrent elements 109

5.2.2 CT requirements for instantaneous earth fault overcurrent elements 109

5.3 Directional definite time/IDMT overcurrent & earth fault protection 109

5.3.1 Time-delayed phase overcurrent elements 109

5.3.2 Time-delayed earth fault overcurrent elements 110

5.4 Directional instantaneous overcurrent & earth fault protection 110

5.4.1 CT requirements for instantaneous phase overcurrent elements 110

5.4.2 CT requirements for instantaneous earth fault overcurrent elements 110

5.5 Non-directional/directional definite time/IDMT sensitive earth fault (SEF)protection 110

5.5.1 Non-directional time delayed SEF protection (residually connected) 110

5.5.2 Non-directional instantaneous SEF protection (residually connected) 110

5.5.3 Directional time delayed SEF protection (residually connected) 110

5.5.4 Directional instantaneous SEF protection (residually connected) 110

5.5.5 SEF protection - as fed from a core-balance CT 110

5.6 High impedance restricted earth fault protection 111

5.7 Reverse and low forward power protection functions 111

5.7.1 Protection class current transformers 111

5.7.2 Metering class current transformers 112

5.8 Converting an IEC185 current transformer standard protectionclassification to a kneepoint voltage 112

5.9 Converting IEC185 current transformer standard protectionclassification to an ANSI/IEEE standard voltage rating 113

6. COMMISSIONING TEST MENU 113

6.1 Opto I/P status 114

6.2 Relay O/P status 114

6.3 Test port status 115

6.4 LED status 115

6.5 Monitor bits 1 to 8 115



6.6 Test mode 115

6.7 Test pattern 116

6.8 Contact test 116

6.9 Test LEDs 116

6.10 Using a monitor/download port test box 116

Figure 1: Typical system with embedded generation 14

Figure 2a: Vector diagram representing steady state condition 17

Figure 2b: Single phase line diagram showing generator parameters 18

Figure 2c: Transient voltage vector change due to change in load current IL 18

Figure 3: Typical distribution system using parallel transformers 32

Figure 4: Positioning of core balance current transformers 38

Figure 5: Current distribution in an insulated system with C phase fault 41

Figure 6: Phasor diagrams for insulated system with C phase fault 42

Figure 7: Current distribution in Peterson Coil earthed system 44

Figure 8: Distribution of currents during a C phase to earth fault 45

Figure 9: Theoretical case – no resistance present in XL or Xc 46

Figure 10: Zero sequence network showing residual currents 47

Figure 11: Practical case: resistance present in XL and Xc 48

Figure 12: Resistive components of spill current 49

Figure 13: High impedance principle 53

Figure 14: High impedance REF relay/CT connections 54

Figure 15a: Residual voltage, solidly earthed systems 58

Figure 15b: Residual voltage, resistance earthed systems 59

Figure 16: Co-ordination of underfrequency protection function with system loadshedding 67

Figure 17: CB fail logic 77

Figure 18a: Simple busbar blocking scheme (single incomer) 78

Figure 18b: Simple busbar blocking scheme (single incomer) 78

Figure 19: VTS logic 80

Figure 20: CT supervision function block diagram 83

Figure 21: CB state monitoring 86



Figure 22: Pole dead logic 87

Figure 23: Remote control of circuit breaker 91

Figure 24: TCS scheme 1 93

Figure 25: PSL for TCS schemes 1 and 3 95


Figure 27: PSL for TCS scheme 2 96


Figure 29: Trip LED logic diagram 109



1. INTRODUCTION

1.1 Interconnection protection

Small-scale generators can be found in a wide range of situations. These may beused to provide emergency power in the event of loss of the main supply.Alternatively the generation of electrical power may be a by-product of a heat/steamgeneration process. Where such embedded generation capacity exists it can beeconomic to run the machines in parallel with the local Public Electricity Supplier’s(PES) network. This can reduce a sites overall power demand or peak load.Additionally, excess generation may be exported and sold to the local PES. If paralleloperation is possible great care must be taken to ensure that the embeddedgeneration does not cause any dangerous conditions to exist on the local PESnetwork.

PES networks have in general been designed for operation where the generation issupplied from central sources down into the network. Generated voltages andfrequency are closely monitored to ensure that values at the point of supply are withinstatutory limits. Tap changers and tap changer control schemes are optimised toensure that supply voltages remain within these limits. Embedded generation canaffect the normal flow of active and reactive power on the network leading tounusually high or low voltages being produced and may also lead to excessive faultcurrent that could exceed the rating of the installed distribution switchgear/cables.

It may also be possible for the embedded generators to become disconnected fromthe main source of supply but be able to supply local load on the PES network. Suchislanded operation must be avoided for several reasons

to ensure that unearthed operation of the PES network is avoided

to ensure that automatic reclosure of system circuit breakers will not result inconnecting unsynchronised supplies causing damage to the generators

to ensure that system operations staff cannot attempt unsynchronised manualclosure of an open circuit breaker.

to ensure that there is no chance of faults on the PES system being undetectabledue to the low fault supplying capability of the embedded generator

to ensure that the voltage and frequency supplied to PES customers remains withinstatutory limits

Before granting permission for the generation to be connected to their system the PESmust be satisfied that no danger will result. The type and extent of protectionrequired at the interconnection point between PES system and embedded generationwill need to be analysed.

1.2 MiCOM interconnection protection relay

MiCOM relays are a new range of products from AREVA T&D. Using the latestnumerical technology the platform 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 P341 Interconnection Protection Relay. The relay has been designed toprovide a wide range of protection functions required to prevent dangerousconditions that could be present when embedded generators provide power to local



power supply networks when the main connection with the Electricity Supply system islost.

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 relay’s remote serial communications options.

1.2.1 Protection features

The P341 relay contains a wide variety of protection functions, these are summarisedbelow:

Phase Fault Overcurrent Protection – four stage back-up protection.

Earth Fault Overcurrent Protection – four stage back-up protection.

Neutral Displacement Protection – provides protection against earth faults onimpedance earthed/un-earthed systems.

Under/Over Voltage Protection – two stage protection to prevent the supply ofunusual voltages to external supply network.

Under/Over Frequency Protection – six stage frequency protection to prevent thesupply of unusual frequencies to the external supply network.

Reverse Power – protection against prime mover failure of a generator.

Low Forward Power – provides an interlock for non urgent tripping.

Over Power – back-up overload protection, or protection against excessive exportpower to local network

Rate of Change of Frequency Protection – to detect the loss of connection to maingrid supply network.

Voltage Vector Shift Protection – to detect the loss of connection to main gridsupply network.

Thermal overload protection – two stage thermal overload protection.

Voltage Transformer Supervision – to prevent mal-operation of voltage dependentprotection elements upon loss of a VT input signal.

Programmable Scheme Logic – allowing user defined protection and control logicto suit particular customer applications.

1.2.2 Non-protection features

Below is a summary of the P341 relay non-protective features:

Measurements – various measurements of value for display on the relay oraccessed from the serial communications, e.g. currents, voltages etc.

Fault/Event/Disturbance Records – available from the serial communications oron the relay display (fault/event records only on relay display).

Four Setting Groups – independent setting groups to cater for alternative powersystem and protection arrangements or special applications.

Remote Serial Communications – to allow remote access to the relays. Thefollowing communications protocols are supported; Courier, MODBUS,IEC 60870-5-103 (VDEW) and DNP 3.0.



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

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 Settings Function

CONFIGURATION

Restore Defaults No Operation

No OperationAll Settings

Setting Group 1Setting Group 2Setting Group 3Setting Group 4

Restore defaultsettings to any or allgroups of settings

Setting Group Select via MenuSelect via MenuSelect via Optos

Change settinggroups by

Active Settings Group 1

Group 1Group 2Group 3Group 4

Select active settinggroup used for

protection settings

Save Changes No OperationNo Operation

SaveAbort

Saves all settingchanges from stored

settings buffermemory into stored

settings

Copy From Group 1 Group1, 2, 3 or 4

Selects a group ofsettings to copy to thegroup designated in

“Copy To” cell

Copy To No Operation Group1, 2, 3 or 4

Copies the group ofsettings selected in the“Copy From” cell tothe selected setting

group

Setting Group 1 Enabled Enabled or DisabledSelects if Group 1

settings are availableon the relay




Setting Group 2 Disabled Enabled or DisabledSelects if Group 2






Power Enabled Enabled or DisabledMakes settings visible

in the relay menu

Thermal Overload Enabled Enabled or DisabledMakes settings visible

in the relay menu

Overcurrent Enabled Enabled or DisabledMakes settings visible

in the relay menu

Earth Fault Enabled Enabled or DisabledMakes settings visible

in the relay menu

SEF/REF/SPower SEF/REFDisabled or SEF/REFor Sensitive Power

Makes settings visiblein the relay menu

Residual O/V NVD Enabled Enabled or DisabledMakes settings visible

in the relay menu

df/dt Disabled Enabled or DisabledMakes settings visible

in the relay menu

V Vector Shift Disabled Enabled or DisabledMakes settings visible

in the relay menu

Reconnect Delay Disabled Enabled or DisabledMakes settings visible

in the relay menu

Volt Protection Enabled Enabled or DisabledMakes settings visible

in the relay menu

Freq Protection Enabled Enabled or DisabledMakes settings visible

in the relay menu

CB Fail Disabled Enabled or DisabledMakes settings visible

in the relay menu

Supervision Disabled Enabled or DisabledMakes settings visible

in the relay menu

Input Labels Visible Invisible or VisibleMakes settings visible

in the relay menu

Output Labels Visible Invisible or VisibleMakes settings visible

in the relay menu

CT & VT Ratios Visible Invisible or VisibleMakes settings visible

in the relay menu

Event Recorder Invisible Invisible or VisibleMakes settings visible

in the relay menu

Disturb Recorder Invisible Invisible or VisibleMakes settings visible

in the relay menu

Measure’t Setup Invisible Invisible or VisibleMakes settings visible

in the relay menu




Comms Settings Visible Invisible or VisibleMakes settings visible

in the relay menu

Commission Tests Visible Invisible or VisibleMakes settings visible

in the relay menu

Setting Values PrimaryPrimary orSecondary

Selects if relayprotection settings aredisplayed in primary

or secondarycurrent/voltage values

2.2 CT and VT ratios

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

Setting RangeMenu Text Default Setting

Min. Max.Step Size

CT & VT RATIOS

Main VT Primary 110V 100V 1000000V 1V

Main VT Sec’y

110V(Vn=100/120V)

400V(Vn=380/480V)

80V(Vn=100/120V)

360V(Vn=380/480V)

140V(Vn=100/120V)

480V(Vn=380/480V)

1V(Vn=100/120V)

4V(Vn=380/480V)

NVD VT Primary 110 V 100 V 1000000 V 1 V

NVD VT Secondary

110V(Vn=100/120V)

400V(Vn=380/480V)

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 Loss of mains protection

If the capacity of an embedded generator exceeds the locally connected load it isconceivable that it could supply the local load in island mode. Fault clearance maydisconnect part of the public supply system from the main source of supply resultingin the embedded generation feeding the local loads, i.e. a ‘Loss of Mains’ or ‘Loss ofGrid’ condition. This is illustrated in Figure 1. A fault at F will result in the tripping ofCB1 disconnecting substations S1, S2 and S3 from the main source of supply. Alsonote that transformer T1 was supplying the earth connection for S1, S2 and S3, thisearth connection is lost when CB1 opens. Should the load at substations S1 and S2greatly exceed the rating of EG1, the generator will slow down quickly andunderfrequency and/or undervoltage relays could operate to disconnect EG1 fromthe system. The worst scenario is when the external load is smaller than the



generator rating, in this case the generator can continue to operate normallysupplying the external loads. The local system will now be operating unearthed andovercurrent protection may be inoperative at S1 and S2 due to the low fault supplyingcapacity of generator EG1. The embedded generator may also lose synchronismwith the main system supply leading to serious problems if CB1 has auto reclosingequipment.

An even more serious problem presents itself if manual operation of distributionswitchgear is considered. System Operation staff may operate circuit breakers byhand. In these circumstances it is essential that unsynchronised reclosure is preventedas this could have very serious consequences for the operator, particularly if theswitchgear is not designed, or rated, to be operated when switching onto a fault. Toprotect personnel, the embedded machine must be disconnected from the system assoon as the system connection is broken, this will ensure that manual unsynchronisedclosure is prevented.

Figure 1: Typical system with embedded generation

Where the embedded generator does not export power under normal conditions itmay be possible to use directional power or directional overcurrent protection relaysto detect the export of power under loss of mains conditions. If export of power intothe system is allowed it may not be possible to set directional relays using settingssensitive enough to detect the loss of the mains connection. In such circumstances aRate of Change of Frequency and/or Voltage Vector Shift protection can be applied.These detect the slight variation in generator speed that occurs when the main supplyconnection is disconnected and the generator experiences a step change in load.

The type of protection required to detect Loss of Mains conditions will depend on anumber of factors, e.g. the generator rating, size of local load, ability to exportpower, and configuration of supply network etc. Protection requirements should bediscussed and agreed with the local Public Electricity Supplier before permission toconnect the embedded generator in parallel with the system is granted.

A number of protection elements that may be sensitive to the Loss of Mains conditionsare offered in the P341 relay; Rate of Change of Frequency, Voltage Vector Shift,Over Power Protection, Directional Overcurrent Protection, Frequency Protection,Voltage Protection. Application of each of these elements is discussed in thefollowing sections.



2.4 Rate of change of frequency protection

When a machine is running in parallel with the main power supply the frequency andhence speed of the machine will be governed by the grid supply. When theconnection with the grid is lost, as described in section 2.3, the now islandedmachine is free to slow down or speed up as determined by the new load conditions,machine rating and governor response. Where there is a significant change in loadconditions between the synchronised and islanded condition the machine will speedup or slow down before the governor can respond.

The rate of change of speed, or frequency, following a power disturbance can beapproximated by

df/dt = P.f

2GH

where P = Change in power output between synchronised and islandedoperation

f = Rated frequency

G = Machine rating in MVA

H = Inertia constant

This simple expression assumes that the machine is running at rated frequency andthat the time intervals are short enough that AVR and governor dynamics can beignored. From this equation it is clear that the rate of change of frequency is directlyproportional to the change in power output between two conditions. Provided thereis a small change in load between the synchronised and islanded (loss of mains)condition the rate of change of frequency as the machine adjusts to the new loadconditions can be detectable. The change in speed of the machine is alsoproportional to the inertia constant and rating of the machine and so will beapplication dependent.

Care must be taken in applying this type of protection as the prime consideration isdetecting the loss of grid connection. Failure to detect this condition may result inunsynchronised re-connection via remote re-closing equipment. However if toosensitive a setting is chosen there is a risk of nuisance tripping due to frequencyfluctuations caused by normal heavy load switching or fault clearance. Guidance canbe given for setting a rate of change of frequency element but these settings must bethoroughly tested on site to prove their accuracy for a given machine and load.

A single stage, definite time delayed, rate of change of frequency element is providein the P341 relay. The element calculates the rate of change of frequency every 3cycles by calculating the frequency difference over the 3-cycle period as shown.

df/dt = fn - fn-3cycle

3cycle

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

The element also allows the user to set a frequency band within which the element isblocked. This provides additional stability for non loss of grid disturbances which donot affect the machine frequency significantly.



A DDB (Digital Data Bus) signal is available to indicate that the element has operated(DDB 440 df/dt Trip). A second DDB signal is available to indicate that the elementhas started (DDB 630 df/dt Start). These signals are used to operate the output relays(as programmed into the Programmable Scheme Logic (PSL)) and trigger thedisturbance recorder. The state of the DDB signals can also be programmed to beviewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in the relay.

The following table shows the relay menu for the rate of change of frequency or df/dtprotection element, including the available setting ranges and factory defaults:


Min. Max.Step Size

GROUP 1 df/dt

df/dt Status Enabled Enabled, Disabled

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

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

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

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

2.4.1 Setting guidelines for df/dt protection

The rate of change of frequency, or df/dt, protection can be selected by setting the“df/dt Status” cell to ‘Enabled’.

The rate of change of frequency setting threshold, “df/dt Setting”, should be set to thedesired level.

The time delay setting, “df/dt Time Delay”, can be used to provide a degree ofstability against normal load switching events which will cause a change in thefrequency before governor correction.

The frequency dead band can be set by setting the upper and lower frequencythresholds, “df/dt f High”, “df/dt f Low”, respectively.

The setting thresholds should be set such that the loss of mains condition can bedetected, this can be determined by system switching during initial commissioning.System simulation testing has shown that the following settings can provide stableoperation for external faults, and load switching events, whilst operating for a loss ofmains event which causes a 10% change in the machine output, for a typical 4MWmachine. These can be used as a guide but will by no means be acceptable in allapplications. Machine rating, governor response, local load and system load, will allaffect the dynamic response of a machine to a loss of mains event.

df/dt Setting – 0.2Hz/s

df/dt Time Delay – 0.5s

df/dt f High – 50.5Hz

df/dt f Low – 49.5Hz

Once installed, the settings should be periodically reviewed to ensure that they areadequate to detect a loss of grid connection event, but not too sensitive such thatunwanted tripping occurs during normal fault clearance, or load switching, that doesnot lead to the loss of mains condition. Safety of personnel is paramount and thisshould be kept in mind when optimising settings; non-synchronised manual



operation of circuit breakers must be prevented by disconnection of the embeddedmachine when the system becomes separated.

2.5 Voltage vector shift protection

An expression for a sinusoidal mains voltage waveform is generally given by thefollowing:

V = Vp sin (wt) or V = Vp sin (t)

where (t) = wt = 2ft

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

(t) = 2f dt,

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

and V = V sin 2 (fo + t Rf/2)t

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

(t) = Rf t2,

Therefore the phase of the voltage with respect to a fixed frequency reference whensubject to a constant rate of change of frequency changes in proportion to t2. This isa characteristic difference from a rate of change of frequency function, which in mostconditions can be assumed as changing linearly with time.

A rate of change of frequency of 10 Hz/s results in an angular voltage vector shift ofonly 0.72 degrees in the first cycle after the disturbance. This is too small to bedetected by vector shift relays. In fact a typical setting for a voltage vector shift relayis, normally between 6 and 13 degrees. Therefore a voltage vector shift relay is notsensitive to the change in voltage phase brought about by change of frequencyalone.

To understand the relation between the resulting voltage vector angle changefollowing a disturbance and the embedded generator characteristics a simplifiedsingle phase equivalent circuit of a synchronous generator or induction generator isshown in Figures 2a, 2b and 2c. The voltage VT is the symmetrical terminal voltageof the generator and the voltage E is the internal voltage lying behind the machineimpedance which is largely reactive (X). When a disturbance causes a change incurrent the terminal voltage will jump with respect to its steady state position. Theresultant voltage vector is dependent on the rate of change in current, and thesubtransient impedance of the machine, which is the impedance the generatorpresents to a sudden load change. In turn the current change depends on howstrong the source is (short circuit capacity) and the voltage regulation at the generatorterminal which is also affected by the reactive power load connected to the machine.

Figure 2a: Vector diagram representing steady state condition



Figure 2b: Single phase line diagram showing generator parameters

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

The voltage vector shift function is designed to respond within one to two full mainscycles when its threshold is exceeded. Discrimination between a loss of mainscondition and a circuit fault is therefore achievable only by selecting the anglethreshold to be above expected fault levels. This setting can be quantified bycalculating the angular change due to islanding. However this angular changedepends on system topology, power flows and very often also on the instant of thesystem faults. For example a bolted three phase short circuit which occurs close tothe relay may cause a problem in that it inherently produces a vector shift angle atthe instant of the fault which is bigger than any normal setting, independent of themains condition. This kind of fault would cause the relay to trip shortly after theinstant of its inception. Although this may seem to be a disadvantage of the vectorshift function, isolating the embedded generator at the instant of a bolted three phasefault is of advantage to the PES. This is because the mains short circuit capacity andconsequently the energy feeding the short circuit is limited by the instant operation ofthe relay. The fast operation of this vector shift function renders it to operate at theinstant of a disturbance rather than during a gradual change caused by a gradualchange of power flow. Operation can occur at the instant of inception of the fault, atfault clearance or following non-synchronised reclosure, which affords additionalprotection to the embedded generator.

The P341 has a single stage Voltage Vector Shift protection element. This elementmeasures the change in voltage angle over successive power system half-cycles. Theelement operates by measuring the time between zero crossings on the voltagewaveforms. A measurement is taken every half cycle for each phase voltage. Over apower system cycle this produces 6 results, a trip is issued if 5 of the 6 calculations forthe last power system cycle are above the set threshold. Checking all three phasesmakes the element less susceptible to incorrect operation due to harmonic distortionor interference in the measured voltage waveform.

A DDB (Digital Data Bus) signal is available to indicate that the element has operated(DDB 441 V Shift Trip). The state of the DDB signal 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 Voltage Vector Shift protectionelement, including the available setting ranges and factory defaults:


Min. Max.Step Size

GROUP 1 V Vector Shift

V Shift Status Enabled Enabled, Disabled

V Shift Angle 10º 2º 30º 1º

2.5.1 Setting guidelines for voltage vector shift protection

The element can be selected by setting the “V Shift Status” cell to ‘Enabled’.

The angle change setting threshold, “V Shift Angle”, should be set to the desiredlevel.

The setting threshold should be set such that the loss of mains condition can bedetected, this can be determined by system switching during initial commissioning.System simulation testing has shown that a “V Shift Angle” setting of 10º can providestable operation for external faults, and load switching events, whilst operating for aloss of mains event which causes a 10% change in the machine output for a typical4MW machine. Although in some circumstances, this setting may prove to be toosensitive, it is recommended to achieve a successful loss of mains trip in as manycases as possible. Although the vector shift function may trip the relay due to abolted 3 phase fault, it is also essential in securing a trip at the instant of an out-of-phase autoreclose, where the df/dt function does not trip.

This setting should be used as a guide but will by no means be acceptable in allapplications. Machine rating, governor response, local load and system load, will allaffect the dynamic response of a machine to a loss of mains event. Once installedthe settings should be periodically reviewed to ensure that they are adequate to detecta loss of grid connection event, but not too sensitive such that unwanted trippingoccurs during normal fault clearance that does not lead to the loss of mainscondition. Safety of personnel is paramount and this should be kept in mind whenoptimising settings; non-synchronised manual operation of circuit breakers must beprevented by disconnection of the embedded machine when the system becomesseparated.

2.6 Reconnection timer

As explained in sections 2.4 and 2.5, due to the sensitivity of the settings applied tothe df/dt and/or the Voltage Vector Shift element, false operation for non loss ofmains events may occur. This could, for example, be due to a close up three phasefault which can cause operation of a Voltage Vector Shift element. Such operationswill lead to the disconnection of the embedded machine from the external networkand prevent export of power. Alternatively the loss of mains protections may operatecorrectly, and auto re-closure equipment may restore the grid supply following atransient fault.

Disconnection of an embedded generator could lead to a simple loss of revenue. Orin cases where the licensing arrangement demands export of power at times of peakload may lead to penalty charges being imposed. To minimise the disruptioncaused, the P341 includes a reconnection timer. This timer is initiated followingoperation of any protection element that could operate due to a loss of mains event,i.e. df/dt, voltage vector shift, under/over frequency, power and under/over voltage.The timer is blocked should a short circuit fault protection element operate, i.e.residual overvoltage, overcurrent, and earth fault. Once the timer delay has expired



the element will provide a pulsed output signal. This signal can be used to initiateexternal synchronising equipment that can re-synchronise the machine with thesystem and reclose the CB.

A DDB (Digital Data Bus) signal is available to indicate that the element has operated(DDB 742 Reconnection). The state of the DDB signal 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 Reconnect Delay, including theavailable setting ranges and factory defaults:


Min. Max.Step Size

GROUP 1 RECONNECT DELAY

Reconnect Status Enabled Enabled, Disabled

Reconnect Delay 60 s 0 s 300 s 0.01 s

Reconnect tPULSE 1 s 0.01 s 30 s 0.01 s

2.6.1 Setting guidelines for the reconnect delay

The element can be selected by setting the “Reconnect Status” cell to ‘Enabled’.

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

2.7 Power protection

The power protection elements of the P341 relay calculate the three phase activepower based on the following formula, using the current measured at the IA, IB, ICinputs on the relay.

P = Vala cosa + Vblb cosb + Vclc cosc

Two stages of power protection are provided, these can be independently selected aseither Reverse Power, Over Power, Low Forward Power or Disabled, operation ineach mode is described in the following sections. The power elements may beselectively disabled, via fixed logic, so that they can be inhibited when used formachine protection and the protected machine CB is open. This will prevent falseoperation and nuisance flagging of any stage selected to operate as Low Forwardpower.

Where the local licensing agreement prevents the export of power into the localsupply Over Power protection may be used as a simple Loss of Mains protection. Inthese cases the element can be used to provide alarm and trip stages allowing themachine operators to closely monitor the machine export capability.

DDB signals are available to indicate starting and tripping of each stage(Starts: DDB 595, DDB 596, Trips: DDB 475, 476). The state of the DDB signals canbe programmed to be viewed in the “Monitor Bit x” cells of the “COMMISSIONTESTS” column in the relay.



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


Min. Max.Step Size

GROUP 1 POWER

Power1 Function Reverse Disabled, Reverse, Low Forward, Over

-P>1 Setting

20 x In W(Vn=100/120V)

80 x In W(Vn=380/480V)

14 x In W(Vn=100/120V)

56 x In W(Vn=380/480V)

40 x In W(Vn=100/120V)

160 x In W(Vn=380/480V)

2 x In W(Vn=100/120V)

8 x In W(Vn=380/480V)

P<1 Setting

20 x In W(Vn=100/120V)

80 x In W(Vn=380/480V)

14 x In W(Vn=100/120V)

56 x In W(Vn=380/480V)

40 x In W(Vn=100/120V)

160 x In W(Vn=380/480V)

2 x In W(Vn=100/120V)

8 x In W(Vn=380/480V)

P>1 Setting

120 x In W(Vn=100/120V)

20 x In W(Vn=380/480V)

14 x In W(Vn=100/120V)

56 x In W(Vn=380/480V)

300 x In W(Vn=100/120V)

1200 x In W(Vn=380/480V)

2 x In W(Vn=100/120V)

8 x In W(Vn=380/480V)

Power1 Time Delay 5 s 0 s 100 s 0.01 s

Power1 DO Timer 0 s 0 s 100 s 0.01 s

P1 Poledead Inh Enabled Enabled, Disabled

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

–P>2 Setting

20 x In W(Vn=100/120V)

20 x In W(Vn=380/480V)

14 x In W(Vn=100/120V)

56 x In W(Vn=380/480V)

40 x In W(Vn=100/120V)

160 x In W(Vn=380/480V)

2 x In W(Vn=100/120V)

8 x In W(Vn=380/480V)

P<2 Setting

20 x In W(Vn=100/120V)

20 x In W(Vn=380/480V)

14 x In W(Vn=100/120V)

56 x In W(Vn=380/480V)

40 x In W(Vn=100/120V)

160 x In W(Vn=380/480V)

2 x In W(Vn=100/120V)

8 x In W(Vn=380/480V)

P>2 Setting

120 x In W(Vn=100/120V)

20 x In W(Vn=380/480V)

14 x In W(Vn=100/120V)

56 x In W(Vn=380/480V)

300 x In W(Vn=100/120V)

100 x In W(Vn=380/480V)

2 x In W(Vn=100/120V)

8 x In W(Vn=380/480V)

Power2 Time Delay 5 s 0 s 100 s 0.01 s


P2 Poledead Inh Enabled Enabled, Disabled

2.7.1 Sensitive power protection function

The minimum standard 3 phase power protection setting (7%Pn for P341) can berestrictive for some applications. For example for steam turbine generators and somehydro generators a reverse power setting as low as 0.5%Pn is required. A sensitivesetting for low forward power protection may also be required, especially for steamturbine generators which have relatively low over speed design limits.

If a power setting less than 7%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 C 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 = A VA cos ( - C)

Where is the angle of A with respect to VA and C is the compensation anglesetting.

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

Pn = In 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.

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 stage (Starts:DDB 643, 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

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

Sen –P>1 Setting

0.5 x n W(Vn=100/120V)

2 x n W(Vn=380/480V)

0.3 x n W(Vn=100/120V)

1.2 x n W(Vn=380/480V)

15 x n W(Vn=100/120V)

60 x n W(Vn=380/480V)

0.1 x n W(Vn=100/120V)

0.4 x n W(Vn=380/480V)

Sen P<1 Setting

0.5 x n W(Vn=100/120V)

2 x n W(Vn=380/480V)

0.3 x n W(Vn=100/120V)

1.2 x n W(Vn=380/480V)

15 x n W(Vn=100/120V)

60 x n W(Vn=380/480V)

0.1 x n W(Vn=100/120V)

0.4 x n W(Vn=380/480V)

Sen P>1 Setting

50 x n W(Vn=100/120V)

200 x n W(Vn=380/480V)

0.3 x n W(Vn=100/120V)

1.2 x n W(Vn=380/480V)

100 x n W(Vn=100/120V)

400 x n W(Vn=380/480V)

0.1 x n W(Vn=100/120V)

0.4 x n W(Vn=380/480V)

Sen Power1 Delay 5 s 0 s 100 s 0.1 s


P1 Poledead nh Enabled Enabled, Disabled




Min MaxStep Size

Group 1: Sensitive Power

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

Sen –P>2 Setting

0.5 x n W(Vn=100/120V)

2 x n W(Vn=380/480V)

0.3 x n W(Vn=100/120V)

1.2 x n W(Vn=380/480V)

15 x n W(Vn=100/120V)

60 x n W(Vn=380/480V)

0.1 x n W(Vn=100/120V)

0.4 x n W(Vn=380/480V)

Sen P<2 Setting

0.5 x n W(Vn=100/120V)

2 x n W(Vn=380/480V)

0.3 x n W(Vn=100/120V)

1.2 x n W(Vn=380/480V)

15 x n W(Vn=100/120V)

60 x n W(Vn=380/480V)

0.1 x n W(Vn=100/120V)

0.4 x n W(Vn=380/480V)

Sen P>2 Setting

50 x n W(Vn=100/120V)

200 x n W(Vn=380/480V)

0.3 x n W(Vn=100/120V)

1.2 x n W(Vn=380/480V)

100 x n W(Vn=100/120V)

400 x n W(Vn=380/480V)

0.1 x n W(Vn=100/120V)

0.4 x n W(Vn=380/480V)

Sen Power2 Delay 2 s 0 s 100 s 0.1 s


P2 Poledead nh Enabled Enabled, Disabled

2.7.2 Over power protection

The Over Power function is a directional element that will operate when power flowsin the forward direction. From the convention, this means power flowing away fromthe busbar into the interconnection feeder or out of the protected machine.

Over Power protection can be used as simple overload indication, or as a back upprotection for failure of governor and control equipment, and would be set above themaximum power rating of the machine.

Alternatively the Over Power function can be used as protection against excessiveexport power for an embedded generator. In some installations the machine may beallowed to operate in parallel with the external supply but the exportation of powerinto the external supply may be forbidden. In these cases a simple Over Powerelement can be used to monitor the power flow at the interconnection circuit breakerand trip if power is seen to be exported into the system. For small standby generatorsthis may be accepted as the Loss of Mains protection.

2.7.2.1 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 “P2 Setting/Sen P>2 Setting”, should be set greater than the machine fullload rated power if providing overload protection. If the element is used to preventthe export of power into the external system then the threshold can be set to minimumor just in excess of the power export allowance.

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

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



2.7.3 Low forward power protection function

Low forward power may be used where the P341 relay is being used to protect asmall generator. When the CB connecting the generator to the system is tripped, theelectrical load on the machine is cut. This could lead to generator over-speed if themechanical input power is not reduced quickly. To reduce the risk of over speeddamage, it is sometimes chosen to interlock non-urgent tripping of the generatorbreaker with a low forward power check. This ensures that the generator set circuitbreaker is opened only when the output power is sufficiently low that over speeding isunlikely. The delay in electrical tripping, until prime mover input power has beenremoved, may be deemed acceptable for ‘non-urgent’ protection trips; e.g. statorearth fault protection for a high impedance earthed generator. For ‘urgent’ trips,e.g. stator short circuit protection the low forward power interlock should not be used.With the low probability of ‘urgent’ trips, the risk of over speed and possibleconsequences must be accepted.

The Low Forward Power protection can be arranged to interlock ‘non-urgent’ trippingusing the relay programmable 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 protectionelement can be disabled when the circuit breaker is opened via ‘poledead’ logic.

2.7.3.1 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/SenPower2 Func” cell to ‘Low Forward’.

When required, the threshold setting of the Low Forward Power protection function,“P<1 Setting/Sen P<1 Setting” or “P<2 Setting/Sen P<2 Setting”, should be lessthan 50% of the power level that could result in a dangerous over speed transient onloss of electrical loading. The generator set manufacturer should be consulted for arating for the protected machine.

The time delay associated with the Low Forward Power protection function, “Power1Time Delay/Sen Power1 Delay” or “Power2 Time Delay/Sen Power2 Delay”, could beset to zero. However, some delay is desirable so that permission for a non-urgentelectrical trip is not given in the event of power fluctuations arising from suddensteam valve/throttle closure. A typical time delay for this reason is 2s.

The delay on reset timer, “Power1 DO Timer” or “Power2 DO Timer”, wouldnormally be set to zero when selected to operate Low Forward power elements.

To prevent unwanted relay alarms and flags, a Low Forward Power protectionelement can be disabled when the circuit breaker is open via ‘poledead’ logic. This iscontrolled by setting the power protection inhibit cells, “P1 Poledead Inh” or “P2Poledead Inh”, to ‘Enabled’.

2.7.4 Reverse power protection function

Reverse Power protection may be used where the P341 relay is being used to protecta small generator. A generator is expected to supply power to the connected systemin normal operation. If the generator prime mover fails, a generator that isconnected in parallel with another source of electrical supply will begin to ‘motor’.This reversal of power flow due to loss of prime mover can be detected by the reversepower 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 of



motoring power and possible motoring damage that could occur for various types ofgenerating plant are given in Table 1.

Prime Mover Motoring Power(Percentage Rating) Possible Damage

Diesel Engine 5% – 25% Risk of fire or explosion from unburnedfuel

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

Gas Turbine

10% – 15%(Split-shaft)

>50%)(Single-shaft)

With some gear-driven sets, damagemay arise due to reverse torque ongear 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.

HydraulicTurbines

0.2 – >2%(Blades out of water)

>2.0%(Blades in water)

Blade and runner cavitation may occurwith a long period of motoring.

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

Table 1: Motoring power and possible damage for various types of prime mover

In some applications, the level of reverse power in the case of prime mover failuremay fluctuate. This may be the case for a failed diesel engine. To prevent cyclicinitiation and reset of the main trip timer, and consequent failure to trip, anadjustable reset time delay is provided (“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 Powerinterlocking is preferred over Low Forward Power interlocking by some utilities.

2.7.4.1 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’.

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 themotoring power, typical values for the level of reverse power for generators are givenin Table 1.



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 Time Delay/Sen Power1 Delay” or “Power2 TimeDelay/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.

2.8 Overcurrent protection

Overcurrent relays are the most commonly used protective devices in any industrial ordistribution power system. They provide main protection to both feeders and busbarswhen unit protection is not used. They are also commonly applied to provide back-up protection when unit systems, such as pilot wire schemes, are used.

By a combination of time delays and relay pick-up settings, overcurrent relays may beapplied to either feeders or power transformers to provide discriminative phase faultprotection (and also earth fault protection if system earth fault levels are sufficientlyhigh). In such applications, the various overcurrent relays on the system areco-ordinated with one another such that the relay nearest to the fault operates first.This is referred to as cascade operation because if the relay nearest to the fault doesnot operate, the next upstream relay will trip in a slightly longer time.

The overcurrent protection included in the P341 relay provides four stage non-directional/directional three phase overcurrent protection with independent timedelay characteristics. All overcurrent and directional settings apply to all three phasesbut are independent for each of the four stages.

The first two stages of overcurrent protection have time delayed characteristics whichare selectable between inverse definite minimum time (IDMT), or definite time (DT).The third and fourth stages have definite time characteristics only.

Various methods are available to achieve correct relay co-ordination on a system; bymeans of time alone, current alone or a combination of both time and current.Grading by means of current is only possible where there is an appreciable differencein fault level between the two relay locations. Grading by time is used by someutilities but can often lead to excessive fault clearance times at or near sourcesubstations where the fault level is highest. For these reasons the most commonlyapplied characteristic in co-ordinating overcurrent relays is the IDMT type.

Each stage can be blocked by energising the relevant DDB signal via the PSL (DDB354, DDB 355, DDB 356, DDB 357). This allows the overcurrent protection to beintegrated into busbar protection schemes, as shown in section 2.18, or can be usedto improve grading with downstream devices. DDB signals are also available toindicate the start and trip of each phase of each stage of protection, (Starts: DDB597-612, Trips: DDB 477-492). The state of the DDB signals can be programmed tobe viewed in the “Monitor Bit x” cells of the “COMMISSION TESTS” column in therelay.

The following table shows the relay menu for the overcurrent protection, including theavailable setting ranges and factory defaults:




Min. Max.Step Size

GROUP 1 OVERCURRENT

I>1 Function IEC S Inverse

Disabled, DT, IEC S Inverse, IEC V Inverse,IEC E Inverse, UK LT Inverse, IEEE M

Inverse, IEEE V Inverse, IEEE E Inverse, USInverse, US ST Inverse

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

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

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

I>1 TMS 1 0.025 1.2 0.025

I>1 Time Dial 7 0.5 15 0.1

I>1 Reset Char DT DT or Inverse

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

I>2 Cells as forI>1 above

I>3 Status Disabled Disabled, Enabled

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

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

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

I>4 Cells as forI>3 above

I> Char Angle 45º –95° +95° 1°

I> Function LinkSee Note

00001111Bit 0 I>1 VTS Block, Bit 1 I>2 VTS Block,Bit 2 I>3 VTS Block, Bit 3 I>4 VTS Block,

Bit 4, 5, 6 & 7 Not Used

Note: VTS Block – When relevant bit set to 1, operation of Voltage TransformerSupervision (VTS) will block stage if directionalised. When set to 0, stage willrevert to non-directional.

The inverse time delayed characteristics listed above, comply with thefollowing formula:

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

t = T x

K

(/s) - 1 +L



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

t =

TD

7 x

K

(/s) - 1 + L

where t = operation time

K = constant

I = measured current

IS = current threshold setting

= 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 CurveDescription Standard K

Constant

ConstantL

Constant

Standard inverse IEC 0.14 0.02 0

Very inverse IEC 13.5 1 0

Extremely inverse IEC 80 2 0

Long time inverse UK 120 1 0

Moderately inverse IEEE 0.0515 0.02 0.114

Very inverse IEEE 19.61 2 0.491

Extremely inverse IEEE 28.2 2 0.1217

Inverse US-C08 5.95 2 0.18

Short time inverse US-C02 0.02394 0.02 0.01694

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‘I> Time Dial’ cell is not visible and vice versa for the TMS setting.

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 overcurrent protection function operates from the phase currents measured bythe A, B and C measurement inputs on the relay.



2.8.1 Transformer magnetising inrush

When applying overcurrent protection to the HV side of a power transformer, it isusual to apply a high set instantaneous overcurrent element, in addition to the timedelayed low-set, to reduce fault clearance times for HV fault conditions. Typically,this will be set to approximately 1.3 times the LV fault level, such that it will onlyoperate for HV faults. A 30% safety margin is sufficient due to the low transientoverreach of the third and fourth overcurrent stages. Transient overreach defines theresponse of a relay to DC components of fault current and is quoted as a percentage.A relay with a low transient overreach will be largely insensitive to a DC offset andmay therefore be set more closely to the steady state AC waveform.

The second requirement for this element is that it should remain inoperative duringtransformer energisation, when a large primary current flows for a transient period.In most applications, the requirement to set the relay above the LV fault level willautomatically result in settings that will be above the level of magnetising inrushcurrent.

Due to the nature of operation of the third and fourth overcurrent stages in the P341relays, it is possible to apply settings corresponding to 35% of the peak inrushcurrent, whilst maintaining stability for the condition.

This is important where low-set instantaneous stages are used to initiate autorecloseequipment. In such applications, the instantaneous stage should not operate forinrush conditions, which may arise from small teed-off transformer loads forexample. However, the setting must also be sensitive enough to provide fastoperation under fault conditions.

Where an instantaneous element is required to accompany the time delayedprotection, as described above, the third or fourth overcurrent stage of the P341 relayshould be used, as they have wider setting ranges.

2.8.2 Application of timer hold facility

The first two stages of overcurrent protection in the P341 relays are provided with atimer hold facility, which may either be set to zero or to a definite time value. (Notethat if an IEEE/US operate curve is selected, the reset characteristic may be set toeither definite or inverse time in cell ‘I>1 Reset Char’; otherwise this setting cell is notvisible in the menu). Setting of the timer to zero means that the overcurrent timer forthat stage will reset instantaneously once the current falls below 95% of the currentsetting. Setting of the hold timer to a value other than zero delays the resetting of theprotection element timers for this period. This may be useful in certain applications,for example when grading with upstream electromechanical overcurrent relays whichhave inherent reset time delays.

Another situation where the timer hold facility may be used to reduce fault clearancetimes is where intermittent faults may be experienced. An example of this may occurin a plastic insulated cable. In this application it is possible that the fault energy meltsand reseals the cable insulation, thereby extinguishing the fault. This process repeatsto give a succession of fault current pulses, each of increasing duration with reducingintervals between the pulses, until the fault becomes permanent.

When the reset time of the overcurrent relay is instantaneous the relay will berepeatedly reset and not be able to trip until the fault becomes permanent. By usingthe Timer Hold facility the relay will integrate the fault current pulses, therebyreducing fault clearance time.



The timer hold facility can be found for the first and second overcurrent stages assettings ‘I>1 tRESET’ and ‘I>2 tRESET’, respectively. Note that this cell is not visible ifan inverse time reset characteristic has been selected, as the reset time is thendetermined by the programmed time dial setting.

2.8.3 Setting guidelines

When applying the overcurrent protection provided in the P341 relays, standardprinciples should be applied in calculating the necessary current and time settings forco-ordination. The setting example detailed below shows a typical setting calculationand describes how the settings are actually applied to the relay.

Assume the following parameters for a relay feeding an LV switchboard:

CT Ratio = 500/1

Full Load Current of circuit = 450A

Slowest downstream protection = 100A Fuse

The current setting employed on the P341 relay must account for both the maximumload current and the reset ratio of the relay itself:

I> must be greater than: 450/0.95 = 474A

The P341 relay allows the current settings to be applied to the relay in either primaryor secondary quantities. Programming the ‘Setting Values’ cell of the“CONFIGURATION” column to either ‘Primary’ or ‘Secondary’ does this. When thiscell is set to primary, all phase overcurrent setting values are scaled by theprogrammed CT ratio. This is found in column 0A of the relay menu, entitled “VT &CT RATIOS”, where cells ‘Phase CT Primary’ and ‘Phase CT Sec’y’ can beprogrammed with the primary and secondary CT ratings, respectively.

In this example, assuming primary currents are to be used, the ratio should beprogrammed as 500/1.

The required setting is therefore 0.95A in terms of secondary current or 475A interms of primary.

A suitable time delayed characteristic will now need to be chosen. Whenco-ordinating with downstream fuses, the applied relay characteristic should beclosely matched to the fuse characteristic. Therefore, assuming IDMT co-ordination isto be used, an Extremely Inverse (EI) characteristic would normally be chosen. Aspreviously described, this is found under ‘I>1 Function’ and should therefore beprogrammed as ‘IEC E Inverse’.

Finally, a suitable time multiplier setting (TMS) must be calculated and entered in cell‘I>1 TMS’.

For more detailed information regarding overcurrent relay co-ordination, referenceshould be made to ALSTOM’S ‘Network Protection & Automation Guide’ – Chapter 9.

2.9 Directional overcurrent protection

If fault current can flow in both directions through a relay location, it is necessary toadd directionality to the overcurrent relays in order to obtain correct co-ordination.Typical systems that require such protection are parallel feeders (both plain andtransformer) and ring main systems, each of which are relatively common indistribution networks.



In order to give directionality to an overcurrent relay, it is necessary to provide it witha suitable reference, or polarising, signal. The reference generally used is the systemvoltage, as it’s angle remains relatively constant under fault conditions. The phasefault elements of the P341 relay are internally polarised by the quadrature phase-phase voltages, as shown in the table below:

Phase of Protection Operate Current Polarising Voltage

A Phase IA VBC

B Phase IB VCA

C Phase IC VAB

It is therefore important to ensure the correct phasing of all current and voltage inputsto the relay, in line with the supplied application diagram.

Under system fault conditions, the fault current vector will lag it’s nominal phasevoltage by an angle dependent upon the system X/R ratio. It is therefore arequirement that the relay operates with maximum sensitivity for currents lying in thisregion. This is achieved by means of the relay characteristic angle (RCA) setting; thisdefines the angle by which the current applied to the relay must be displaced fromthe voltage applied to the relay to obtain maximum relay sensitivity. This is set in cell‘I>Char Angle’ in the Overcurrent menu.

Figure 3 shows a typical distribution system utilising parallel power transformers. Insuch an application, a fault at ‘F’ could result in the operation of both R3 and R4relays and the subsequent loss of supply to the 11kV busbar. Hence, with this systemconfiguration, it is necessary to apply directional relays at these locations set to “lookinto” their respective transformers. These relays should co-ordinate with the non-directional relays, R1 and R2; hence ensuring discriminative relay operation duringsuch fault conditions.

In such an application, relays R3 and R4 may commonly require non-directionalovercurrent protection elements to provide protection to the 11kV busbar, in additionto providing a back-up function to the overcurrent relays on the outgoing feeders(R5).

When applying the P341 relays in the above application, stage 1 of the overcurrentprotection of relays R3 and R4 would be set non-directional and time graded with R5,using an appropriate time delay characteristic. Stage 2 could then be set directional,looking back into the transformer, also having a characteristic which provided correctco-ordination with R1 and R2. IDMT or DT characteristics are selectable for bothstages 1 and 2 and directionality of each of the overcurrent stages is set in cell ‘I>Direction’



!!"

Figure 3: Typical distribution system using parallel transformers

Note that the principles previously outlined for the parallel transformer applicationare equally applicable for plain feeders which are operating in parallel.

2.9.1 Synchronous polarisation

For a fault condition that occurs close to the relaying point, the faulty phase voltagewill reduce to a value close to zero volts. For single or double phase faults, there willalways be at least one healthy phase voltage present for polarisation of the phaseovercurrent elements. For example, a close up A to B fault condition will result in thecollapse of the A and B phase voltages. However, the A and B phase elements arepolarised from VBC and VCA respectively. As such a polarising signal will bepresent, allowing correct relay operation.

For a close up three phase fault, all three voltages will collapse to zero and nohealthy phase voltages will be present. For this reason, the P341 relays include asynchronous polarisation feature that stores the pre-fault voltage information andcontinues to apply it to the DOC elements for a time period of 3.2 seconds. Thisensures that either instantaneous or time delayed DOC elements will be allowed tooperate, even with a three phase voltage collapse.




The applied current settings for directional overcurrent relays are dependent upon theapplication in question. In a parallel feeder arrangement, load current is alwaysflowing in the non-operate direction. Hence, the relay current setting may be lessthan the full load rating of the circuit; typically 50% of In.

Note that the minimum setting that may be applied has to take into account thethermal rating of the relay. Some electro-mechanical directional overcurrent relayshave continuous withstand ratings of only twice the applied current setting and hence50% of rating was the minimum setting that could be applied. With the P341, thecontinuous current rating is 4 x rated current and so it is possible to apply much moresensitive settings, if required. However, there are minimum safe current settingconstraints to be observed when applying directional overcurrent protection at thereceiving-ends of parallel feeders. The minimum safe settings to ensure that there isno possibility of an unwanted trip during clearance of a source fault are as follows forlinear system load:

Parallel plain feeders:

Set>50% Prefault load current

Parallel transformer feeders:

Set>87% Prefault load current

When the above setting constraints are infringed, independent-time protection ismore likely to issue an unwanted trip during clearance of a source fault thandependent-time protection.

Where the above setting constraints are unavoidably infringed, secure phase faultprotection can be provided with relays which have 2-out-of-3 directional protectiontripping logic.

A common minimum current setting recommendation (50% relay rated current) wouldbe virtually safe for plain parallel feeder protection as long as the circuit load currentdoes not exceed 100% relay rated current. It would also be safe for paralleltransformer feeders, if the system design criterion for two feeders is such that the loadon each feeder will never exceed 50% rated current with both feeders in service. Formore than two feeders in parallel the 50% relay rated current setting may not beabsolutely safe.

In a ring main application, it is possible for load current to flow in either directionthrough the relaying point. Hence, the current setting must be above the maximumload current, as in a standard non-directional application.

The required characteristic angle settings for directional relays will differ dependingon the exact application in which they are used. Recommended characteristic anglesettings are as follows:

Plain feeders, or applications with an earthing point (zero sequence source)behind the relay location, should utilise a +30º RCA setting.

Transformer feeders, or applications with a zero sequence source in front of therelay location, should utilise a +45º RCA setting.

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



2.10 Earth fault protection

The P341 relay has a total of four input current transformers; one for each of thephase current inputs and one for supplying the sensitive earth fault protectionelement. Residual, or earth fault, current can be derived from the sum of the phasecurrent inputs. With this flexible input arrangement, various combinations ofstandard, sensitive (SEF) and restricted earth fault (REF) protection may be configuredwithin the relay.

It should be noted that in order to achieve the sensitive setting range that is availablein the P341 relay for SEF protection, the input CT is designed specifically to operate atlow current magnitudes. This common input is used to drive either the SEF or REFprotection which are enabled / disabled accordingly within the relay menu.

2.10.1 Standard earth fault protection element

The four stage Standard Earth Fault protection operates from earth fault currentwhich is derived internally from the summation of the three phase currents.

The first and second stages have selectable IDMT or DT characteristics, whilst thethird and fourth stages are DT only. Each stage is selectable to be either non-directional, directional forward or directional reverse. The Timer Hold facility,previously described for the overcurrent elements, is available on each of the first twostages.


The following table shows the relay menu for the Earth Fault protection, including theavailable setting ranges and factory defaults:


Min. Max.Step Size

GROUP 1 EARTH FAULT 1

IN>1 Function IEC S Inverse

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

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

IN>1 DirectionNon-

Directional Non-Directional, Directional Fwd, Directional Rev

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

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

IN1>1 TMS 1 0.025 1.2 0.025

IN1>1 Time Dial 7 0.5 15 0.1

IN>1 Reset Char DT DT or Inverse

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

IN>2 Cells as forIN>1 above




Min. Max.Step Size

GROUP 1 EARTH FAULT 1

IN>3 Status Disabled Disabled, Enabled

IN>3 DirectionNon-

DirectionalNon-Directional, Directional Fwd, Directional Rev

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

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

IN>4 Cells as forIN>3 above

IN> Function LinkSee Note 00001111

Bit 0 I>1 VTS Block, Bit 1 I>2 VTS Block, Bit 2 I>3VTS Block, Bit 3 I>4 VTS Block,

Bit 4, 5 6&7 Not Used

IN> DIRECTIONAL Sub Heading

IN> Char Angle –60º –95° +95° 1°

IN1> PolZero

SequenceZero Sequence, Neg Sequence

IN1>VNpol Set

5 V(Vn=100/120V)

20V(Vn=380/480V)

0.5V(Vn=100/120V)

2V(Vn=380/480V)

22V(Vn=100/120V)

88V(Vn=380/480V)

0.5V(Vn=100/120V)

2V(Vn=380/480V)

IN1>V2pol Set

5 V(Vn=100/120V)

20V(Vn=380/480V)

0.5V(Vn=100/120V)

2V(Vn=380/480V)

22V(Vn=100/120V)

88V(Vn=380/480V)

0.5V(Vn=100/120V)

2V(Vn=380/480V)

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

Note: VTS Block - When relevant bit set to 1, operation of VTS will block stage ifdirectionalised. When set to 0, stage will revert to non-directional.

For the range of available inverse time delayed characteristics, refer to thoseof the phase overcurrent elements, section 2.9.

The multiple stages may be enabled in the relay at the same time, thisprovides some application advantages. For example, the paralleltransformer application shown in Figure 1 requires directional earth faultprotection at locations R3 and R4, to provide discriminative protection.However, in order to provide back-up protection for the busbar and otherdownstream earth fault devices, non-directional earth fault protection canalso be applied.

Where a neutral earthing resistor (NER) is used to limit the earth fault level, itis possible that an earth fault condition could cause a flashover of the NERand hence a dramatic increase in the earth fault current. For this reason, itmay be appropriate to apply two stage EF protection. The first stage shouldhave current and time characteristics which co-ordinate with downstreamearth fault protection. A second stage may then be set with a higher currentsetting greater than the NER limited fault current but with zero time delay;hence providing fast clearance of an earth fault which gives rise to an NERflashover.



2.10.2 Sensitive earth fault protection element (SEF)

If a system is earthed through high impedance, or is subject to high ground faultresistance, the earth fault level will be severely limited. Consequently, the appliedearth fault protection requires both an appropriate characteristic and a sensitivesetting range in order to be effective. A separate 4 stage Sensitive Earth Faultelement is provided within the P341 relay for this purpose, this has a dedicated CTinput.


The following table shows the relay menu for the ‘Sensitive Earth Fault ‘ protection,including the available setting ranges and factory defaults.


Min. Max.Step Size

GROUP 1 SEF/REF PROT’N

Sens E/F Options SEFSEF, SEF cos (PHI), SEF sin (PHI), Wattmetric, Hi Z

REF

ISEF>1 Function DT

Disabled, DT, IEC S Inverse, IEC V Inverse, IEC EInverse, UK LT Inverse, IEEE M Inverse, IEEE V

Inverse, IEEE E Inverse, US Inverse,US ST Inverse

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

Directional Rev

ISEF>1 Current 0.05 x In A 0.005 x In A 0.1 x In A 0.00025 x In A

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

ISEF>1 TMS 1 0.025 1.2 0.025

ISEF>1 Time Dial 7 0.5 15 0.1

ISEF>1 Reset Char DT DT or Inverse

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

ISEF>2 Cells as forISEF>1 above

ISEF>3 Status Disabled Disabled, Enabled

ISEF>3 DirectionNon-

DirectionalNon-Directional, Directional Fwd,

Directional Rev

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

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

ISEF>4 Cells as forISEF>3 above

ISEF> Func LinkSee Note

00001111Bit 0 ISEF>1 VTS Block, Bit 1 ISEF>2 VTS Block,Bit 2 ISEF>3 VTS Block, Bit 3 ISEF>4 VTS Block,

Bit 4, 5, 6 & 7 Not Used




Min. Max.Step Size


ISEF DIRECTIONAL Sub Heading

ISEF> Char Angle 90º –95° +95° 1°

ISEF> VNpol Input Measured Measured, Derived

ISEF> VNpol Set

5 V(Vn=100/120V)

20V(Vn=380/480V)

0.5V(Vn=100/120V)

2V(Vn=380/480V)

80V(Vn=100/120V)

320V(Vn=380/480V)

0.5V(Vn=100/120V)

2V(Vn=380/480V)

WATTMETRIC SEF Sub Heading

PN> Setting

9 x In W(Vn=100/120V)

36 x In W(Vn=380/480V)

0 x In W(Vn=100/120V)

0 x In W(Vn=380/480V)

20 x In W(Vn=100/120V)

80 x In W(Vn=380/480V)

0.05 x In W(Vn=100/120V)

0.2 x In W(Vn=380/480V)

Note: VTS Block - When relevant bit set to 1, operation of VTS will block stage ifdirectionalised. When set to 0, stage will revert to non-directional.

For the range of available inverse time delayed characteristics, refer to thoseof the phase overcurrent elements, section 2.9.

Notes: As can be seen from the menu, the ‘Sens E/F Options’ cell has a number ofsetting options. To enable standard, four stage SEF protection, the ‘SEF’option should be selected, which is the default setting. However, ifwattmetric or restricted earth fault protection is required, then one of theremaining options should be selected. These are described in more detail insection 2.11.6. The ‘WATTMETRIC’ and ‘RESTRICTED E/F’ cells will onlyappear in the menu if the functions have been selected in the Options cell.

As shown in the previous menu, each SEF stage is selectable to be eithernon-directional, directional forward or directional reverse in the ‘ISEF>Direction’ cell. The Timer Hold facility, previously described for theovercurrent elements in section 2.9, is available on each of the first twostages and is set in the same manner.

Settings related to directionalising the SEF protection are described in detailin the following section.

SEF would normally be fed from a core balance current transformer (CBCT)mounted around the three phases of the feeder cable. However, care mustbe taken in the positioning of the CT with respect to the earthing of the cablesheath. See Figure 4 below:



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Figure 4: Positioning of core balance current transformers

As can be seen from the diagram, if the cable sheath is terminated at the cable glandand earthed directly at that point, a cable fault (from phase to sheath) will not resultin any unbalance current in the core balance CT. Prior to earthing, the connectionmust be brought back through the CBCT and earthed on the feeder side. Thisensures correct relay operation during earth fault conditions.

2.11 Directional earth fault protection (DEF)

Each of the four stages of standard earth fault protection and SEF protection may beset to be directional if required. Consequently, as with the application of directionalovercurrent protection, a voltage supply is required by the relay to provide thenecessary polarisation.

With the standard earth fault protection element in the P341 relay, two options areavailable for polarisation; Residual Voltage or Negative Sequence.

2.11.1 Residual voltage polarisation

With earth fault protection, the polarising signal requires to be representative of theearth fault condition. As residual voltage is generated during earth fault conditions,this quantity is commonly used to polarise DEF elements. The P341 relay caninternally derive this voltage from the 3 phase voltage input, or can measure thevoltage via the neutral displacement or residual overvoltage input. The method of



measuring the polarising signal is set in the “IN> Vnpol Input” cell. Where theresidual voltage is derived from the 3 phase voltages a 5-limb or three single phaseVT’s must be used. These types of VT design allow the passage of residual flux andconsequently permit the relay to derive the required residual voltage. In addition, theprimary star point of the VT must be earthed. A three limb VT has no path forresidual flux and is therefore unsuitable to supply the relay.

It is possible that small levels of residual voltage will be present under normal systemconditions due to system imbalances, VT inaccuracies, relay tolerances etc. Hence,the P341 relay includes a user settable threshold, “IN>VNpol Set”, which must beexceeded in order for the DEF function to be operational. The residual voltagemeasurement provided in the “MEASUREMENTS 1” column of the menu may assist indetermining the required threshold setting during the commissioning stage, as thiswill indicate the level of standing residual voltage present.

Note that residual voltage is nominally 180º out of phase with residual current.Consequently, the DEF relays are polarised from the ‘–Vres’ quantity. This 180ºphase shift is automatically introduced within the P341 relay.

2.11.2 Negative sequence polarisation

In certain applications, the use of residual voltage polarisation of DEF may either benot possible to achieve, or problematic. An example of the former case would bewhere a suitable type of VT was unavailable, for example if only a three limb VT wasfitted. An example of the latter case would be an HV/EHV parallel line applicationwhere problems with zero sequence mutual coupling may exist.

In either of these situations, the problem may be solved by the use of negative phasesequence (nps) quantities for polarisation. This method determines the fault directionby comparison of nps voltage with nps current. The operate quantity, however, is stillresidual current. This is available for selection on the derived earth fault element butnot on the SEF protection. It requires a voltage and current threshold to be set in cells“IN> V2pol Set” & “IN> I2pol Set”, respectively.

Negative sequence polarising is not recommended for impedance earthed systemsregardless of the type of VT feeding the relay. This is due to the reduced earth faultcurrent limiting the voltage drop across the negative phase sequence sourceimpedance (V2pol) to negligible levels. If this voltage is less than 0.5 volts the relaywill cease to provide DEF protection.

2.11.3 General setting guidelines for DEF

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

The following angle settings are recommended for a residual voltage polarised relay:

Resistance earthed systems 0º

Distribution systems (solidly earthed) –45º

Transmission Systems (solidly earthed) –60º



For negative sequence polarisation, the RCA settings must be based on the angle ofthe nps source impedance, much the same as for residual polarising. Typical settingswould be:

Distribution systems –45º

Transmission Systems –60º

2.11.4 Application to insulated systems

The advantage gained by running a power system which is insulated from earth is thefact that during a single phase to earth fault condition, no earth fault current isallowed to flow. Consequently, it is possible to maintain power flow on the systemeven when an earth fault condition is present. However, this advantage is offset bythe fact that the resultant steady state and transient overvoltages on the sound phasescan be very high. It is generally the case, therefore, that insulated systems will onlybe used in low/medium voltage networks where it does not prove too costly toprovide the necessary insulation against such overvoltages. Higher system voltageswould normally be solidly earthed or earthed via a low impedance.

Operational advantages may be gained by the use of insulated systems. However, itis still vital that detection of the fault is achieved. This is not possible by means ofstandard current operated earth fault protection. One possibility for fault detection isby means of a residual overvoltage device. This functionality is included within theP341 relays and is detailed in section 2.12. However, fully discriminative earth faultprotection on this type of system can only be achieved by the application of asensitive earth fault element. This type of relay is set to detect the resultant imbalancein the system charging currents that occurs under earth fault conditions. It is thereforeessential that a core balance CT is used for this application. This eliminates thepossibility of spill current that may arise from slight mismatches between residuallyconnected line CT’s. It also enables a much lower CT ratio to be applied, therebyallowing the required protection sensitivity to be more easily achieved.

Consider Figure 5:



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



From Figure 5, it can be seen that the relays on the healthy feeders see theunbalance in the charging currents for their own feeder. The relay on the faultedfeeder, however, sees the charging current from the rest of the system (IH1 and IH2in this case), with it’s own feeders charging current (IH3) becoming cancelled out.This is further illustrated by the phasor diagrams shown in Figure 6.

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

Referring to the phasor diagram, it can be seen that the C phase to earth fault causesthe voltages on the healthy phases to rise by a factor of √3. The A phase chargingcurrent (Ia1), is then shown to be leading the resultant A phase voltage by 90º.Likewise, the B phase charging current leads the resultant Vb by 90º.

The unbalance current detected by a core balance current transformer on the healthyfeeders can be seen to be the vector addition of Ia1 and Ib1, giving a residualcurrent which lies at exactly 90º lagging the polarising voltage (–3Vo). As the healthyphase voltages have risen by a factor of √3, the charging currents on these phaseswill also be √3 times larger than their steady state values. Therefore, the magnitudeof residual current, IR1, is equal to 3 x the steady state per phase charging current.

The phasor diagrams indicate that the residual currents on the healthy and faultedfeeders, IR1 and IR3 respectively, are in anti-phase. A directional element couldtherefore be used to provide discriminative earth fault protection.

If the polarising voltage of this element, equal to –3Vo, is shifted through +90º, theresidual current seen by the relay on the faulted feeder will lie within the operateregion of the directional characteristic and the current on the healthy feeders will fallwithin the restrain region.

As previously stated, the required characteristic angle setting for the SEF elementwhen applied to insulated systems, is +90º. It should be noted though, that thisrecommended setting corresponds to the relay being connected such that it’sdirection of current flow for operation is from the source busbar towards the feeder,as would be the convention for a relay on an earthed system. However, if theforward direction for operation was set as being from the feeder into the busbar,(which some utilities may standardise on), then a –90( RCA would be required. The



correct relay connections to give a defined direction for operation are shown on therelay connection diagram.

Note that discrimination can be provided without the need for directional control.This can only be achieved if it is possible to set the relay in excess of the chargingcurrent of the protected feeder and below the charging current for the rest of thesystem.

2.11.5 Setting guidelines – insulated systems

As has been previously shown, the residual current detected by the relay on thefaulted feeder is equal to the sum of the charging currents flowing from the rest of thesystem. Further, the addition of the two healthy phase charging currents on eachfeeder gives a total charging current which has a magnitude of three times the perphase value. Therefore, the total unbalance current detected by the relay is equal tothree times the per phase charging current of the rest of the system. A typical relaysetting may therefore be in the order of 30% of this value, i.e. equal to the per phasecharging current of the remaining system. Practically though, the required settingmay well be determined on site, where suitable settings can be adopted based uponpractically obtained results. The use of the P140 relays’ comprehensive measurementand fault recording facilities may prove useful in this respect.

2.11.6 Application to petersen coil earthed systems

Power systems are usually earthed in order to limit transient overvoltages duringarcing faults and also to assist with detection and clearance of earth faults.Impedance earthing has the advantage of limiting damage incurred by plant duringearth fault conditions and also limits the risk of explosive failure of switchgear, whichis a danger to personnel. In addition, it limits touch and step potentials at asubstation or in the vicinity of an earth fault.

If a high impedance device is used for earthing the system, or the system isunearthed, the earth fault current will be reduced but the steady state and transientovervoltages on the sound phases can be very high. Consequently, it is generally thecase that high impedance earthing will only be used in low/medium voltage networksin which it does not prove too costly to provide the necessary insulation against suchovervoltages. Higher system voltages would normally be solidly earthed or earthedvia a low impedance.

A special case of high impedance earthing via a reactor occurs when the inductiveearthing reactance is made equal to the total system capacitive reactance to earth atsystem frequency. This practice is widely referred to as Petersen (or resonant) CoilEarthing. With a correctly tuned system, the steady state earthfault current will bezero, so that arcing earth faults become self extinguishing. Such a system can, ifdesigned to do so, be run with one phase earthed for a long period until the cause ofthe fault is identified and rectified. With the effectiveness of this method beingdependent upon the correct tuning of the coil reactance to the system capacitivereactance, an expansion of the system at any time would clearly necessitate anadjustment of the coil reactance. Such adjustment is sometimes automated.

Petersen Coil earthed systems are commonly found in areas where the power systemconsists mainly of rural overhead lines and can be particularly beneficial in locationswhich are subject to a high incidence of transient faults. Transient earth faults causedby lightning strikes, for example, can be extinguished by the Petersen Coil without theneed for line outages.

Figure 7 shows a source of generation earthed through a Petersen Coil, with an earthfault applied on the A Phase. Under this situation, it can be seen that the A phaseshunt capacitance becomes short circuited by the fault. Consequently, the



calculations show that if the reactance of the earthing coil is set correctly, the resultingsteady state earth fault current will be zero.

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Prior to actually applying protective relays to provide earth fault protection on systemswhich are earthed via a Petersen Coil, it is imperative to gain an understanding of thecurrent distributions that occur under fault conditions on such systems. With thisknowledge, it is then possible to decide on the type of relay that may be applied,ensuring that it is both set and connected correctly.

Figure 8 shows a radial distribution system having a source which is earthed via aPetersen Coil. Three outgoing feeders are present, the lower of which has a phase toearth fault applied on the C phase.



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

Figures 9 (a, b and c) show vector diagrams for the previous system, assuming that itis fully compensated (i.e. coil reactance fully tuned to system capacitance), in additionto assuming a theoretical situation where no resistance is present either in theearthing coil or in the feeder cables.

Referring to the vector diagram illustrated in Figure 9a, it can be seen that the Cphase to earth fault causes the voltages on the healthy phases to rise by a factor of3. The A phase charging currents (Ia1, Ia2 and Ia3), are then shown to be leadingthe resultant A phase voltage by 90° and likewise for the B phase charging currentswith respect to the resultant Vb.

The unbalance current detected by a core balance current transformer on the healthyfeeders can be seen to be a simple vector addition of Ia1 and Ib1, giving a residualcurrent which lies at exactly 90° lagging the residual voltage (Figure 9b). Clearly, asthe healthy phase voltages have risen by a factor of 3, the charging currents onthese phases will also be 3 times larger than their steady state values. Therefore,the magnitude of residual current, IR1, is equal to 3 x the steady state per phasecharging current.



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Note: The actual residual voltage used as a reference signal for directional earthfault relays is phase shifted by 180° and is therefore shown as –3Vo in thevector diagrams. This phase shift is automatically introduced within theP140 relays.

On the faulted feeder, the residual current is the addition of the chargingcurrent on the healthy phases (IH3) plus the fault current (IF). The netunbalance is therefore equal to IL-IH1-IH2, as shown in Figure 9c.

This situation may be more readily observed by considering the zerosequence network for this fault condition. This is depicted in Figure 10.



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In comparing the residual currents occurring on the healthy and on the faultedfeeders (Figures 9b & 9c), it can be seen that the currents would be similar in bothmagnitude and phase; hence it would not be possible to apply a relay which couldprovide discrimination.

However, as previously stated, the scenario of no resistance being present in the coilor feeder cables is purely theoretical. Further consideration therefore needs to begiven to a practical application in which the resistive component is no longer ignored– consider Figure 11.



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

Figure 11a again shows the relationship between the capacitive currents, coil currentand residual voltage. It can now be seen that due to the presence of resistance in thefeeders, the healthy phase charging currents are now leading their respective phasevoltages by less than 90°. In a similar manner, the resistance present in the earthingcoil has the effect of shifting the current, IL, to an angle less than 90° lagging. Theresult of these slight shifts in angles can be seen in Figures 11b and 11c.

The residual current now appears at an angle in excess of 90° from the polarisingvoltage for the unfaulted feeder and less than 90° on the faulted feeder. Hence, adirectional relay having a characteristic angle setting of 0° (with respect to thepolarising signal of –3Vo) could be applied to provide discrimination. i.e. the healthyfeeder residual current would appear within the restrain section of the characteristicbut the residual current on the faulted feeder would lie within the operate region – asshown in diagrams 11b and 11c.

In practical systems, it may be found that a value of resistance is purposely inserted inparallel with the earthing coil. This serves two purposes; one is to actually increasethe level of earth fault current to a more practically detectable level and the second isto increase the angular difference between the residual signals; again to aid in theapplication of discriminating protection.

2.12 Operation of sensitive earth fault element

It has been shown that the angular difference between the residual currents on thehealthy and faulted feeders allows the application of a directional relay whose zerotorque line passes between the two currents. Two possibilities exist for the type ofprotection element that may consequently be applied for earth fault detection:



1. A suitably sensitive directional earth fault relay having a relay characteristicangle setting (RCA) of zero degrees, with the possibility of fine adjustment aboutthis threshold.

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

3. A sensitive directional earth fault relay having Icos and Isin characteristics.

All stages of the sensitive earth fault element of the P341 relay are settable down to0.5% of rated current and would therefore fulfill the requirements of the first methodlisted above and could therefore be applied successfully. However, many utilities(particularly in central Europe) have standardised on the wattmetric method of earthfault detection, which is described in the following section.

Zero sequence power measurement, as a derivative of Vo and Io, offers improvedrelay security against false operation with any spurious core balance CT output fornon earth fault conditions. This is also the case for a sensitive directional earth faultrelay having an adjustable Vo polarising threshold.

Some utilities in Scandinavia prefer to use cos/sin for non compensated PetersonCoil or insulated networks.

Wattmetric Characteristic

The previous analysis has shown that a small angular difference exists between thespill current on the healthy and faulted feeders. It can be seen that this angulardifference gives rise to active components of current which are in antiphase to oneanother. This is shown in Figure 12 below:

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Consequently, the active components of zero sequence power will also lie in similarplanes and so a relay capable of detecting active power would be able to make adiscriminatory decision. i.e. if the wattmetric component of zero sequence power wasdetected in the forward direction, then this would be indicative of a fault on thatfeeder; if power was detected in the reverse direction, then the fault must be presenton an adjacent feeder or at the source.

For operation of the directional earth fault element within the P140 relays, all three ofthe settable thresholds on the relay must be exceeded; namely the current "ISEF>",the voltage "ISEF>VNpol Set" and the power "PN> Setting".



As can be seen from the following formula, the power setting within the relay menu iscalled PN> and is therefore calculated using residual rather than zero sequencequantities. Residual quantities are three times their respective zero sequence valuesand so the complete formula for operation is as shown below:

Vres x Ires X Cos ( – c) = 9 x Vo x Io x Cos ( – c)

Where:

= Angle between the Polarising Voltage (-Vres) and the Residual Current

c = Relay Characteristic Angle (RCA) Setting (ISEF> Char Angle)

Vres = Residual Voltage

Ires = Residual Current

Vo = Zero Sequence Voltage

Io = Zero Sequence Current

The action of setting the PN> threshold to zero would effectively disable thewattmetric function and the relay would operate as a basic, sensitive directional earthfault element. However, if this is required, then the 'SEF' option can be selected fromthe 'Sens E/F Options' cell in the menu.

A further point to note is that when a power threshold other than zero is selected, aslight alteration is made to the angular boundaries of the directional characteristic.Rather than being ±90° from the RCA, they are made slightly narrower at ±85°.

cos /sin Characteristic

In some applications, the residual current on the healthy feeder can lie just inside theoperating boundary following a fault condition. The residual current for the faultedfeeder lies close to the operating boundary.

In this case, correct discrimination is achieved by means of an cos characteristic asthe faulted feeder will have a large active component of residual current, whilst thehealthy feeder will have a small value.

For insulated earth applications, it is common to use the sin characteristic.

2.13 Application considerations

Required relay current and voltage connections

Referring to the relevant application diagram for the P140 Relay, it should be appliedsuch that it’s direction for forward operation is looking down into the protected feeder(away from the busbar), with a 0° RCA setting.

As illustrated in the relay application diagram, it is usual for the earth fault element tobe driven from a core balance current transformer (CBCT). This eliminates thepossibility of spill current that may arise from slight mismatches between residuallyconnected line CT’s. It also enables a much lower CT ratio to be applied, therebyallowing the required protection sensitivity to be more easily achieved.

2.13.1 Calculation of required relay settings

As has been previously shown, for a fully compensated system, the residual currentdetected by the relay on the faulted feeder is equal to the coil current minus the sumof the charging currents flowing from the rest of the system. Further, as stated in theprevious section, the addition of the two healthy phase charging currents on eachfeeder gives a total charging current which has a magnitude of three times the steady



state per phase value. Therefore, for a fully compensated system, the total unbalancecurrent detected by the relay is equal to three times the per phase charging current ofthe faulted circuit. A typical relay setting may therefore be in the order of 30% of thisvalue, i.e. equal to the per phase charging current of the faulted circuit. Practicallythough, the required setting may well be determined on site, where system faults canbe applied and suitable settings can be adopted based upon practically obtainedresults.

Also, it should be noted that in most situations, the system will not be fullycompensated and consequently a small level of steady state fault current will beallowed to flow. The residual current seen by the relay on the faulted feeder maythus be a larger value, which further emphasises the fact that relay settings should bebased upon practical current levels, wherever possible.

The above also holds true regarding the required Relay Characteristic Angle (RCA)setting. As has been shown earlier, a nominal RCA setting of 0º is required.However, fine tuning of this setting will require to be carried out on site in order toobtain the optimum setting in accordance with the levels of coil and feederresistances present. The loading and performance of the CT will also have an effectin this regard. The effect of CT magnetising current will be to create phase lead ofcurrent. Whilst this would assist with operation of faulted feeder relays it wouldreduce the stability margin of healthy feeder relays. A compromise can therefore bereached through fine adjustment of the RCA. This is adjustable in 1° steps on theP341 relay.

2.13.2 Application of settings to the relay

All of the relevant settings can be found under the SENSITIVE E/F column within therelay menu. Within the Sens E/F Options cell, there are two possibilities for selectingwattmetric earth fault protection; either on it’s own or in conjunction with lowimpedance REF protection, which is described in section 2.10.

Note that the residual power setting, PN>, is scaled by the programmed CT and VTratios in the relay.

2.14 Restricted earth fault protection

Earth faults occurring on a transformer winding or terminal may be of limitedmagnitude, either due to the impedance present in the earth path or by thepercentage of transformer winding that is involved in the fault. In general,particularly as the size of the transformer increases, it becomes unacceptable to relyon time delayed protection to clear winding or terminal faults as this would lead to anincreased amount of damage to the transformer. A common requirement istherefore to provide instantaneous phase and earth fault protection. Applyingdifferential protection across the transformer may fulfill these requirements.However, an earth fault occurring on the LV winding, particularly if it is of a limitedlevel, may not be detected by the differential relay, as it is only measuring thecorresponding HV current. Therefore, instantaneous protection that is restricted tooperating for transformer earth faults only is applied. This is referred to as restricted,or balanced, earth fault protection (REF or BEF). The BEF terminology is usually usedwhen the protection is applied to a delta winding.

When applying differential protection such as REF, some technique must be employedto give the protection stability under external fault conditions, ensuring that relayoperation only occurs for faults on the transformer winding/connections. Twomethods are commonly used; bias or high impedance. The biasing techniqueoperates by measuring the level of through current flowing and altering the relaysensitivity accordingly. The high impedance technique ensures that the relay circuit isof sufficiently high impedance such that the differential voltage that may occur under



external fault conditions is less than that required to drive setting current through therelay.

The REF protection in the P341 should be applied as a high impedance differentialelement.

Note that the high impedance REF element of the relay shares the same CT input asthe SEF protection. Hence, only one of these elements may be selected.

A single DDB signal is available to indicate that the REF protection has tripped, 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.

All of the REF settings can be found at the bottom of the ‘SEF/REF Prot’n’ column andare shown below, in addition to the SEF setting options:


Min. Max.Step Size


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

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

Note that CT requirements for REF protection are included in section 6.

2.14.1 High impedance restricted earth fault protection

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



0$'

A

A 75

;( () )*();*

4 :+*;)& ('(;%'2;$);((&

E'( 4 $#;( &

4 ;((&(&2(()& (D*& *&%(*&)

4 *&)2*&%$$ 2('($');((&(&2((

$%)(($)*();*

4?3 16D'(?4

#*$**&%(*( $**,*$$);((& 3($*&%6

4 5

Figure 13: High impedance principle

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 13. An additional non linear, metrosil,may be required to limit the peak secondary circuit voltage during internal faultconditions.

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.

The necessary relay connections for high impedance REF are shown in Figure 14:

As can be seen from Figure 14, the high impedance protection uses an externaldifferential connection between the line CT’s and neutral CT. The SEF input is thenconnected to the differential circuit with a stabilising resistor in series. This leaves theEF1 input free to be connected for standby earth fault protection, if required, eitherfrom a residual connection of the line CTs or from a separate neutral CT.



7

7

.&,;

Figure 14: High impedance REF relay/CT connections

2.14.2 Setting guidelines for high impedance REF

From the ‘Sens E/F Options’ cell, ‘Hi Z REF’ must be selected to enable thisprotection. The only setting cell then visible is ‘IREF> Is1’, which may beprogrammed with the required differential current setting. This would typically be setto give a primary operating current of either 30% of the minimum earth fault level fora resistance earthed system or between 10 and 60% of rated current for a solidlyearthed system.

The primary operating current (Iop) will be a function of the current transformer ratio,the relay operating current (IREF> Is1), the number of current transformers inparallel with a relay element (n) and the magnetising current of each currenttransformer (Ie) at the stability voltage (Vs). This relationship can be expressed inthree ways:

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

e < 1

n x

op

CT ratio - REF > s1

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

[REF > s] <

op

CT ratio - ne

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

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



In order to achieve the required primary operating current with the currenttransformers that are used, a current setting (IREF> Is) must be selected for the highimpedance element, as detailed in expression (2.) 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(IREF> Is).

Vs

REF>s = F (RCT + 2RL)

REF > s

The above equation ssumes negligible relay burden.

The stabilising resisdeclared resistance.

USE OF “METROSIL”

Metrosils are used tunder internal fault transformers, relay a3000V peak.

The following formucould be produced internal fault will be prospective voltage tsaturation did not ointernal fault secondsecondary winding rpoint, the relay lead

Vp = 2

Vf = I‘f (R

where Vp = peak

Vk = curr

Vf = maxoccu

I‘f = max

RCT = curr

RL = max

RST = relay

When the value givebe applied. They ashunting the secondorder to prevent very

Metrosils are externacharacteristics follow

a

tor supplied is continuously adjustable up to its maximum

NON-LINEAR RESISTORS

o limit the peak voltage developed by the current transformersconditions, to a value below the insulation level of the currentnd interconnecting leads, which are normally able to withstand

lae should be used to estimate the peak transient voltage thatfor an internal fault. The peak voltage produced during ana function of the current transformer kneepoint voltage and thehat would be produced for an internal fault if current transformerccur. This prospective voltage will be a function of maximumary current, the current transformer ratio, the current transformeresistance, the current transformer lead resistance to the commonresistance and the stabilising resistor value.

2 Vk ( )Vf - Vk

CT + 2RL + RST)

voltage developed by the c.t. under internal fault conditions.

ent transformer knee-point voltage.

imum voltage that would be produced if c.t. saturation did notr.

imum internal secondary fault current.

ent transformer secondary winding resistance.

imum lead burden from current transformer to relay.

stabilising resistor.

n by the formulae is greater than 3000V peak, metrosils shouldre connected across the relay circuit and serve the purpose ofary current output of the current transformer from the relay in high secondary voltages.

lly mounted and take the form of annular discs. Their operating the expression:



V = CI0.25

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

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

I = instantaneous current through the non-linear resistor (“metrosil”) .

With a sinusoidal voltage applied across the metrosil, the RMS current would beapproximately 0.52x the peak current. This current value can be calculated asfollows:

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

2. At the maximum secondary current, the non-linear resistor (“metrosil”) shouldlimit the voltage to 1500V r.m.s. or 2120V peak for 0.25 second. At higherrelay voltage settings, it is not always possible to limit the fault voltage to 1500Vr.m.s., 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.

The Metrosil units normally recommended for use with 1Amp CT's are as shown inthe following table:

NominalCharacteristic Recommended Metrosil TypeRelay Voltage

SettingC Single Pole Relay Triple Pole Relay

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

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

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



Metrosil Units for Relays with a 5 Amp CT

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

1. At the relay voltage setting, the Metrosil current should be less than 100mA rms(the actual maximum 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 *, **, ***).

3. The Metrosil units normally recommended for use with 5 Amp CTs and singlepole relays are as shown in the following table:

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, contactAREVA T&D for detailed applications.

Note:1. The Metrosil units recommended for use with 5 Amp CTs can also be applied

for 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 be suppliedif required.

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

2.15 Residual over voltage/neutral voltage displacement protection

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 120º 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 voltage transformer having a “brokendelta” secondary connection. Hence, a relay that measures residual voltage can beused to offer earth fault protection on such a system. Note that this condition causesa rise in the neutral voltage with respect to earth that is commonly referred to as“neutral voltage displacement” or NVD. Alternatively, if the system is impedance or



distribution transformer earthed, the neutral displacement voltage can be measureddirectly in the earth path via a single phase VT.

This type of protection can be used to provide earth fault protection irrespective ofwhether the system is connected to earth or not, and irrespective of the form of earthconnection and earth fault current level.

Where embedded generation can be run in parallel with the external distributionsystem it is essential that this type of protection is provided at the interconnection withthe external system. This will ensure that if the connection with the main supplysystem is lost due to external switching events, some type of reliable earth faultprotection is provided to isolate the generator from an earth fault. Loss of connectionwith the external supply system may result in the loss of the earth connection, wherethis is provided at a distant transformer, and hence current based earth faultprotection may be unreliable.

A A

7/

7

7

7

7

* ;$<$%3($,*&6* ,& &;,& A A (*F

A A! A A!1 1 1

4 +A!

Figure 15a: Residual voltage, solidly earthed systems

The residual over voltage protection function of the P341 relay consists of two stageswith adjustable time delays.

Two stages are included for the element to account for applications that require bothalarm and trip stages, for example, an insulated system. It is common in such a casefor the system to have been designed to withstand the associated healthy phase overvoltages for a number of hours following an earth fault. In such applications, an



alarm 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.Alternatively, the residual voltage may be derived internally from the three phase toneutral voltage measurements. Where derived measurement is used the 3 phase toneutral voltage must be supplied from either a 5-limb or three single phase VTs.

7/

"

A

A A

7/

G

/ /

//

7/G G

/

/

7/

/

/

7/

/

/

/

/

A A! A A!1 1 1

4 +A!

A1

A1

Figure 15b: Residual voltage, resistance earthed systems

These types of VT design allow the passage of residual flux and consequently permitthe relay to derive the required residual voltage. In addition, the primary star point ofthe VT must be earthed. A three limb VT has no path for residual flux and istherefore unsuitable to supply the relay when residual voltage is required to bederived from the phase to neutral voltage measurement.

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



Each stage of protection can be blocked by energising the relevant DDB signal, viathe PSL (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. Max.Step Size

GROUP 1 RESIDUAL O/V NVD

VN Input Measured Measured, Derived

VN>1 Function DT Disabled, DT, IDMT

VN>1 Voltage Set

5 V(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, DT

VN>2 Voltage Set

5 V(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

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

t = K / (M-1)

where:

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

t = Operating Time in Seconds

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

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

Stage 1 may be selected as either ‘IDMT’ (inverse time operating characteristic), ‘DT’(definite time operating characteristic) or ‘Disabled’, within the “VN>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 TimeDelay”, “V>2 Time Delay”– for definite time) should be selected in accordance withnormal relay co-ordination procedures to ensure correct discrimination for systemfaults.

The Residual Over voltage protection can be set to operate from the voltagemeasured at the Vn input VT terminals or the residual voltage derived from thePhase-Neutral voltage inputs as selected by “VN Input”.



The voltage setting applied to the elements is dependent upon the magnitude ofresidual voltage that is expected to occur during the earth fault condition. This in turnis dependent upon the method of system earthing employed and may be calculatedby using the formulae previously given in Figs. 15a and 15b. It must also be ensuredthat the relay is set above any standing level of residual voltage that is present on thesystem.

Note that IDMT characteristics are selectable on the first stage of NVD in order thatelements located at various points on the system may be time graded with oneanother.

It must also be ensured that the voltage setting of the element is set above anystanding level of residual voltage that is present on the system. A typical setting forresidual over voltage protection is 5V.

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

2.16 Under voltage protection

Where the P341 relay is being used as interconnection protection the under voltageelement is used to prevent power being exported to external loads at a voltage belownormal allowable limits. Under voltage protection may also be used for back-upprotection for a machine where it may be difficult to provide adequate sensitivity withphase current measuring elements.

For an isolated generator, or isolated set of generators, a prolonged under voltagecondition could arise for a number of reasons. This could be due to failure ofautomatic voltage regulation (AVR) equipment or excessive load followingdisconnection from the main grid supply. Where there is a risk that a machine couldbecome disconnected from the main grid supply and energise external load it isessential that under voltage protection is used. The embedded generator must beprevented from energising external customers with voltage below the statutory limitsimposed on the electricity supply authorities.

A two stage under voltage element is provided. The element can be set to operatefrom phase-phase or phase-neutral voltages. Each stage has an independent timedelay that can be set to zero for instantaneous operation. Selectable, fixed Logic isincluded within the relay to allow the operation of the element to be inhibited duringperiods when the machine is isolated from the external system.

Each stage of under voltage protection can be blocked by energising the relevantDDB signal via the PSL, (DDB 370, DDB 371). DDB signals are also available toindicate a 3 phase and per phase start and trip, (Starts: DDB 579-586, Trips: DDB453-460). 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.

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



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


Min. Max.Step Size

GROUP 1 VOLT PROTECTION

UNDERVOLTAGE Sub Heading

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

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

V<1 Function DT Disabled, DT, IDMT

V<1 Voltage Set

80 V(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

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)

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

V<1 Poledead Inh Enabled Disabled, Enabled


t = K / (1-M)

where:

K = Time Multiplier Setting (V>1 TMS)


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

2.16.1 Setting guidelines for under voltage protection

Stage 1 may be selected as either ‘IDMT’ (for inverse time delayed operation), ‘DT’(for definite time delayed operation) or ‘Disabled’, within the “V<1 Function” cell.Stage 2 is definite time only and is Enabled/Disabled in the “V<2 Status” cell. Thetime delay. (“V<1 TMS” - for IDMT curve: “V<1 Time Delay”, “V<2 Time Delay” –for definite time) should be adjusted accordingly.

The under voltage protection can be set to operate from Phase-Phase or Phase-Neutral voltage as selected by “V< Measur’t Mode”. Single or three 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.

The under voltage threshold for each stage is set in the “V>1 Voltage Set” and “V>2Voltage Set” cells.



Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (e.g. requirements ofG59 in the UK), the local electricity supply authority will advise settings for theelement. The settings must prevent the generator from exporting power to the systemwith voltage outside of the statutory limits imposed on the supply authority. For thismode of operation the element must be set to operate from phase to neutral voltage,which will provide an additional degree of earth fault protection.

The operating characteristic would normally be set to definite time, set “V<1Function” to ‘DT’. The time delay, “V<1 Time Delay”, should be set to co-ordinatewith downstream. Additionally, the delay should be long enough to preventunwanted operation of the under voltage protection for transient voltage dips. Thesemay occur during clearance of faults further into the power system or by starting oflocal machines. The required time delay would typically be in excess of 3s – 5s.

As previously stated, local regulations for operating a generator in parallel with theexternal electricity supply may dictate the settings used for the under voltageprotection. For example in the UK the protection should be set to measure phase toneutral voltage and trip at 90% of nominal voltage in a time of less than 0.5s.

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

To prevent operation of any under voltage stage during normal shutdown of thegenerator “poledead” logic is included in the relay. This is facilitated by selecting “VPoledead nh” 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 under voltage element will beinhibited.

2.17 Over voltage protection

An over voltage condition could arise when a generator is running but not connectedto a power system, or where a generator is providing power to an islanded powersystem. Such an over voltage could arise in the event of a fault with automaticvoltage regulating equipment or if the voltage regulator is set for manual control andan operator error is made. Over voltage protection should be set to prevent possibledamage to generator insulation, prolonged over-fluxing of the generating plant, ordamage to power system loads.

When a generator is synchronised to a power system with other sources, an overvoltage could arise if the generator is lightly loaded supplying a high level of powersystem capacitive charging current. An over voltage condition might also be possiblefollowing a system separation, where a generator might experience full-load rejectionwhilst still being connected to part of the original power system. The automaticvoltage regulating equipment and machine governor should quickly respond tocorrect the over voltage condition in these cases. However, over voltage protection isadvisable to cater for a possible failure of the voltage regulator or for the regulatorhaving been set to manual control.

A two stage over voltage element is provided. The element can be set to operatefrom phase-phase or phase-neutral voltages. Each stage has an independent timedelay which can be set to zero for instantaneous operation.

Each stage of over voltage protection can be blocked by energising the relevant DDBsignal via the PSL, (DDB 372, DDB 373). 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 operationthen the DDB signals V>1/2 Start/Trip A/AB, V>1/2 Start/TripB/BC, V>1/2 Start/Trip C/CA refer to V>1/2 Start/Trip AB andV>1/2 Start/Trip BC and V>1/2 Start/Trip CA. If set for phase-neutral then the DDB signals V>1/2 Start/Trip A/AB, V>1/2Start/Trip B/BC, V>1/2 Start/Trip C/CA refer to V>1/2Start/Trip A and V>1/2 Start/Trip B and V>1/2 Start/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. Max.Step Size

GROUP VOLT 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

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”)

2.17.1 Setting guidelines for over voltage protection

Stage 1 may be selected as either ‘IDMT’ (for inverse time delayed operation), ‘DT’(for definite time delayed operation) or ‘Disabled’, within the “V>1 Function” cell.Stage 2 has a definite time delayed characteristic and is Enabled/Disabled in the“V>2 Status” cell. The time delay. (“V>1 TMS” - for IDMT curve; “V>1 TimeDelay”, “V>2 Time Delay” - for definite time) should be selected accordingly.



The over voltage protection can be set to operate from Phase-Phase or Phase-Neutralvoltage as selected by “V> Measur’t Mode” cell. Single or three phase operation canbe selected in “V> Operate Mode” cell. 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 above the setting.

Generators can typically withstand a 5% over voltage condition continuously. Thewithstand times for higher over voltages 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 over voltage 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 over voltage 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.

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>2Time Delay”, should be set to 0s.

Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (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. For examplein the UK the protection should be set to measure phase to neutral voltage and trip at110% of nominal voltage in a time of less than 0.5s.

If phase to neutral operation is selected, the element may operate during earth faults,where the phase-neutral voltage can rise significantly.

2.18 Under frequency protection

Under frequency 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.Automatic load shedding could compensate for such events. In this case, underfrequency operation would be a transient condition. This characteristic makes underfrequency protection a simple form of “Loss of Mains” protection on system where it isexpected that the islanded load attached to the machine when the grid connectionfails exceeds the generator capacity. In the event of the load shedding beingunsuccessful, the generators should be provided with backup under frequencyprotection. Where the P341 relay is being used as interconnection protection theunder frequency element is also used to prevent power being exported to externalloads at a frequency below normal allowable limits.

Four independent definite time-delayed stages of under frequency protection areoffered. Two additional over frequency stages can also be reconfigured as underfrequency protection by reprogramming the Programmable Scheme Logic. As well asbeing able to initiate generator tripping, the under frequency protection can also bearranged to initiate local load-shedding, where appropriate.



Energising the relevant DDB signal, via the PSL (DDB 374-377), can block each stageof underfrequency protection. DDB signals are also available to indicate start andtrip of each stage, (Starts: DDB 622-625, Trips: DDB 469-472). The state of the DDBsignals can be programmed to be viewed in the “Monitor Bit x” cells of the“COMMISSION TESTS” column in the relay.



Min. Max.Step Size

GROUP 1 FREQ 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 s 100 s 0.01 s


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






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


F< Function Link 1111

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

2.18.1 Setting guidelines for under frequency protection

Each stage of under frequency protection may be selected as ‘Enabled’ or ‘Disabled’,within the “F<x Status” cells. The frequency pickup setting, “F<x Setting”, and 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 or system are not infringed. Typically, a 10% under frequencycondition should be continuously sustainable by the machine however systemconsiderations may mean that settings much closer to the nominal frequency arespecified.

For industrial generation schemes, where generation and loads may be undercommon control/ownership, the P341 under frequency protection function could beused to initiate local system load-shedding. Four stage under frequency/loadshedding can be provided. The final stage of under frequency protection should beused to trip the generator.

Where separate load shedding equipment is provided, the under frequency 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.



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To prevent operation of any under frequency 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 under frequency 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 over fluxing 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 ofG.59 in the UK), the local electricity supply authority may advise settings for theelement. The settings must prevent the generator from exporting power to the systemwith frequency outside of the statutory limits imposed on the supply authority. Forexample, in the UK the under frequency protection should be set to 47Hz with a triptime of less than 0.5s.



2.19 Over frequency protection function

Over frequency running of a generator arises when the mechanical power input tothe alternator is in excess of the electrical load and mechanical losses. The mostcommon occurrence of over frequency is after substantial loss of load. When a risein running speed occurs, the governor should quickly respond to reduce themechanical input power, so that normal running speed is quickly regained. Overfrequency protection may be required as a backup protection function to cater forgovernor or throttle control failure following loss of load or during unsynchronised orislanded running.

Moderate over frequency operation of a generator is not as potentially threatening tothe generator and other electrical plant as under frequency running. Action can betaken at the generating plant to correct the situation without necessarily shutting downthe generator. However, where the P341 relay is being used as interconnectionprotection the under frequency element will prevent power being exported to externalloads at a frequency higher than normal allowable limits.

Two independent time-delayed stages of over frequency protection are provided.

Each stage of protection can be blocked by energising the relevant DDB signal 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). The state of the DDBsignals can be programmed to be viewed in the “Monitor Bit x” cells of the“COMMISSION TESTS” column in the relay.



Min. Max.Step Size

GROUP 1 FREQ PROTECTION

OVER FREQUENCY Sub Heading

F>1 Status Enabled Disabled, Enabled


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

F>2 Status Enabled Disabled, Enabled


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

2.19.1 Setting guidelines for over frequency protection

Each stage of over frequency protection may be selected as Enabled or Disabled,within the “F>x Status” cells. The frequency pickup setting, “F>x Setting”, and timedelays, “F>x Time Delay”, for each stage should be selected accordingly.

The P341 over frequency settings should be selected to co-ordinate with normal,transient over frequency excursions following full-load rejection. The generatormanufacturer should declare the expected transient over frequency behaviour, whichshould comply with international governor response standards. A typical overfrequency setting would be 10% above nominal.

Where the relay is used to provide the protection required for connecting thegenerator in parallel with the local electricity supply system (e.g. requirements ofG.59 in the UK), the local electricity supply authority may advise settings for theelement. The settings must prevent the generator from exporting power to the systemwith frequency outside of the statutory limits imposed on the supply authority. For



example in the UK over frequency protection should be set to 50.5Hz with a trip timeof less than 0.5s.

2.20 Thermal overload protection

2.20.1 Introduction

Thermal overload protection can be used to prevent electrical plant from operating attemperatures in excess of the designed maximum withstand. Prolonged overloadingcauses excessive heating, which may result in premature ageing of the insulation, orin extreme cases, insulation failure.

The P341 relay incorporates a current based thermal replica, using positive andnegative sequence currents to model heating and cooling of the protected plant. Theelement can be set with both alarm and trip stages. The P341 thermal protection hasbeen designed specifically for electrical machines but could also be used for otheritems of plant such as transformers or cables.

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 10C 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/)

Where

Tmax = final steady state temperature

= heating time constant

This assumes a thermal equilibrium in the form:

Heat developed = Heat stored + Heat dissipated

Temperature rise is proportional to the current squared:

T = K R2 (1-e-t/)

T = Tmax = K R2 if t =

Where

R = the continuous current level which would produce a temperature Tmax in thegenerator

For an overload current of ‘’ the temperature is given by:

T = K2 (1-e-t/)



For a machine not to exceed Tmax, the rated temperature, then the time ‘t’ for whichthe machine can withstand the current ‘’ can be shown to be given by:

Tmax = K R2 = K2 (1-e-t/)

t = . Log e (1/(1-( R /)2))

An overload protection element should therefore satisfy the above relationship. Thevalue of R 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.

2.20.2 Thermal replica

The P341 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, eq, which is supplied to the replicacircuit. The heating effect in the thermal replica is produced by eq

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 sequencecurrents 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 22t specifically for thermal protection of therotor.



The equivalent current for operation of the overload protection is in accordance withthe following expression:

eq = (12 + M22)

Where

1 = positive sequence current

2 = negative sequence current

M = a user settable constant proportional to the thermal capacity of the machine

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 P341 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 = loge (eq2 – P2)/(eq

2 – (Thermal >)2

where:

t = time to trip, following application of the overload current,

= heating time constant of the protected plant

eq = equivalent current

Thermal > = relay setting current

P = 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”.

The thermal time constant characteristic may be rewritten as:

exp(–t/) = ( – 1) / ( – p)

where:

= eq2/(Thermal >)2

and

p = p2/ (Thermal >)2

where is the thermal state and is p the prefault thermal state.

Note, that the thermal model does not compensate for the effects of ambienttemperature change.



t = . Loge (K2-A2/(K2-1))

Where

K = eq/Thermal >

A = P /Thermal >

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

Thermal Enabled Disabled, Enabled

Thermal > 1.2 n A 0.5 n A 2.5 n A 0.01 n 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


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.

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 rotorresistance at rated speed. When an exact setting can not be calculated a setting of 3should be used. This is a typical setting and will suffice for the majority ofapplications for machines. 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. The M factor should be set to 0 if the thermal replicaprotection is not used to protect machines e.g. for cables or transformers. Note, theextra heating caused by unbalanced phase currents is not accounted for in thethermal limit curves supplied by the generator manufacturer as these curves assumepositive sequence currents only that come from a perfectly balanced supply andgenerator design, so the default setting is 0.

2.21 Circuit breaker fail protection (CBF)

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 backtrip upstream circuit breakers to ensure that thefault is isolated correctly. CBF operation can also reset all start output contacts,ensuring that any blocks asserted on upstream protection are removed.

2.21.1 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.

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.



2.21.2 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 (I<) 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, I< only gives a reliable reset method if the protected circuitwould always have load current flowing. Detecting drop-off of the initiatingprotection element might be a more reliable method.

Where non-current operated protection, such as under/overvoltage orunder/overfrequency, derives measurements from a busbar connected voltagetransformer. Again using I< would rely upon the feeder normally being loaded.Also, tripping the circuit breaker may not remove the initiating condition 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:

Initiation (Menu Selectable) CB Fail Timer Reset Mechnaism

Current based protection

The resetting mechanism is fixed(e.g. 50/51/46/21/87..)[IA< operates] &[IB< operates] &[IC< operates] &[IN< operates]

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

Non-current based protection(e.g. 27/59/81/32L..)

Three options are available. The user canselect from the following options.[All I< and IN< elements operate][Protection element reset] AND[All I< and IN< elements operate]CB open (all 3 poles) AND [All I< and IN<elements operate]



External protection

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

The selection in the relay menu is grouped as follows:


Min. Max.Step Size

NEG SEQ O/C GROUP 1

BREAKER FAIL Sub-Heading

CB Fail 1 Status Enabled Enabled, Disabled

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

CB Fail 2 Status Disabled Enabled, Disabled

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

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

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

UNDERCURRENT Sub-Heading

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

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

ISEF< Current 0.02In 0.001In 0.8In 0.0005In

BLOCKED O/C Sub-Heading

Remove I> Disabled Enabled, Disabled

Remove IN> Disabled Enabled, Disabled

The "Remove I>" and "Remove IN>" settings are used to remove starts issued fromthe overcurrent and earth elements respectively following a breaker fail time out(DDB 628 I> Block Start, DDB 629 IN/SEF> Blk Start). The start is removed whenthe cell is set to Enabled. This can be used to remove a blocking signal from anupstream relay to back trip and clear the fault.

2.22 Typical settings

2.22.1 Breaker fail timer settings

Typical timer settings to use are as follows:

CB Fail Reset Mechanism tBF Time Delay Typical Delay for2º Cycle 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 + safetymargin

50 + 10 + 50 = 110 ms



CB Fail Reset Mechanism tBF Time Delay Typical Delay for2º Cycle Circuit Breaker

Undercurrent elementsCB interrupting time +undercurrent element(max.) + operating 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 10-15ms must be added toallow for trip relay operation.

2.22.2 Breaker fail undercurrent settings

The phase undercurrent settings (I<) must be set less than load current, to ensurethat I< operation indicates that the circuit breaker pole is open. A typical setting foroverhead line or cable circuits is 20% In, with 5% In common for generator circuitbreaker CBF.

The sensitive earth fault protection (SEF) and standard earth fault undercurrentelements must be set less than the respective trip setting, typically as follows:

ISEF< = (ISEF> trip) / 2

IN< = (IN> trip) / 2



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3. OTHER PROTECTION CONSIDERATIONS

3.1 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 P341 which are then arranged to be blocked by startcontacts from the relays protecting the outgoing feeders. The fast acting element isthus allowed to trip for a fault condition on the busbar but is stable for external feederfaults by means of the blocking signal. This type of scheme therefore provides muchreduced fault clearance times for busbar faults than would be the case withconventional time graded overcurrent protection. The availability of multipleovercurrent and earth fault stages means that back-up time graded overcurrentprotection is also provided. This is shown in Figures 18a and 18b.



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Figure 18b: Simple busbar blocking scheme (single incomer)

The P140/P341 relays have start outputs available from each stage of each of theovercurrent and earth fault elements, including sensitive earth fault. These startsignals may then be routed to output contacts by programming accordingly. Eachstage is also capable of being blocked by being programmed to the relevant opto-isolated input.

Note that the P341 relays provide a 50V field supply for powering the opto-inputs.Hence, in the unlikely event of the failure 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 the



substation. 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.

4. APPLICATION OF NON-PROTECTION FUNCTIONS

4.1 Voltage transformer supervision (VTS)

The voltage transformer supervision (VTS) feature is used to detect failure of the acvoltage inputs to the relay. This may be caused by internal voltage 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:

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 (or 40V on a380/480V rated relay), and I2 = 0.05 to 0.5In settable (defaulted to 0.05In).

4.1.1 Loss of all three phase voltages under load conditions

Under the loss of all three phase voltages to the relay, there will be no negativephase sequence quantities present to operate the VTS function. However, 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 (40V on380/480V relays) and pickup at 30V (120V on 380/480V relays).

The sensitivity of the superimposed current elements is fixed at 0.1In.



4.1.2 Absence of three phase voltages upon line energisation

If a VT were inadvertently left isolated prior to line energisation, 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 I> 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.

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 I> Inhibit overcurrent element will not be pickedup.

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Figure 19: VTS logic

Required to drive the VTS logic are a number of dedicated level detectors as follows:

A>, B>, C>, 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.



2>, 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.

IA>, B>, C>, 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.

4.1.2.1 Inputs

Signal Name Description

A>, B>, C> Phase current levels (Fourier Magnitudes)

2> 2 level (Fourier Magnitude)

A, B, CPhase 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



4.1.2.2 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

4.1.3 Menu settings

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


Min. Max.Step Size

SUPERVISION

VTS Status Blocking Blocking, Indication

VTS Reset Mode Manual Manual, Auto

VTS Time Delay 5 s 1 s 10 s 0.1 s

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

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

The relay may respond as follows, on operation of any VTS element:

VTS set to provide alarm indication only (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 overcurrent, earth fault and SEF elements tonon-directional protection (available when VTS set to Blocking mode only). Thesesettings are found in the Function Links cell of the relevant protection elementcolumns in the menu.

Time delayed protection elements (Directional SEF, Directional Earth Fault, Power,Sensitive Power) are blocked after the VTS Time Delay on operation of the VTS SlowBlock. Fast operating protection elements (Neutral Voltage Displacement, DirectionalOvercurrent, Undervoltage) are blocked on operation of the VTS Fast Block.

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

Once the signal has latched then two methods of resetting are available. The first ismanually via the front panel interface (or remote communications) provided the VTScondition has been removed and secondly, when in ‘Auto’ mode, by the restorationof the 3 phase voltages 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 forcompatibility with various utilities current practices. Energising an opto-isolated inputassigned to “MCB Open” on the relay will therefore provide the necessary block.

Where directional overcurrent elements are converted to non-directional protectionon VTS operation, it must be ensured that the current pick-up setting of theseelements is higher than full load current.

4.2 Current transformer 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.

4.2.1 The CT supervision feature

The CT supervision feature operates on detection of derived residual current, in theabsence of corresponding derived residual voltage that would normally accompanyit.

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 VT is of five limb construction, or comprises three single phase units, and has theprimary star point earthed. A derived residual voltage or a measured residualvoltage 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 are always blocked on operation of the CT supervision element;other protections can be selectively blocked by customising the PSL, integrating DDB738: CTS Block with the protection function logic.

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The following table shows the relay menu for the CT Supervision element, includingthe available setting ranges and factory defaults:




Min. Max.Step Size

GROUP 1 SUPERVISION

CT Supervision Sub Heading

CTS Status Disabled Enabled, Disabled N/A

CTS VN< Inhibit 1

0.5/2VFor

110/440Vrespectively

22/88VFor


0.5/2VFor


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

CTS Time Delay 5 0s 10s 1s

4.2.2 Setting the CT supervision element

The residual voltage setting, "CTS Vn< Inhibit" and the residual current setting,"CTS In> set", should be set to avoid unwanted operation during healthy systemconditions. For example "CTS Vn< Inhibit" should be set to 120% of the maximumsteady state residual voltage. The "CTS In> set" will typically be set 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 protection elements being blocked during faultconditions.

4.3 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.

4.3.1 Circuit breaker state monitoring features

MiCOM relays can be set to monitor normally open (52a) and normally closed (52b)auxiliary contacts of the circuit breaker. Under healthy conditions, 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 conditionswould apply:

Auxiliary contacts/wiring defective.

Circuit Breaker (CB) is defective.

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 via theprogrammable 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 21.

Auxiliary Contact Position CB State Detected Action

52A 52B

Open Closed Breaker open Circuit breaker healthy

Closed Open Breaker closed Circuit breaker healthy

Closed Closed CB failureAlarm raised if thecondition persists forgreater than 5s

Open Open State unknownAlarm raised if thecondition persists forgreater than 5s



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4.4 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 (<)thresholds have the following, fixed, pickup and drop-off levels:

Settings Range Step Size

V< Pick-up and drop off10V and 30V (100/120V)

40V and 120V (380/480V)Fixed

< Pick-up and drop off 0.05 n and 0.055n 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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4.5 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.

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.



4.5.1 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 A Broken 0 0 25000n^ 1

Total B Broken 0 0 25000n^ 1

Total C Broken 0 0 25000n^ 1n^

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. Max.Step Size

CB MONITORSETUP

Broken ^ 2 1 2 0.1

^ Maintenance Alarm disabled Alarm disabled, Alarm enabled

^ Maintenance 1000n^ 1n^ 25000n^ 1n^

^ Lockout Alarm disabled Alarm disabled, Alarm enabled

^ Lockout 2000n^ 1n^ 25000n^ 1n^

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

Fault Freq Lock Alarm disabled Alarm disabled, Alarm enabled

Fault Freq Count 10 1 9999 1




Min. Max.Step Size

CB MONITORSETUP

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.


4.5.2.1 Setting the ^ 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. The ^ 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 of 2t. This is where ‘’ 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 ^’ = 2.

For other types of circuit breaker, especially those operating on higher voltagesystems, practical evidence suggests that the value of ‘Broken ^’ = 2 may beinappropriate. In such applications ‘Broken ^’ 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 ^’ 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.

4.5.2.2 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.



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.

4.5.2.3 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.

4.5.2.4 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.

4.6 Circuit breaker control

The relay includes the following options for control of a single circuit breaker:

Local tripping and closing, via the relay menu.

Local tripping and closing, via relay opto-isolated inputs.

Remote tripping and closing, using the relay communications.

It is recommended that separate relay output contacts are allocated for remote circuitbreaker control and protection tripping. This enables the control outputs to beselected via a local/remote selector switch as shown in Figure 23. Where this featureis not required the same output contact(s) can be used for both protection and remotetripping.



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


Min. Max.Step Size

CB CONTROL

CB control by DisabledDisabled, Local, Remote, Local+Remote, Opto,Opto+Local, Opto+Remote, Opto+Rem+Local

Close Pulse Time 0.5 s 0.01 s 10 s 0.01 s

Trip Pulse Time 0.5 s 0.01 s 5 s 0.01 s

Man Close Delay 10 s 0.01 s 600 s 0.01 s

CB Healthy Time 5 s 0.01 s 9999 s 0.01 s

Lockout Reset No No, Yes

Reset Lockout By CB Close User Interface, CB Close

Man Close RstDly 5 s 0.01 s 600 s 0.01 s

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

A manual trip will be permitted provided that the circuit breaker is initially closed.Likewise, a close command can only be issued if the CB is initially open. To confirmthese states it will be necessary to use the breaker 52A and/or 52B contacts (thedifferent selection options are given from the ‘CB Status Input’ cell above). If no CBauxiliary contacts are available then this cell should be set to None. Under thesecircumstances no CB control (manual or auto) will be possible.



Once a CB Close command is initiated the output contact can be set to operatefollowing a user defined time delay (‘Man Close Delay’). This would give personneltime to move away from the circuit breaker following the close command. This timedelay will apply to all manual CB Close commands.

The length of the trip or close control pulse can be set via the ‘Trip Pulse Time’ and‘Close Pulse Time’ settings respectively. These should be set long enough to ensurethe breaker has completed its open or close cycle before the pulse has elapsed.

Note that the manual close commands are found in the SYSTEM DATAcolumn of the menu.

If an attempt to close the breaker is being made, and a protection trip signal isgenerated, the protection trip command overrides the close command.

There is also a CB Healthy check if required. This facility accepts an input to one ofthe relays opto-isolators to indicate that the breaker is capable of closing (circuitbreaker energy for example). A user settable time delay is included "CB HealthyTime" for manual closure with this check. If the CB does not indicate a healthycondition in this time period following a close command then the relay will lockoutand alarm.

If the CB fails to respond to the control command (indicated by no change in the stateof CB Status inputs) a "CB Failed to Trip" or "CB Failed to Close" alarm will begenerated after the relevant trip or close pulses have expired. These alarms can beviewed on the relay LCD display, remotely via the relay communications, or can beassigned to operate output contacts for annunciation using the relays programmablescheme logic (PSL).

The "Lockout Reset" and "Reset Lockout by" setting cells in the menu are applicable toCB Lockouts associated with manual circuit breaker closure, CB Condition monitoring(Number of circuit breaker operations, for example).

The lockout alarms can be reset using the ‘Lockout Reset’ command or the bypressing the Clear key after reading the alarm or by closing the CB if the ‘ResetLockout By’ setting is set to ‘CB Close’ or via an opto input using DDB 175, ResetLockout. If lockout is reset by closing the CB then there is a time delay after closingthe CB to resetting of lockout, the Man Close RstDly.

4.7 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.



4.7.1 TCS scheme 1

4.7.1.1 Scheme description

P2228ENa

Optional

Figure 24: 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.

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.



4.7.2 Scheme 1 PSL

Figure 25 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.

:3,"",(:-8(

;

?A38

%,8(8(4#

/(>$(

B)4#'

(?$>

Figure 25: PSL for TCS schemes 1 and 3

4.7.3 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.

4.7.4 Scheme 2 PSL

The PSL for this scheme (Figure 27) 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.

,(:-8(

,(:-8(

%8*$ !

:3,""

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/(>$(

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;

B)4#'

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Figure 27: PSL for TCS scheme 2

4.7.5 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.

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.

4.7.6 Scheme 3 PSL

The PSL for scheme 3 is identical to that of scheme 1 (see Figure 25).

4.8 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 shown thefollowing table:



VIEW RECORDS

LCD Reference Description

Select EventSetting range from 0 to 249. This selects the requiredevent record from the possible 250 that may be stored. Avalue of 0 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 or integer representative of theEvent (refer to following 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.

Select ReportSetting range from 0 to 4. This selects the requiredmaintenance report from the possible 5 that may be stored.A value of 0 corresponds to the latest report and so on.

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

Report 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.

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 the SCADACommunications section, where the procedure is fully explained.

Note that a full list of all the event types and the meaning of their values is given inAppendix A.

4.8.1 Types of event

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

4.8.1.1 Change of state of opto-isolated inputs

If one or more of the opto (logic) inputs has changed state since the last time 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.

4.8.1.2 Change of state of one or more output relay contacts

If one or more of the output relay contacts has changed state since the last 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:

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.

4.8.1.3 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

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

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

User Alarm (Self Reset) User Alarm 1, 2 ON/OFF Bit position 29, 30 in 32 bitfield

User Alarm (Manual Reset) User Alarm 3 ON/OFF Bit position 31 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.

4.8.1.4 Protection element starts and trips

Any operation of protection elements, (either a start or a trip condition), will belogged as an event record, consisting of a text string indicating the 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.

4.8.1.5 General events

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

Nature of Event Displayed Text in Event Record Displayed Value

Level 1 password modified,either from user interface,front or rear port

PW1 edited UI, F or R 6, 11, 16respectively

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

4.8.1.6 Fault records

Each time a fault record is generated, an event is also created. The event simplystates that a fault record was generated, with a corresponding time stamp.

Note that viewing of the actual fault record is carried out in the "Select Fault’" cellfurther down the "VIEW RECORDS" column, which is selectable from up to 5 records.These records consist of fault flags, fault location, fault measurements etc. Also notethat the time stamp given in the fault record itself will be more accurate than thecorresponding stamp given in the event record as the event is logged some time afterthe actual fault record 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 faultrecorder does not stop recording until any start or relay 3 (protection trip) resets inorder to record 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.

4.8.1.7 Maintenance reports

Internal failures detected by the self monitoring circuitry, such as watchdog failure,field voltage failure etc. are logged into a maintenance report. The MaintenanceReport holds up to 5 such ‘events’ and is accessed from the "Select Report" cell 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 Appendix A.



Each time a Maintenance Report is generated, an event is also created. The eventsimply states that a report was generated, with a corresponding time stamp.

4.8.1.8 Setting changes

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

Type of setting change Displayed Text in Event Record 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 ratiosettings etc, which are not duplicated within the four setting groups. Whenany of these settings are changed, the event record is createdsimultaneously. However, changes to protection or disturbance recordersettings will only generate an event once the settings have been confirmed atthe ‘setting trap’.

4.8.2 Resetting of event/fault records

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

4.8.3 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 03 November 1998 15:32:49 GMT I>1 Start ON 2147483881

ALSTOM : MiCOM

Model Number: P141

Address: 001 Column: 00 Row: 23

Event Type: Protection operation

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

ALSTOM : MiCOM

Model Number: P141


Event Type: Fault record

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

ALSTOM : MiCOM

Model Number: P141


Event Type: Logic input changed state



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

ALSTOM : MiCOM

Model Number: P141


Event Type: Relay output changed state

As can be seen, the first line gives the description and time stamp for the event, whilstthe additional information that is displayed below may be collapsed via the +/–symbol.

For further information regarding events and their specific meaning, refer toAppendix A.

4.8.4 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.



For further information regarding events and their specific meaning, refer toAppendix A.

4.9 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 MODBUSand DNP3.0 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 analog data channels and thirty-two digitaldata channels. Note that the relevant CT and VT ratios for the analog channels arealso extracted to enable scaling to primary quantities). Note that if a CT ratio is setless than unity, the relay will choose a scaling factor of zero for the appropriatechannel.

The "DISTURBANCE RECORDER" menu column is shown in the following table:


Min. Max.Step Size

DISTURB RECORDER

Duration 1.5 s 0.1 s 10.5 s 0.01 s

Trigger Position 33.3% 0 100% 0.1%

Trigger Mode Single Single or Extended

Analog Channel 1 VANVAN, VBN, VCN, VCHECKSYNC, IA, IB, IC,

IN, IN SEF

Analog Channel 2 VBN As above

Analog Channel 3 VCN As above

Analog Channel 4 VN As above

Analog Channel 5 IA As above

Analog Channel 6 IB As above

Analog Channel 7 IC As above

Analog Channel 8 IN SEF As above

Digital Inputs 1 to 32Relays 1 to 7/14

andOpto’s 1 to 8/16

Any of 7 or 14 O/P Contacts orAny of 8 or 16 Opto Inputs or

Internal Digital Signals

Inputs 1 to 32 Trigger

No Triggerexcept DedicatedTrip Relay O/P’swhich are set to

Trigger L/H

No Trigger, Trigger L/H, Trigger H/L

Note: The available analog and digital signals will differ between relay types andmodels and so the individual courier database in the SCADACommunications section should be referred to when determining defaultsettings 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 analog channels is selectable from theavailable analog inputs to the relay. The digital channels may be mapped to any ofthe opto isolated inputs or output contacts, in addition to a number of internal relaydigital signals, such as protection starts, LED’s etc. The complete list of these signalsmay be found by viewing the available settings in the relay menu or via a setting filein MiCOM S1. Any of the digital channels may be selected to trigger the disturbancerecorder on either a low to high or a high to low transition, via the "Input Trigger" cell.The default trigger settings are that any dedicated trip 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 the SCADA Communications section.

4.10 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

4.10.1 Measured voltages and currents

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

4.10.2 Sequence voltages and currents

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

4.10.3 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

0 (Default)

Export PowerImport PowerLagging VarsLeading VArs

+–+–

1


–++

–

2


+––+

3


–+–+

Table 2: Measurement mode

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.

4.10.4 Rms. voltages and currents

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

4.10.5 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.

4.10.5.1 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.

4.10.5.2 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.



4.10.5.3 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.

4.10.6 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/IA/IB/ICMeasurement 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.

4.10.6.1 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.

4.10.6.2 Local values

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

4.10.6.3 Remote values

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

4.10.6.4 Measurement ref

Using this setting the phase reference for all angular measurements by the relay canbe selected.

4.10.6.5 Measurement mode

This setting is used to control the signing of the real and reactive power quantities;the signing convention used is defined in Table 2, section 4.10.3.

4.10.6.6 Fixed demand period

This setting defines the length of the fixed demand window.



4.10.6.7 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.

4.11 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 Scheme Logic.Each is independent per group - not shared as common. The settings aregenerated in the Settings and Records application within MiCOM S1, or canbe applied directly from the relay front panel menu. The programmablescheme logic can only be set using the PSL Editor application within MiCOMS1, generating files with extension ".psl". It is essential that where theinstallation needs application-specific PSL, that the appropriate .psl file isdownloaded (sent) to the relay, for each and every setting group that will beused. If the user fails to download the required .psl file to any setting groupthat may be brought into service, then factory default PSL will still beresident. This may have severe operational and safety consequences.

4.12 Control inputs

Menu Text DefaultSetting Setting Range Step Size

CONTROL INPUTS

Ctrl I/P Status 00000000000000000000000000000000

Control Input 1 No Operation No Operation, Set, Reset

Control Input 2 to 32 No Operation No Operation, Set, Reset

The Control Input commands can be found in the ‘Control Input’ menu. In the ‘Ctrl/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.



4.13 VT connections

4.13.1 Open delta (vee connected) VT's

The P341 relay can be used with vee connected VTs by connecting the VT secondariesto C19, C20 and C21 input terminals, with the C22 input left unconnected (seeFigures 2 and 17 in Appendix B).

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 protection,directional earth fault protection and CT supervision should be disabled unless theresidual voltage is measured directly from the secondary of the earthing transformeror from a broken delta VT winding on a 5 limb VT.

The under and over voltage protection can be set as phase-to-phase measurementwith vee connected VTs. The directional overcurrent protection uses phase-phasevoltages anyway, therefore the accuracy should not be affected. The protectionfunctions which use phase-neutral voltages are the power, sensitive power protectionand voltage vector shift protection; all are for detecting abnormal generatoroperation under 3-phase balanced conditions, therefore the 'neutral' point, although'floating' will be approximately at the centre of the three phase voltage vectors.

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 thephase 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 10k 1% (6W) resistors are used for the 110V (Vn) rated relay,assuming the VT can supply this burden.

4.13.2 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.

4.14 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.



7&$ 7&(

(*,

"7

.7

('37& (*,63& 63%*).&,;6

."@

= !

J

Figure 29: Trip LED logic diagram

5. CT/VT REQUIREMENTS

The CT requirements for P341 are as shown below.

The current transformer requirements are based on a maximum prospective faultcurrent of 50 times the relay rated current (In) and the relay having an instantaneoussetting of 25 times rated current (In). The current transformer requirements aredesigned to provide operation of all protection elements.

Where the criteria for a specific application are in excess of those detailed above, orthe actual lead resistance exceeds the limiting value quoted, the CT requirements mayneed to be increased according to the formulae in the following sections.

NominalRating

NominalOutput

AccuracyClass

AccuracyLimited Factor

Limiting LeadResistance

1A 2.5VA 10P 20 1.3 ohms

5A 7.5VA 10P 20 0.11 ohms

Separate requirements for Restricted Earth Fault and reverse power protection aregiven in section 5.6 and 5.7.

5.1 Non-directional definite time/IDMT overcurrent & earth fault protection

5.1.1 Time-delayed phase overcurrent elements

VK Icp/2 * (RCT + RL + Rrp)

5.1.2 Time-delayed earth fault overcurrent elements

VK Icn/2 * (RCT + 2RL + Rrp + Rrn)

5.2 Non-directional instantaneous overcurrent & earth fault protection

5.2.1 CT requirements for instantaneous phase overcurrent elements

VK Isp * (RCT + RL + Rrp)

5.2.2 CT requirements for instantaneous earth fault overcurrent elements

VK Isn * (RCT + 2RL + Rrp + Rrn)

5.3 Directional definite time/IDMT overcurrent & earth fault protection

5.3.1 Time-delayed phase overcurrent elements

VK Icp/2 * (RCT + RL + Rrp)



5.3.2 Time-delayed earth fault overcurrent elements


5.4 Directional instantaneous overcurrent & earth fault protection

5.4.1 CT requirements for instantaneous phase overcurrent elements

VK Ifp/2 * (RCT + RL + Rrp)

5.4.2 CT requirements for instantaneous earth fault overcurrent elements

VK Ifn/2 * (RCT + 2RL + Rrp + Rrn)

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

5.5.1 Non-directional time delayed SEF protection (residually connected)


5.5.2 Non-directional instantaneous SEF protection (residually connected)

VK Isn/2 * (RCT + 2RL + Rrp + Rrn)

5.5.3 Directional time delayed SEF protection (residually connected)


5.5.4 Directional instantaneous SEF protection (residually connected)

VK Ifn/2 * (RCT + 2RL + Rrp + Rrn)

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

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

Directional non-directional time delayed element:

VK Icn/2 * (RCT + 2RL + Rrn)

Directional instantaneous element:

VK Ifn/2 * (RCT + 2RL + Rrn)

Non-directional instantaneous element

VK Isn/2 * (RCT + 2RL + Rrn)

Note that, in addition, it should be ensured that the phase error of the applied corebalance current transformer is less than 90 minutes at 10% of rated current and lessthan 150 minutes at 1% of rated current.

Abbreviations used in the previous formulae are explained below:

where

VK = Required CT knee-point voltage (volts)

Ifn = Maximum prospective secondary earth fault current (amps)

Ifp = Maximum prospective secondary phase fault current (amps)

Icn = Maximum prospective secondary earth fault current or 31 timesI> setting (whichever is lower) (amps)



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

Isn = Stage 2 & 3 Earth Fault setting (amps)

Isp = Stage 2 and 3 setting (amps)

RCT = Resistance of current transformer secondary winding (ohms)

RL = Resistance of a single lead from relay to current transformer (ohms)

Rrp = Impedance of relay phase current input at 30In (ohms)

Rrn = Impedance of the relay neutral current input at 30In (ohms)

5.6 High impedance restricted earth fault protection

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:

Rst = F (RCT + 2RL)

s

VK 4 * Is * Rs

where

VK = Required CT knee-point voltage (volts)

Rst = Value of Stabilising resistor (ohms)

If = Maximum through fault current level (amps)

VK = CT knee point voltage (volts)

S = Current setting of REF element (amps), (REFs)

RCT = Resistance of current transformer secondary winding (ohms)

RL = Resistance of a single lead from relay to current transformer (ohms)

5.7 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.

5.7.1 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.



5.7.2 Metering class current transformers

For low Power settings (<3%Pn), the n 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.

Reverse and Low Forward Power Settings%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

5.8 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

n + ALF x n x Rct

where:

Vk = Required kneepoint voltage

VA = Current transformer rated burden (VA)

ALF = Accuracy limit factor

n = Current transformer secondary rated current (A)



Rct = Resistance of current transformer secondary winding ()

If Rct is not available, then the second term in the above equation can be ignored.

Example: 400/5A, 15VA 5P 10, Rct = 0.2

Vk = 15 x 10

5 + 10 x 5 x 0.2

= 40V

5.9 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 than an IECknee point voltage. This is because the ANSI/IEEE voltage rating is defined in termsof useful output voltage at the terminals of the CT, whereas the IEC knee pointvoltage includes the voltage drop across the internal resistance of the CT secondarywinding added to the useful output. The IEC/BS knee point is also typically 5% higherthan 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

n = 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

6. 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:

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 Appendix Afor details of digitaldata bus 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 3

6.1 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.

6.2 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.



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.

6.3 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 6.10 of theseApplication Notes.

6.4 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.

6.5 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 Appendix A of this guide.The pins of the monitor/download port used for monitor bits are given in the tableoverleaf. The signal ground is available on pins 18, 19, 22 and 25.

Monitor Bit 1 2 3 4 5 6 7 8

Monitor/ Download Port Pin 11 12 15 13 20 21 23 24

Table 4

THE MONITOR/DOWNLOAD PORT DOES NOT HAVE ELECTRICAL ISOLATEDAGAINST INDUCED VOLTAGES ON THE COMMUNICATIONS CHANNEL. ITSHOULD THEREFORE ONLY BE USED FOR LOCAL COMMUNICATIONS.

6.6 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.



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.

6.7 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.

6.8 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.

6.9 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’.

6.10 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.


MiCOM P341

RELAY DESCRIPTION

P341/EN HW/D22 Relay Description

MiCOM P341



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 IRIG-B 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 & 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 7

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 IRIG-B board 9

2.6 Mechanical layout 9

3. RELAY SOFTWARE 10

3.1 Real-time operating system 10

3.2 System services software 11

3.3 Platform software 11

3.3.1 Record logging 11

3.3.2 Settings database 11

3.3.3 Database interface 11

3.4 Protection & control software 12



3.4.1 Overview - protection & control scheduling 12

3.4.2 Signal processing 12

3.4.3 Programmable scheme logic 13

3.4.3.1 PSL data 13

3.4.4 Event, fault & maintenance recording 13

3.4.5 Disturbance recorder 14

4. SELF TESTING & DIAGNOSTICS 14

4.1 Start-up self-testing 14

4.1.1 System boot 15

4.1.2 Initialisation software 15

4.1.3 Platform software initialisation & monitoring 15

4.2 Continuous self-testing 15

Figure 1: Relay modules and information flow 4

Figure 2: Main input board 7

Figure 3: Relay software structure 10



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

Processor board which performs all calculations for the relay and controls theoperation of all other modules within the relay. The processor board also containsand controls the 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 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 IEC 60870communication 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.



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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 and 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 & 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 measurements. The protection & controlsoftware interfaces with the platform software for settings changes and logging ofrecords, and with the system services software for acquisition of sample data andaccess to output relays and digital opto-isolated inputs.

1.2.5 Disturbance recorder

The analogue values and logic signals are routed from the protection and controlsoftware to the disturbance recorder software. This software compresses the data toallow a greater number of records to be stored. The platform software interfaces tothe 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 the25-pin D-connector relay test port for parallel communication. All serialcommunication is handled using a two-channel 85C30 serial communicationscontroller (SCC).

The memory provided on the main processor board is split into two categories,volatile and non-volatile: the volatile memory is fast access (zero wait state) SRAMwhich is used for the storage and execution of the processor software, and datastorage as required during the processor’s calculations. The non-volatile memory issub-divided into 3 groups: 2MB of flash memory for non-volatile storage of softwarecode and text, 256kB of battery backed-up SRAM for the storage of disturbance,event and fault record data, and 32kB of E2PROM memory for the storage ofconfiguration data, including the present setting values.

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 consists of twoPCBs; the main input board and a transformer board. The P341 relay provides fourvoltage inputs and four current inputs.

2.3.1 Transformer board

The standard transformer board holds up to four voltage transformers (VTs) and upto five current transformers (CTs). The current inputs will accept either 1A or 5Anominal current (menu and wiring options) and the voltage inputs can be specifiedfor either 110V or 440V nominal voltage (order option). The transformers are usedboth to step-down the currents and voltages to levels appropriate to the relay’selectronic circuitry and to provide effective isolation between the relay and the powersystem. The connection arrangements of both the current and voltage transformersecondaries provide differential 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 intoa single analogue-to-digital converter chip. The A-D converter provides 16-bitresolution and a serial data stream output. The digital input signals are opto isolatedon this board to prevent excessive voltages on these inputs causing damage to therelay's internal circuitry.



The signal multiplexing arrangement provides for 16 analogue channels to besampled. The P341 provides 4 current inputs and 4 voltage inputs. 3 sparechannels are used to sample 3 different reference voltages for the purpose ofcontinually checking the operation of the multiplexer and the accuracy of the A-Dconverter. The sample rate is maintained at 24 samples per cycle of the powerwaveform by a logic control circuit which which is driven by the frequency trackingfunction on the main processor board. The calibration E2PROM holds the calibrationcoefficients which are used by the processor board to correct for any amplitude orphase 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.

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The input board provides some hardware filtering of the digital signals to removeunwanted noise before buffering the signals for reading on the parallel data bus.Depending on the relay model, more than 8 digital input signals can be accepted bythe relay. This is achieved by the use of an additional opto-board which contains thesame provision for 8 isolated digital inputs as the main input board, but does notcontain any of the circuits for analogue signals which are provided on the main inputboard.

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 during



a 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 P341 interconnection protection relay, the protection task is executed twotimes per cycle, i.e. after every 12 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 one cycle. The time to register thechange of state will depend on if the opto input changes state at the start or end of aprotection 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 RS485communication 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

24/54V dc only

48/125V 30/100V rms

110/250V 100/240V rms

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. Allpower supply voltages including the 0V earth line are distributed around the relay viathe 64-way ribbon cable. One further voltage level is provided by the power supplyboard which is the field voltage of 48V. This is brought out to terminals on the backof the relay so that it can be used to drive the optically isolated 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, DNP 3.0 or IEC 60870-5-103 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, two normallyopen contacts and six 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 IRIG-B board

The IRIG-B board is an order option which can be fitted to provide a timing referencefor the relay. This can be used wherever an IRIG-B signal is available. The IRIG-Bsignal is connected to the board via a BNC connector on the back of the relay. Thetiming information is used to synchronise the relay’s internal real-time clock to anaccuracy 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 (IEC 60870 only).

2.6 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-pin



and 25-pin female D-connectors are used at the front of the relay for datacommunication.

Inside the relay the PCBs plug into the connector blocks at the rear, and can beremoved from the front of the relay only. The connector blocks to the relay’s CTinputs are provided with internal shorting links inside the relay which willautomatically short the current transformer circuits before they are broken when theboard is removed.

The front panel consists of a membrane keypad with tactile dome keys, an LCD and12 LEDs mounted on an aluminium backing plate.

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 3 shows the structure of the relay software.

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Figure 3: Relay software structure

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 3, 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, DNP 3.0, IEC 60870-5-103).

3.3.1 Record logging

The logging function is provided to store all alarms, events, faults and maintenancerecords. The records for all of these incidents are logged in battery backed-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 is responsible for logging of amaintenance record in the event of a relay failure. This includes errors that havebeen detected by the platform software itself or error that are detected by either thesystem services or the protection software function. See also the section onsupervision 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 groups. The settingsare maintained in non-volatile E2PROM memory. The platform software’smanagement of the settings database includes the responsibility of ensuring that onlyone user interface modifies the settings of the database at any one time. This featureis employed to avoid confusion between different parts of the software during asetting change. For changes to protection settings and disturbance recorder settings,the platform software operates a ‘scratchpad’ in SRAM memory. This allows anumber of setting changes to be made in any order but applied to the protectionelements, and saved in the database in E2PROM, at the same time (see also sectionP341/EN IT/C22 on the user interface). If a setting change affects the protection &control task, the database advises it of the new values.

3.3.3 Database interface

The other function of the platform software is to implement the relay’s internalinterface between the database and each of the relay’s user interfaces. The 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 ofany of the software tasks in the relay in order to provide the fastest possibleprotection response. The protection & control software has a supervisor task whichcontrols the start-up of the task and deals with the exchange of messages betweenthe task and the platform software.

3.4.1 Overview - protection & control scheduling

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

3.4.2 Signal processing

The sampling function provides filtering of the digital input signals from the opto-isolators and frequency tracking of the analogue signals. The digital inputs arechecked against their previous value over a period of half a cycle. Hence 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 P34x0yy0” 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 this has been completed the data then held in SRAM iscompared to that in the flash EPROM to ensure that the two are the same and 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 boardif fitted. The final test that is made concerns the input and output of data; thepresence and healthy condition of the input board is checked and the analogue dataacquisition 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 IRIG-B board is checked, where it is fitted, by the softwarethat reads the time and date from the board.

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 or theIRIG-B board, the relay will continue in operation. However, for problems detected inany other area the relay will initiate a shutdown and re-boot. This will result in aperiod of up to 5 seconds when the protection is unavailable, but the complete restartof the relay including all initialisations should clear most problems that could occur.As described above, an integral part of the start-up procedure is a thoroughdiagnostic self-check. If this detects the same problem that caused the relay torestart, i.e. the restart has not cleared the problem, then the relay will take itselfpermanently out of service. This is indicated by the ‘Healthy’ LED on the front of therelay, which will extinguish, and the watchdog contact which will operate.


MiCOM P341

TECHNICAL DATA

P341/EN TD/D22 Technical Data

MiCOM P341



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 9

2.1 Current circuit 9

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 11

4.1 Dielectric withstand 11

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 12

5.1.2 Class B 12

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 13

5.3.1 AC voltage short interruptions 13

5.3.2 AC voltage dips 13

5.4 High frequency disturbance 14

5.5 Fast transients 14

5.6 Conducted/radiated emissions 14

5.6.1 Conducted emissions 14

5.6.2 Radiated emissions 14

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 15

5.9 Surge immunity 15

5.10 Power frequency magnetic field 16

5.11 Power frequency interference 16

5.12 Surge withstand capability (SWC) 16

5.13 Radiated immunity 16

6. ATMOSPHERIC ENVIRONMENT 17

6.1 Temperature 17

6.2 Humidity 17

6.3 Enclosure protection 17

7. MECHANICAL ENVIRONMENT 17

7.1 Performance criteria 17

7.1.1 Severity classes 18

7.1.2 Vibration (sinusoidal) 18

7.1.3 Shock and bump 18

7.1.4 Seismic 18

8. EC EMC COMPLIANCE 19

9. EC LVD COMPLIANCE 19

10. PROTECTION FUNCTIONS 19

10.1 Three phase non-directional/directional overcurrent protection (50/51)(67) 19



10.1.1 Setting ranges 19

10.1.2 Time delay settings 20

10.1.3 Transient overreach and overshoot 20

10.1.3.1 Accuracy 20

10.2 Inverse time (IDMT) characteristic 20

10.2.1 Time multiplier settings for IEC/UK curves 21

10.2.1.1 Time dial settings for IEEE/US curves 21

10.2.1.2 Definite time characteristic 21

10.2.1.3 Reset characteristics 21

10.2.2 Accuracy 22

10.3 Earth fault & sensitive earth fault protection (50N/51N) (67N) (64) 25


10.3.1.1 Earth fault, sensitive earth fault 25

10.3.1.2 Polarising quantities for earth fault measuring elements 25

10.3.1.3 Restricted earth fault (low impedance) 26

10.3.1.4 Restricted earth fault (high impedance) 26

10.3.2 EF and SEF time delay characteristics 26

10.3.3 Wattmetric SEF settings (zero sequence power settings) 26

10.3.4 Accuracy 27

10.3.4.1 Earth fault 1 27

10.3.4.2 Earth fault 2 27

10.3.4.3 SEF 27

10.3.4.4 REF 28

10.3.4.5 Wattmetric SEF 28

10.3.4.6 Polarising quantities 28

10.4 Neutral displacement/residual overvoltage (59N) 28


10.4.2 Time delay settings 29

10.4.3 Accuracy 29

10.5 Under voltage (27) 29

10.5.1 Level settings 29

10.5.2 Under voltage protection time delay characteristics 29

10.5.3 Accuracy 30

10.6 Over voltage (59) 30

10.6.1 Level settings 30



10.6.2 Over voltage protection time delay characteristics 30

10.6.3 Accuracy 31

10.7 Under frequency (81U) 31

10.7.1 Accuracy 31

10.8 Over frequency (81O) 31

10.8.1 Accuracy 31

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

10.9.1 Accuracy 32

10.10 Sensitive reverse power/low forward power/over power (32R /32L /32O) 33

10.10.1 Accuracy 33

10.11 Rate of change of frequency 34

10.11.1 Setting range 34

10.11.2 Accuracy 34

10.12 Reconnection time delay 34


10.12.2 Accuracy 34

10.13 Voltage vector shift 34


10.13.2 Accuracy 34

10.14 Thermal overload (49) 35

10.14.1 Accuracy 35

11. SUPERVISORY FUNCTIONS 35

11.1 Voltage transformer supervision 35

11.1.1 Accuracy 35

11.2 Current transformer supervision 36

11.2.1 Accuracy 36

12. PROGRAMMABLE SCHEME LOGIC 36

12.1 Level settings 36

12.2 Accuracy 36

13. MEASUREMENTS AND RECORDING FACILITIES 37

13.1 Measurements 37

13.2 IRIG-B and real time clock 37

13.2.1 Features 37

13.2.2 Performance 37



14. DISTURBANCE RECORDS 38

14.1 Level settings 38

14.2 Accuracy 38

15. PLANT SUPERVISION 38

15.1 CB state monitoring control and condition monitoring 38

15.1.1 CB monitor settings 38

15.1.2 CB control settings 38

15.1.3 Accuracy 38

15.2 CB fail and backtrip breaker fail 39

15.2.1 Timer settings 39

15.2.2 Timer accuracy 39

15.2.3 Undercurrent settings 39

15.2.4 Undercurrent accuracy 39

16. INPUT AND OUTPUT SETTING RANGES 39

16.1 CT and VT ratio settings 39

17. BATTERY LIFE 40

18. FREQUENCY RESPONSE 40

19. LOCAL AND REMOTE COMMUNICATIONS 41

19.1 Front port 41

19.2 Rear port 41

19.2.1 Performance 41

Figure 1: IEC inverse time curves 23

Figure 2: American inverse time curves 24

Figure 3: Biased REF characteristic 26

Figure 4: Frequency response 40



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 64 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

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 is40Hz – 70Hz.

1.5 ‘Universal’ logic inputs (P340 range)

The P340 series relays are fitted with universal opto isolated logic inputs that can be programmed 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 lower nominal voltage and a Logic 0 or Off value for the voltages ≤60% of the set higher nominal voltage. This lower value eliminates fleeting pickups that may occur during a battery earth fault, when stray capacitance may present up to 50% of battery voltage across an input. Each input also has a pre-set filter of ½ cycle which renders the 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. The P341 relay has a base numberof opto inputs of 8 in the 40TE case. One optional board can be added to the P341 to increase it’s number of opto inputs, the boards available are the 8 opto input board or the 8 output contact board or the 4 opto input + 4 output contact board.

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, two normallyopen contacts and six 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 to



existing models for suffix issue B or greater hardware. Note, the model number suffixletter refers to the hardware version.

The P341 has a base number of relay contacts of 7 in the 40TE case. One optionalboard can be added to the P341 to increase it’s number of output contacts, theboards available are the 8 opto input board or the 8 output contact board or the 4opto input + 4 output contact board.

Make & Carry 30A for 3s

Carry 250A for 30ms10A continuous

Break

dc: 50W resistivedc: 62.5W inductive (L/R = 40ms)ac: 2500VA resistive (P.F. = 1)ac: 2500VA inductive (P.F. = 0.7)

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).

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

Size 12 /60TE 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

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



Quantity Reference Conditions Test Tolerance

General

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.



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 Three phase non-directional/directional overcurrent protection (50/51) (67)

10.1.1 Setting ranges

Setting Stage Range Step Size

Ι>1 Current Set 1st Stage 0.08 - 4.0Ιn 0.01Ιn

Ι>2 Current Set 2nd Stage 0.08 - 4.0Ιn 0.01Ιn

Ι>3 Current Set 3rd Stage 0.08 - 32Ιn 0.01Ιn

Ι>4 Current Set 4th Stage 0.08 - 32Ιn 0.01Ιn

Directional overcurrent settings:

Range Step Size

Relay characteristic angle -95° to +95° 1

The directional elements polarising is fixed and uses a cross polarised quantity, if thepolarising voltage falls to less than 0.5V synchronous memory polarising is availablefor 3.2s.



10.1.2 Time delay settings

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

Element Time Delay Type

1st Stage Definite Time (DT) or IDMT

2nd Stage DT or IDMT

3rd Stage DT

4th Stage DT

Curve Type Reset Time Delay

IEC / UK curves DT only

All other IDMT or DT

10.1.3 Transient overreach and overshoot

10.1.3.1 Accuracy

Additional tolerance due to increasingX/R ratios ±5% over the X/R ratio of 1 to 90

Overshoot of overcurrent elements <30ms

10.2 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

7 x

K

(Ι/Ιs) α - 1 + L

where

t = operation time

K = constant

Ι = measured current

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

Moderately inverse IEEE 0.0515 0.02 0.114

Very inverse IEEE 19.61 2 0.491

Extremely inverse IEEE 28.2 2 0.1217

Inverse US-C08 5.95 2 0.18

Short time inverse US-C02 0.02394 0.02 0.01694

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.

10.2.1 Time multiplier settings for IEC/UK curves

Name Range Step Size

TMS 0.025 to 1.2 0.025

10.2.1.1 Time dial settings for IEEE/US curves


TD 0.5 to 15 0.1

10.2.1.2 Definite time characteristic

Element Range Step Size

All stages 0 to 100s 10ms

10.2.1.3 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

7 x

tr

1 - (Ι/Ιs) α



Where

tReset = reset time

tr = constant

Ι = measured current

ΙS = current threshold setting

α = constant

TD = time dial Setting (same setting as that employed by IDMT curve)

IEEE/US IDMT Curve Description Standard tr Constant α Constant

Moderately Inverse IEEE 4.85 2

Very Inverse IEEE 21.6 2

Extremely Inverse IEEE 29.1 2

Inverse US-C08 5.95 2

Short Time Inverse US-C02 2.261 2

Inverse Reset Characteristics

10.2.2 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 40ms 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

Reference conditions TMS=1, TD=7 and Ι> setting of 1A, operating range 2-20Ιn



! "#! $%

&'"(

Figure 1: IEC inverse time curves



) """! ' """! * """#! + $ , $-

./

)

'

,

*

+

&*"(

Figure 2: American inverse time curves



10.3 Earth fault & sensitive earth fault protection (50N/51N) (67N) (64)

There are two standard earth fault elements, Earth Fault 1 uses measured quantities,Earth Fault 2 uses derived quantities.


10.3.1.1 Earth fault, sensitive earth fault

Range Step Size

Earth Fault 1 ΙN1>1 Current Set 0.08 - 4.0Ιn 0.01Ιn

(Measured) ΙN1>2 Current Set 0.08 - 4.0Ιn 0.01Ιn

ΙN1>3 Current Set 0.08 - 32Ιn 0.01Ιn


Earth Fault 2 ΙN2>1 Current Set 0.08 - 4.0Ιn 0.01Ιn

(Derived) ΙN2>2 Current Set 0.08 - 4.0Ιn 0.01Ιn



Sensitive Earth Fault ΙSEF>1 Current Set 0.005 - 0.1Ιn 0.00025Ιn

(Measured) ΙSEF>2 Current Set 0.005 - 0.1Ιn 0.00025Ιn

ΙSEF>3 Current Set 0.005 - 0.8Ιn 0.001Ιn

ΙSEF>4 Current Set 0.005 - 0.8Ιn 0.001Ιn

10.3.1.2 Polarising quantities for earth fault measuring elements

The polarising quantity for earth fault elements can be either zero sequence ornegative sequence values. This can be set independently set for Earth Fault 1 andEarth Fault 2.

Characteristic Angle Settings

Setting Range Step Size

ΙN1> Char angle -95° to +95° 1°

ΙN2> Char angle -95° to +95° 1°

ΙSEF> Char angle -95° to +95° 1°

Zero Sequence Voltage Polarisation


ΙN1>VNpol Set (Vn = 100/120 V) 0.5 – 80V 0.5V

ΙN1>VNpol Set (Vn = 380/480 V) 2.0 – 320V 2V

Negative Sequence Polarisation


ΙN1>Ι2pol Set 0.08 - 1.0Ιn 0.01Ιn

ΙN1>V2pol Set (Vn = 100/120 V) 0.5 – 25V 0.5V

ΙN1>V2pol Set (Vn = 380/480 V) 2.0 – 100V 2V



10.3.1.3 Restricted earth fault (low impedance)


ΙREF> K1 0% to 20% 1% (minimum)


ΙREF> Ιs1 8% to 100% Ιn 1% Ιn

ΙREF> Ιs2 10% to 150% Ιn 1% Ιn

&*"(0

Figure 3: Biased REF characteristic

10.3.1.4 Restricted earth fault (high impedance)

The High Impedance Restricted Earth Fault protection is mutually exclusive with theSensitive Earth Fault protection as the same sensitive current input is used. Thiselement should be used in conjunction with an external stabilising resistor.



10.3.2 EF and SEF time delay characteristics

The earth-fault measuring elements for EF and SEF are followed by an independentlyselectable time delay. These time delays are identical to those of the PhaseOvercurrent time delay. The reset time delay is also the same as the Phaseovercurrent reset time.

10.3.3 Wattmetric SEF settings (zero sequence power settings)

If Wattmetric SEF is selected an additional zero sequence power threshold is applied,this is settable according to the following table:


PN> Setting 0 - 20W (Rating = 1A, 100/120V) 0.05W

0 - 100W (Rating = 5A, 100/120V) 0.25W

0 - 80W (Rating = 1A, 380/440V) 0.20W

0 - 400W (Rating = 5A, 380/440V) 1W



10.3.4 Accuracy

10.3.4.1 Earth fault 1







DT reset ±5%

Repeatability 2.5%

* Reference conditions TMS=1, TD=7 and ΙN> setting of 1A, operating range2-20Ιn.

10.3.4.2 Earth fault 2


Drop-off >0.85 x Setting





DT reset ±2% or 50ms whichever is greater

Repeatability 5%

* Reference conditions TMS=1, TD=7 and ΙN> setting of 1A, operating range2 - 20Ιn.

10.3.4.3 SEF





IEEE reset ±7.5% or 60ms whichever is greater


DT reset ±5%

Repeatability 5%

Reference conditions TMS=1, TD=7 and ΙN> setting of 100mA, operating range2-20Ιs.



10.3.4.4 REF

Pick-up Setting formula ±5%

Drop-off 0.80 x Setting formula ±5%

Low impedance operating time <60ms

High impedance pick-up Setting ±5%

High impedance operating time <30ms

Repeatability <15%

10.3.4.5 Wattmetric SEF

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%

10.3.4.6 Polarising quantities

Zero Sequence Polarising

Operating boundary pick-up ±2°of RCA ±90°

Hysteresis <3°

VN> Pick-up Setting ±10%

VN> Drop-off 0.9 x Setting ±10%

Negative Sequence Polarising

Operating boundary pick-up ±2°of RCA ±90°

Hysteresis <3°

V2> Pick-up Setting ±10%

V2> Drop-off 0.9 x Setting ±10%

Ι2> Pick-up Setting ±10%

Ι2> Drop-off 0.9 x Setting ±10%

10.4 Neutral displacement/residual overvoltage (59N)



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



10.4.2 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

10.4.3 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%

10.5 Under voltage (27)

10.5.1 Level settings


V<1 & V<2(Vn = 100/120V) 10 – 120V 1V

V<1 & V<2(Vn = 380/480V) 40 – 480V 4V

10.5.2 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.

10.5.3 Accuracy






Reset <75ms

Repeatability <1%

10.6 Over voltage (59)

10.6.1 Level settings


V>1 & V>2(Vn = 100/120V) 60 – 185V 1V

V>1 & V>2(Vn = 380/480V) 240 – 740V 4V

10.6.2 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

10.6.3 Accuracy






Reset <75ms

10.7 Under frequency (81U)


f (for all stages) 45 – 65 Hz 0.01 Hz

t (for all stages) 0 – 100s 0.01s

10.7.1 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)

10.8 Over frequency (81O)


f (for all stages) 45 – 65 Hz 0.01 Hz

t (for all stages) 0 – 100s 0.01s

10.8.1 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)



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


Stage 1 Enable/disable

Mode Reverse/low forward/over

–P> (reverse power)

14W – 40W (Ιn=1A, Vn=100/120V)56W – 160W (Ιn=1A, Vn=380/480V)70W – 200W (Ιn=5A, Vn=100/120V)280W – 800W (Ιn=5A, Vn=380/480V)

Equivalent Range in %Pn 8% - 21%

2W8W10W40W

1%

P< (low forward power



2W8W10W40W

1%

P> (over power)



2W8W10W40W

1%

DT 0 – 100s 0.01s

DO Timer 0 – 100s 0.01s

Stage 2 Same as Stage 1

10.9.1 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

Operating time ±2% or 50ms whichever is greater

Repeatability <5%

Disengagement time <50ms

tRESET ±5%

Instantaneous operating time <50ms



10.10 Sensitive reverse power/low forward power/over power (32R /32L /32O)


Stage 1 Enable/disable

Mode Reverse/low forward/over

–P> (reverse power)

0.3W – 15W (Ιn=1A, Vn=100/120V)

1.2W – 60W (Ιn=1A, Vn=380/480V)

1.5W – 75W (Ιn=5A, Vn=100/120V)

6.0W – 300W (Ιn=5A, Vn=380/480V)

Equivalent range in %Pn 0.5% – 23%

0.1W

0.4W

0.5W

2.0W

0.2%

P< (low forward power)

0.3W – 15W (Ιn=1A, Vn=100/120V)

1.2W – 60W (Ιn=1A, Vn=380/480V)

1.5W – 75W (Ιn=5A, Vn=100/120V)

6.0W – 300W (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

10.10.1 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%

Disengagement time <50ms

tRESET ±5%

Instantaneous operating time <50ms



10.11 Rate of change of frequency

10.11.1 Setting range


df/dt Status Enable/Disable

df/dt Setting 0.1 – 10Hz/s 0.01Hz

df/dt Time Delay 0 – 100s 0.01s

df/dt f Low 45 – 65Hz 0.01Hz

df/dt f High 45 – 65Hz 0.01Hz

10.11.2 Accuracy

Pick-up Setting ±0.5Hz/s


Lower deadband operating time ±2% or 160ms whichever is greater

Upper deadband operating time ±2% or 160ms whichever is greater

Operation over deadband ±2% or 170ms whichever is greater

Repeatability <5%

10.12 Reconnection time delay



Reconnect Status Enable/Disable

Reconnect 0.1 – 10Hz/s 0.01Hz

Reconnect delay 0 – 300s 0.01s

Reconnect pulse 0.03 – 30s 0.01s

10.12.2 Accuracy


10.13 Voltage vector shift



V Shift Status Enable/Disable

V shift angle 2 – 30° 1°

10.13.2 Accuracy

Pick-up Setting ±0.5°

Trip pulse 500ms ±2%



10.14 Thermal overload (49)


Thermal I> 0.5 - 1.5 Ιn 0.01Ιn

Thermal Alarm 20 -100% 1%

T-heating 1 - 200 minutes 1 minute

T-cooling 1 - 200 minutes 1 minute

M Factor 0 - 10 1

10.14.1 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 overvoltage P.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 Vn

0.05 to 3 Ιn±5% of reading at unitypower factor

Reactive Power (VArs)0.2 to 2 Vn

0.05 to 3 Ιn±5% of reading at zeropower factor

Apparent Power (VA)0.2 to 2 Vn

0.05 to 3 Ιn±5% of reading

Energy (Wh)0.2 to 2 Vn


Energy (Varh)0.2 to 2 Vn


Phase accuracy 0° to 360° ±0.5°

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 seconds / 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



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 4: 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 P34x range 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, 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


MiCOM P341

SCADA COMMUNICATIONS

P341/EN CT/D22 SCADA Communications

MiCOM P341



CONTENT

1. INTRODUCTION 3

2. COURIER INTERFACE 3

2.1 Courier protocol 3

2.2 Front courier port 4

2.3 Supported command set 4

2.4 Relay courier database 5

2.5 Setting changes 6

2.5.1 Method 1 6

2.5.2 Method 2 6

2.5.3 Relay settings 6

2.5.4 Setting transfer mode 7

2.6 Event extraction 7

2.6.1 Automatic event extraction 7

2.6.2 Event types 7

2.6.3 Event format 8

2.6.4 Manual event record extraction 8

2.7 Disturbance record extraction 8

2.8 Programmable logic settings 9

3. MODBUS INTERFACE 10

3.1 Communication link 10

3.2 Modbus functions 10

3.3 Response codes 11

3.4 Register mapping 11

3.5 Event extraction 11

3.5.1 Manual selection 11

3.5.2 Automatic extraction 12

3.5.3 Record data 12

3.6 Disturbance record extraction 13

3.6.1 Manual selection 13

3.6.2 Automatic extraction 13

3.6.3 Record data 14



3.7 Setting changes 14

3.7.1 Password protection 14

3.7.2 Control and support settings 15

3.7.3 Protection and disturbance recorder settings 15

4. IEC60870-5-103 INTERFACE 16

4.1 Physical connection and link layer 16

4.2 Initialisation 16

4.3 Time synchronisation 17

4.4 Spontaneous events 17

4.5 General interrogation 17

4.6 Cyclic measurements 17

4.7 Commands 17

4.8 Test mode 17

4.9 Disturbance records 18

4.10 Blocking of monitor/command direction 18

5. DNP3 INTERFACE 18

5.1 DNP3 protocol 18

5.2 DNP3 menu setting 18

5.3 Object 1 binary inputs 18

5.4 Object 10 binary outputs 19

5.5 Object 20 binary counters 19

5.6 Object 30 analogue input 19

5.7 DNP3 configuration using MiCOM S1 19

5.7.1 Object 1 20

5.7.2 Object 20 20

5.7.3 Object 30 20



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 three protocols via the rearcommunication interface. This is in addition to the front serial interface whichsupports the Courier protocol.

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 three protocol options the supported functions/commands will belisted together with the database definition. The operation of standard proceduressuch as extraction of event, fault and disturbance records or setting changes will alsobe described.

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 on 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/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 twophysical links K-Bus or EIA(RS)232; K-Bus is based on EIA(RS)485 voltage levels and issynchronous, the EIA(RS)232 interface uses IEC60870 FT1.2 (IEC60870) frameformat. The relay supports an IEC60870 connection on the front, for one to oneconnection, this is not suitable for permanent connection. This interface uses a fixedbaud rate, 11 bit frame and a fixed device address. The rear EIA(RS)485 interface isused to provide a permanent connection for K-Bus and allows multi-drop connection.It should be noted that although K-Bus is based on EIA(RS)485 voltage levels it is asynchronous protocol using FM0 encoding. It is not possible to use a standardEIA(RS)232 to EIA(RS)485 converter to convert IEC60870 to K-Bus.

The following documentation should be referred to for a detailed description of theCourier protocol, command set and link description.

R6509 K-Bus Interface Guide

R6510 IEC60870 Interface Guide

R6511 Courier Protocol

R6512 Courier User Guide



2.2 Front courier port

The front EIA(RS)232 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 someof 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

Sent 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 a request will be the final data

Fixed Address:

The address of the front Courier port is always 1, the Change Device address command is not supported.

It should be noted that although automatic extraction of event and disturbancerecords is not supported it is possible to manually access this data via the 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*

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 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.

Appendix A contains the complete database definition for the relay for each celllocation the following information is stated:

Cell Text

Cell Datatype

Cell value

Whether if the cell is settable, if so

Minimum value

Maximum value

Step size

Password Level required to allow setting changes

String information (for Indexed String or Binary flag cells)



2.5 Setting changes

(See Courier User Guide Chapter 9)

Courier provides two mechanisms for making setting changes, both of these aresupported by the relay. Either method can be used for editing any of the settingswithin the relay database.

2.5.1 Method 1

This uses a combination of three commands to perform a settings change:

Enter Setting Mode - checks that the cell is settable and returns the limits

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 is most suitable for off-line setting editors such as MiCOM S1.

2.5.3 Relay settings

There are three categories of settings within the relay database

Control and Support

Disturbance Recorder

Protection Settings Group

Setting changes made to the control and support settings are implementedimmediately and stored in non-volatile memory. Settings made to either theDisturbance recorder settings or the Protection Settings Groups are stored inscratchpad memory only and are not immediately implemented by the relay.

To action setting changes made to these areas of the relay database the SaveChanges cell in the Configuration column must be written to. This allows thechanges to either be confirmed and stored within non-volatile memory or the settingchanges 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 confirmedand stored in non-volatile memory.

2.6 Event extraction

Events can be extracted either automatically (rear port only) or manually (eitherCourier port). For automatic extraction all events are extracted in sequential orderusing the standard Courier mechanism, this includes fault/maintenance data ifappropriate. The manual approach allows the user to select events, faults ormaintenance data at random from the stored records.

2.6.1 Automatic event extraction

(See Chapter 7 Courier User Guide)

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

Appendix B contains a table of the events created by the relay and indicates how thecontents of the above fields are interpreted. Fault records and Maintenance recordswill return a Courier Type 3 event which contains the above fields together with twoadditional fields:

Event extraction column

Event number

These events contain additional information which is extracted from the relay usingthe referenced extraction column. Row 01 of the extraction column contains a settingwhich allows the fault/maintenance record to be selected. This setting should be setto the 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 of the nature of therecord selected. It is possible to select by event number, or to directly select a faultrecord or maintenance record.

Event Record selection (Row 01) - This cell can be set to a value between 0 to 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, older records will beassigned positive values, and negative values will be used for more recent records.To facilitate automatic extraction via the rear port the Disturbance bit of the Statusbyte is set by the relay whenever there are unextracted disturbance records.

Once a record has been selected, using the above cell, the time and date of therecord can be read from cell 02. The disturbance record itself can be extracted usingthe block transfer mechanism from cell B00B. It should be noted that the file extractedfrom the relay is in a compressed format, it will be necessary to use MiCOM S1 to de-compress this file and save the disturbance record in the COMTRADE 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 logic settings

The programmable logic settings can be uploaded from and downloaded to the relayusing the block transfer mechanism defined in Chapter 12 of 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, it is defined by MODICON Inc bythe following document:

Modicon Modbus 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 modecommunication rather than ASCII mode as this provides more efficient use of thecommunication bandwidth. This mode of communication is defined in page 7 of theModbus Guide.

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 is not anallowable value. If any of the cells in therange to be written to cannot be accesseddue to password protection then all changeswithin the request are discarded and thiserror response will be returned. Note: If thestart address is correct but the range includesnon - implemented addresses this response isnot produced.

03 Illegal Value A value referenced in the data fieldtransmitted by the master is not within range.Other values transmitted within the samepacket will be executed if inside range.

06 Slave Device Busy The write command cannot be implementeddue to the database being locked by anotherinterface. This response is also produced ifthe relay software is busy executing aprevious request.

3.4 Register mapping

The relay supports the following memory page references:-

Memory Page Interpretation

0xxxx Read and write access of the Output Relays.

1xxxx Read only access of the Opto Inputs.

3xxxx Read only access of Data.

4xxxx Read and write access of Settings.

where xxxx represents the addresses available in the page (0 to 9999).

Note that the “extended memory file” (6xxxx) is not supported.

A complete map of the Modbus addresses supported by the relay is contained inAppendix 1 of this service manual.

3.5 Event extraction

The relay supports two methods of event extraction providing either automatic ormanual extraction of the stored event, fault and maintenance records.

3.5.1 Manual selection

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



There are three registers available to manually select stored records.

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.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. (See 3.5.3 for details)

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 that havenot yet been extracted. This is performed by reading the relay status register 30001(G26 data type). If the event bit of this register is set then the relay has unextractedevents available. To select the next event for sequential extraction the master stationwrites a value of 1 to the record selection register 40400 (G18 data type). The eventdata together with any fault/maintenance data can be read from the registersspecified below. Once the data has been read the event record can be marked ashaving been read by writing a value of 2 to register 40400. The process can then berepeated untill all events have been extracted.

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 andDate

30103 4 See G12 data type

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.

ModbusAddress

30110 1 This indicates the Modbus Register addresswhere the change occurred.Alarm 30011Relays 30723Optos 30725Protection events – Like the Relay and Optoaddresses this will map onto the Modbusaddress of the South Park extensionsdepending on which bit of the DDB thechange occurred. These will range from30727 to 30785.

For Platform events, Fault events andMaintenance events the default is 0.



EventDescription

ModbusAddress

Length Comments

Event Index 30111 1 This register will contain the DDB No forprotection events or the bit No for alarmevents. The direction of the change will beindicated by the MSB

AdditionalData Present

30112 1 0 means that there is no additional data

1 means fault record data can be read from30113 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 cells 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, this has the same effect on the relay as pressing the clearkey within the alarm viewer using the front panel menu.

3.6 Disturbance record extraction

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 a listof 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 0 x 0004 to cell 40400 (G18 data type). Oncethe disturbance record data has been read by the master station this record can bemarked as having been read by writing a value of 0 x 0008 to register 40400.



3.6.3 Record data

The timestamp for a record selected using either of the above means can be readfrom registers 30930 to 30933. 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, this will be 127 for all but the last page in the record). Oncethe first page has been read the next page can be selected by writing a value of0x0010 to register 40400. If this action is performed on the last page for thedisturbance record an illegal value error response will be returned. This errorresponse can be used by the Modbus master to indicate that the last page of thedisturbance record has been read.

3.7 Setting changes

The relay settings can be split into two categories:

control and support settings

disturbance record settings and protection setting groups

Changes to settings within the control and support area are executed immediately.Changes to either the protection setting groups or the disturbance recorder are storedin a temporary area and must be confirmed before they are implemented. All therelay settings are edited via Modbus using 4xxxx addresses. The following pointsshould be noted when settings are being edited:

Settings implemented using multiple registers must be written to using a multi-register write operation.

The first address for a multi-register write must be a valid address, if there areunmapped addresses within the range being written to then the data associatedwith these addresses will be discarded.

If a write operation is performed with values that are out of range then theillegal data response will be produced. Valid setting values within the samewrite operation will be executed.

If a write operation is performed attempting to change registers that require ahigher level of password access than is currently enabled then all settingchanges in the write operation will be discarded.

3.7.1 Password protection

As described in the introduction to this service manual the relay settings can besubject to Password protection. The level of password protection required to edit asetting is indicated in relay setting database (Appendix A). Level 2 is the highest levelof password access, level 0 indicates that no password is required for editing.



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 to abort operation is performed. Register40405 can be used to 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 following functionsare 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.



4. IEC60870-5-103 INTERFACE

The IEC60870-5-103 interface is a master/slave interface with the relay as the slavedevice. This protocol is based on the VDEW communication protocol.The relay conforms to compatibility level 2, compatibility level 3 is not supported.

The following IEC60870-5-103 facilities are supported by this interface:

Initialisation (Reset)

Time Synchronisation

Event Record Extraction

General Interrogation

Cyclic Measurements

General Commands

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.

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 following informationwill be contained in the data section of this ASDU:

Manufacturer Name: AREVA T&D

The Software Identification Section will contain the first four characters of the relaymodel number to identify the type of relay, e.g. P141 and the software reference.

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 timesynchronisation message is sent as a send confirm or a broadcast (send/no reply)message, a time synchronisation message will be returned as Class 1 data.

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

The events created by the relay will be passed using the standard functiontype/information numbers to the IEC60870-5-103 master station. Private codes areused, thus any events that cannot be passed using the standardised messages can besent using Private Codes.

Events are categorised using the following information:

Function Type

Information number

Appendix A contains a complete 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 inAppendix A.

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 either 1.2 or 2.4 times the rated value of the analog value.The selection of either 1.2 or 2.4 for a particular value is indicated in Appendix A.

4.7 Commands

A list of the supported commands is contained in Appendix A. The relay will respondto other commands with an ASDU 1, with a cause of transmission (COT) of negativeacknowledgement of a command.

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 is interpreted as test mode by the IEC60870-5-103 standard. An event will beproduced to indicate both entry to and exit from test mode. Spontaneous events andcyclic measured data transmitted whilst the relay is in test mode will have a COT oftest mode.



4.9 Disturbance records

The disturbance records stored in uncompressed format and can be extracted usingthe standard mechanisms described in IEC60870-5-103.

4.10 Blocking of monitor/command direction

The relay does support a facility to block messages in the Monitor direction and alsoin the Command direction.

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 website:

www.dnp.org

The descriptions given here are intended to accompany the device profile documentwhich is included in Appendix A. The DNP3 protocol is not described here, pleaserefer to the documentation available from the user group. The device profiledocument specifies the full details of the DNP3 implementation for the relay. This isthe standard format DNP3 document which specifies which objects, variations andqualifiers are supported. The device profile document also specifies what data isavailable from the relay via DNP3. The relay operates as a DNP3 slave and supportssubset 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 8 data bits, 1 start 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 requesting timesync from the master via IIN bit 4 word 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 Appendix A. The binary input points canalso be read as change events via object 2 and object 60.

http://www.dnp.org/



5.4 Object 10 binary outputs

Object 10, binary outputs, contains commands which can be operated via DNP3. Assuch all points accept commands of type pulse on and latch on and execute thecommand once for either command. Pulse off and latch off are also accepted butresult in no action being taken. The other fields ignored (queue, clear, trip/close, intime and off time). A read of object 10 will give a value of zero at all times since thecommands do not have a data value. Due to that fact that many of the relay’sfunctions are configurable, it may be the case that some of the object 10 commandsare not available for operation. For example a ‘test auto-reclose’ command whenthe auto-reclose function is disabled. In the case of a read from object 10 this willresult in the point being reported as off-line and for an operate command to object12 will generate an error response.

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 freeze and clear functions. The freeze function takes the current value ofthe object 20 running counter and stores is it the corresponding object 21 frozencounter. The freeze and clear function resets the object 20 running counter to zeroafter freezing its value.

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 via DNP3 as fixed pointvalues although they are stored inside the relay in floating point format. Theconversion to fixed point format requires the use of a scaling factor, which differs forthe various types of data within the relay e.g. current, voltage, phase angle etc. Thedata types supported are listed at the end of the device profile document with eachtype allocated a ‘D number’, i.e. D1, D2, etc. In the object 30 point list each datapoint has a D number data type assigned to it which defines the scaling factor,default deadband 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 thermal state when the thermal protection is disabled in theconfiguration column. Note that all object 30 points are reported as secondaryvalues 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 section P341/EN IT/C22, Introduction. The configuration data isuploaded from the relay to the PC in a block of compressed format data anddownloaded to the relay in a similar manner after modification. The new DNP3configuration takes effect in the relay after the download is complete. The defaultconfiguration can be restored at any time by choosing ‘All Settings’ from the ‘RestoreDefaults’ cell in the menu ‘Configuration’ column. In S1 the DNP3 data is displayedon three tabbed screen, one for each object1, 20 and 30. Object 10 is notconfigurable.



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 pointwhich is in class 0 must be a member of one of the change event classes, 1, 2 or 3.

Points which 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.


MiCOM P341

RELAY MENU DATABASE

P341/EN GC/D22 Relay Menu Database

MiCOM P341

MiCOM P341 Guide

Interconnection Protection Relay

Relay Menu Database

This version of the Relay Menu Database is specific to the followingmodels

Model Number Software Number

P341------0050B P341------0050-A/B/C

For other models / software versions, please contact AREVA T&D for therelevant information.

(Software versions P341------0010*, P341------0020*, P341------0030*,P341------0040* are not supported by this menu database, seeP341/EN T/B11 (0020 – 0040) and TG8617A (0010) for informationon the menu database for these software versions).



RELAY MENU DATABASE

This 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.



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 512 internal signals eachreferenced by a numeric index as shown in this table. This numeric index is used toselect a signal for the commissioning monitor port. It is also used to explicitly defineprotection 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

Section 1 Introduction: User Interface operation and connections to the relay

Section 5 Communications: 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

MiCOM P341

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Col Row Start End P341 P342 P343

SYSTEM 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 * * *

Sys Fn Links 03 Binary Flag (8 bits) G95 40003 G95 Setting 1 1 1 2 * * *

Indexed Strings

Description 04 ASCII Text(16 chars) G3 40004 40011 G3 MiCOM P34* Setting 32 163 1 2 * * ** = 1 for Model 1, 2 for Model 2, 3 for Model 3

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 * * *

Relay Address 0B Unsigned Integer(16 bits) 255 Setting 0 255 1 1 * * *Needs to be address of interface Rear Courier Address available via LCD

Binary Flag(16 bits) 30001 G26 Data * * *Relay status (repeat of Courier Status byte without the busy flag

Plant Status 0C Binary Flag(16 bits) 30002 G4 Data * * *

Control Status 0D Binary Flag(16 bits) 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 0 * Visible to Rear Port

Software Ref. 1 11 ASCII Text(16 chars) 30052 30059 G3 Data * * *

Opto I/P Status 20 Binary Flag(32 bits) 30084 30085 G8 Data * * *

Indexed String

Relay O/P Status 21 Binary Flag(32 bits) 30008 30009 G9 Data * * *

Indexed String

Alarm Status 1 22 Binary Flag(32 bits) 30011 30012 G96 Data * * *

Indexed String

UNUSED 23

Access Level D0 Unsigned Integer(16 bits) G1 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 * * *

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.

Time & Date 03 IEC870 Time & Date 30103 30106 G12 (From Record) Data * * * See Event sheet

Event Text 04 Ascii String (32 chars) Data * * * See Event sheet

Modbus Address ModelMax Step Password

Level CommentModbus Database Default Setting Cell Type MinCourier Text UI Data Type Strings

Courier

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Courier

Event Value 05 Unsigned Int / Binary Flag (32 bits) 30108 30109 G27 Data * * *

Note DTL depends on event type binary flag for o/p, opto, alarm & prot. See event sheet of Spreadsheet

Select Fault 06 Unsigned Integer (16 bits) 40101 Setting 0 4 1 2 * * * Allows Fault Record to be selected

30110 G1 Data * * *

Modbus address where change occurred Alarm 330011; Relay 30723; Opto 30725 Protection 30727-30754

30111 G1 Data * * * Status of current 16 DDB elements

30112 G1 Data * * * Additional data present

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

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> 12341/2/3/4 visible if Start IN>1/2/3/4

Earth Fault N/A Data * * *

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Courier

Trip IN> 12341/2/3/4 visible if Trip IN>1/2/3/4

Sensitive E/F N/A Data * * *

Start ISEF> 12341/2/3/4 visible if Start ISEF>1/2/3/4

Sensitive E/F N/A Data * * *

Trip ISEF> 12341/2/3/4 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 * * *

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

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Courier

RTD Alarm N/A Data * *

RTD 1 label


RTD 2 label


RTD 3 label


RTD 4 label


RTD5 label


RTD6 label


RTD7 label


RTD8 label


RTD9 label


RTD10 label

RTD Trip N/A Data * *

RTD 1 label


RTD 2 label


RTD 3 label


RTD 4 label


RTD5 label


RTD6 label


RTD7 label


RTD8 label


RTD9 label


RTD10 label

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

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Courier

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 * * * Started phases + tripped phases

Start Elements1 N/A 08 Binary Flag (32 Bits) G84 30114 30115 G84 Data * * * Started Elements

Indexed String

Start Elements2 N/A 09 Binary Flag (32 Bits) G107 30116 30117 G107 Data * * * Started Elements

Indexed String

Trip Elements1 N/A 0A Binary Flag (32 Bits) G85 30118 30119 G85 Data * * * Tripped main elements

Indexed String

Trip Elements2 N/A 0B Binary Flag (32 Bits) G86 30120 30121 G86 Data * * * Tripped secondary elements

Indexed String

Fault Alarms N/A 0C Binary Flag (32 Bits) G87 30122 30123 G87 Data * * * Faullt Alarms/Warnings

Indexed String

Fault Time 0D IEC870 Time & Date 30124 30127 G12 (From Record) Data * * *

Active Group 0E Unsigned Integer 30128 G1 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 * * *

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 *

VAB 16 Courier Number (voltage) 30141 30142 G24 Data * * *

VBC 17 Courier Number (voltage) 30143 30144 G24 Data * * *

VCA 18 Courier Number (voltage) 30145 30146 G24 Data * * *

VAN 19 Courier Number (voltage) 30147 30148 G24 Data * * *

VBN 1A Courier Number (voltage) 30149 30150 G24 Data * * *

VCN 1B Courier Number (voltage) 30151 30152 G24 Data * * *

IA-2 1C Courier Number (current) 30153 30154 G24 Data *

IB-2 1D Courier Number (current) 30155 30156 G24 Data *IC-2 1E Courier Number (current) 30157 30158 G24 Data *IA Differential 1F Courier Number (current) 30159 30160 G24 Data *

IB Differential 20 Courier Number (current) 30161 30162 G24 Data *

IC Differential 21 Courier Number (current) 30163 30164 G24 Data *

VN Measured 22 Courier Number (voltage) 30165 30166 G24 Data * * *

VN Derived 23 Courier Number (voltage) 30167 30168 G24 Data * * *

IN Measured 24 Courier Number (current) 30169 30170 G24 Data * *

IN Derived *

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Courier

I Sensitive 25 Courier Number (current) 30171 30172 G24 Data * * *

IREF Diff 26 Courier Number (current) 30173 30174 G24 Data * *

IREF Bias 27 Courier Number (current) 30175 30176 G24 Data * *

I2 28 Courier Number (current) 30177 30178 G24 Data * *

3 Phase Watts 29 Courier Number (Power) 30179 30180 G125 Data * * *

3 Phase VArs 2A Courier Number (VAr) 30181 30182 G125 Data * * *

3Ph Power Factor 2B Courier Number (Decimal) 30183 G30 Data * * *

RTD 1 Label 2C Courier Number (Temperature) 30184 G10 Data * *

RTD 2 Label 2D Courier Number (Temperature) 30185 G10 Data * *

RTD 3 Label 2E Courier Number (Temperature) 30186 G10 Data * *

RTD 4 Label 2F Courier Number (Temperature) 30187 G10 Data * *

RTD 5 Label 30 Courier Number (Temperature) 30188 G10 Data * *






df/dt 36 Courier Number (Hz/s) 30194 G25 Data *

V Vector Shift 37 Courier Number (Angle) 30195 G30 Data *

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 * *

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 * * *

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Courier

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 * * *MEASUREMENTS 2 03 00 * * *A Phase Watts 01 Courier Number (Power) 30300 30302 G29 Data * * *

B Phase Watts 02 Courier Number (Power) 30303 30305 G29 Data * * *

C Phase Watts 03 Courier Number (Power) 30306 30308 G29 Data * * *

A Phase VArs 04 Courier Number (VAr) 30309 30311 G29 Data * * *

B Phase VArs 05 Courier Number (VAr) 30312 30314 G29 Data * * *

C Phase VArs 06 Courier Number (VAr) 30315 30317 G29 Data * * *

A Phase VA 07 Courier Number (VA) 30318 30320 G29 Data * * *

B Phase VA 08 Courier Number (VA) 30321 30323 G29 Data * * *

C Phase VA 09 Courier Number (VA) 30324 30326 G29 Data * * *

3 Phase Watts 0A Courier Number (Power) 30327 30329 G29 Data * * *

3 Phase VArs 0B Courier Number (VAr) 30330 30332 G29 Data * * *

3 Phase VA 0C Courier Number (VA) 30333 30335 G29 Data * * *

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 * * *

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Courier

3Ph WHours Fwd 12 Courier Number (Wh) 30343 30345 G29 Data * * * 3 Phase Watt - Hours (Forward)

3Ph WHours Rev 13 Courier Number (Wh) 30346 30348 G29 Data * * * 3 Phase Watts - Hours (Reverse)

3Ph VArHours Fwd 14 Courier Number (VArh) 30349 30351 G29 Data * * * 3 Phase VAr - Hours (Forward)

3Ph VArHours Rev 15 Courier Number (VArh) 30352 30354 G29 Data * * * 3 Phase VAr - Hours (Reverse)

3Ph W Fix Demand 16 Courier Number (Power) 30355 30357 G29 Data * * * 3 Phase Watts - Fixed Demand

3Ph VArs Fix Dem 17 Courier Number (Vars) 30358 30360 G29 Data * * * 3 Phase VArs - Fixed Demand

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 * * * 3 Phase Watts - Rolling Demand

3Ph VArs RollDem 1C Courier Number (VAr) 30370 30372 G29 Data * * * 3 Phase VArs - Rolling Demand

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 * * * 3 Phase Watts - Peak Demand

3Ph VAr Peak Dem 21 Courier Number (VAr) 30382 30384 G29 Data * * * 3 Phase VArs - Peak Demand

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])

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Courier

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 * *

MEASUREMENTS 3 04 00 *Visible if (0915=2) II ((0911=1 && (x650 = 1))

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 *Visible if (090B=1) && (X001 = 1)

IB Differential 08 Courier Number (Current) 30446 30447 G24 Data *Visible if (090B=1) && (X001 = 1)

IC Differential 09 Courier Number (Current) 30448 30449 G24 Data *Visible if (090B=1) && (X001 = 1)

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 * *Visible if (0915=1) && (XA01 >= 3)

IREF Bias 0E Courier Number (Current) 30458 30459 G24 Data * *Visible if (0915=1) && (XA01 >= 3)

VN 3rd Harmonic 0F Courier Number (Voltage) 30460 30461 G24 Data *

NPS Thermal 10 Courier Number (Percentage) 30462 G1 Data * *Visible if (090E=1) && (X304 = 1)

Reset NPSThermal 11 Indexed String G11 40104 G11 No Command 0 1 1 1 * *Visible if (090E=1) && (X304 = 1)

RTD 1 12 Courier Number (Temperature) 30463 G10 Data * * Courier text = RTD lable setting








RTD 9 1A Courier Number (Temperature) 30471 G10 Data * * Courier text = RTD lable setting

RTD 10 1B Courier Number (Temperature) 30472 G10 Data * * Courier text = RTD lable setting

RTD Open Cct 1C Binary Flag (10 bits) G108 30473 G108 Data * *

Indexed String

RTD Short Cct 1D Binary Flag (10 bits) G109 30474 G109 Data * *

Indexed String

RTD Data Error 1E Binary Flag (10 bits) G110 30475 G110 Data * *

Indexed String

Reset RTD Flags 1F Indexed string G11 40105 G11 No Command 0 1 1 1 * *

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Courier

APh Sen Watts 20 Courier Number (Power) 30476 30477 G125 Data * * *Visible only when Spower is selected in the Configuration column

APh Sen Vars 21 Courier Number (Var) 30478 30479 G125 Data * * *Visible only when Spower is selected in the Configuration column

APh Power Angle 22 Courier Number (angle) 30480 G30 Data * * *Visible only when Spower is selected in the Configuration column

Thermal Overload 23 Courier Number (Percentage) 30481 G1 Data * * *Visible if (0911=1) && (X650 = 1)

Reset ThermalO/L 24 Indexed String G11 40106 G11 No Command 0 1 1 1 * * *Visible if (0911=1) && (X650 = 1)

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 *

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 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 * * *

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Courier

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 Enabled Setting 0 1 1 2 *

Power 0C Indexed String G37 40413 Enabled Setting 0 1 1 2 * * *

Field Failure 0D Indexed String G37 40414 Enabled Setting 0 1 1 2 * *

NPS Thermal 0E Indexed String G37 40415 Enabled Setting 0 1 1 2 * *

System Backup 0F Indexed String G37 40416 Enabled Setting 0 1 1 2 * *

Overcurrent 10 Indexed String G37 40417 Enabled Setting 0 1 1 2 * * *

Thermal Overload 11 Indexed String G37 40433 Disabled Setting 0 1 1 2 * * *

NOT USED 12

Earth Fault 13 Indexed String G37 40418 Enabled Setting 0 1 1 2 * * *

NOT USED 14

SEF/REF/SPower 15 Indexed String G114 40419 Disabled Setting 0 2 1 2 *

SEF/REF * *

Residual O/V NVD 16 Indexed String G37 40420 Enabled Setting 0 1 1 2 * * * Residual Overvoltage

100% Stator EF 17 Indexed String G37 40421 Disabled Setting 0 1 1 2 *

V/Hz 18 Indexed String G37 40422 Disabled Setting 0 1 1 2 * *

df/dt 19 Indexed String G37 40423 Enabled Setting 0 1 1 2 *

V Vector Shift 1A Indexed String G37 40424 Disabled Setting 0 1 1 2 *

Dead Machine 1B Indexed String G37 40425 Disabled Setting 0 1 1 2 *

Reconnect Delay 1C Indexed String G37 40426 Disabled Setting 0 1 1 2 *

Volt Protection 1D Indexed String G37 40427 Enabled Setting 0 1 1 2 * * *

Freq Protection 1E Indexed String G37 40428 Enabled Setting 0 1 1 2 * * *

RTD Inputs 1F Indexed String G37 40429 Enabled Setting 0 1 1 2 * *

CB Fail 20 Indexed String G37 40430 Disabled Setting 0 1 1 2 * * *

Supervision 21 Indexed String G37 40431 Disabled Setting 0 1 1 2 * * *

NOT USED 22 NOT USED

NOT USED 23

Pole Slipping 24 Indexed String G37 40432 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 * * *

Recorder Control 29 Indexed String G80 Invisible Setting 0 1 1 1 * * *

Disturb Recorder 2A Indexed String G80 Invisible Setting 0 1 1 1 * * * Disturbance recorder

Measure't Setup 2B Indexed String G80 Invisible 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 * * *

NOT USED 2F

40400 G18 * * *Record selection command register

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Courier

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 * * *

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) G27 40527 40528 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 63 - 32 0B 0C Binary Flag (32 bits) G27 40529 40530 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 95 - 64 0B 0D Binary Flag (32 bits) G27 40531 40532 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 127 - 96 0B 0E Binary Flag (32 bits) G27 40533 40534 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 159 - 128 0B 0F Binary Flag (32 bits) G27 40535 40536 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 191 - 160 0B 10 Binary Flag (32 bits) G27 40537 40538 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *







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Courier




DDB 511 - 480 0B 1A Binary Flag (32 bits) G27 40557 40558 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 543 - 512 0B 1B Binary Flag (32 bits) G27 40559 40560 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 575 - 544 0B 1C Binary Flag (32 bits) G27 40561 40562 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 607 - 576 0B 1D Binary Flag (32 bits) G27 40563 40564 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 639 - 608 0B 1E Binary Flag (32 bits) G27 40565 40566 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *

DDB 671 - 640 0B 1F Binary Flag (32 bits) G27 40567 40568 G27 0xFFFFFFFF Setting 0xFFFFFFFF 32 1 2 * * *











DDB 1022 - 992 0B 2A Binary Flag (32 bits) G27 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

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 * * *



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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 *



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 *


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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 *



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

COMMUNICATIONS 0E 00 * * *

Rear Protocol 01 Indexed String G71 Data * * *

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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

COMMISSION TESTS 0F 00 * * *

Opto I/P Status 01 Binary Flag(16 bits) G8 Data * * *

Indexed String

Relay O/P Status 02 Binary Flag(32 bits) G9 Data * * *

Indexed String

Test Port Status 03 Binary Flag(8 bits) 0-7 Data * * *

Indexed String

LED Status 04 Binary Flag(8 bits) 0-7 0-7 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

Test Pattern 0E Binary Flag (21bits) G9 40859 40860 G9 0 Setting 0 20 1 2 * * * IEC60870 Test Mode Change

Indexed String

Contact Test 0F Indexed String G93 40861 G93 No Operation Command 0 2 1 2 * * * IEC60870 Test Mode Change

Test LEDs 10 Binary Flag (8bits) G94 40862 G94 No Operation Command 0 1 1 2 * * *

Indexed String

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 * * *


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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

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I^ Maintenance 02 Indexed String G88 40152 G88 Alarm Disabled Setting 0 1 1 2 * * *Broken Current to cause maint. 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 * * * CB Trips to cause maint. alarm

No. CB Ops Maint 07 Unsigned Integer 40159 G1 10 Setting 1 10000 1 2 * * *Number of CB Trips for maint. alarm

No. CB Ops Lock 08 Indexed String G88 40160 G88 Alarm Disabled Setting 0 1 1 2 * * * CB Trips to cause lockout alarm

No. CB Ops Lock 09 Unsigned Integer 40161 G1 20 Setting 1 10000 1 2 * * *Number of CB Trips for lockout alarm

CB Time Maint 0A Indexed String G88 40162 G88 Alarm Disabled Setting 0 1 1 2 * * *CB Oper. Time to cause maint. alarm

CB Time Maint 0B Courier Number (Time) 40163 40164 G35 0.1 Setting 0.005 0.5 0.001 2 * * *CB Operating time for maint. alarm

CB Time Lockout 0C Indexed String G88 40165 G88 Alarm Disabled Setting 0 1 1 2 * * *CB Oper. 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 * * *CB 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 7 08 Indexed String G203 40958 G203 No Operation Command 0 2 1 2 * * *Control Input 8 09 Indexed String G203 40959 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 * * *


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GROUP 1 30 00 *

GEN DIFF

GenDiff Function 01 Indexed String G101 41000 G101 Percentage Bias Setting 0 2 1 2 *

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 *

GROUP 1 31 00 * * *

POWER

Power1 Function 01 Indexed String G102 41050 G102 Over Setting 0 3 1 2 *

Reverse * *

-P>1 Setting 02 Courier Number (Power) 41051 G2 20 Setting 14*V1*I1 40*V1*I1 2*V1*I1 2 *

5 4*V1*I1 40*V1*I1 0.5*V1*I1 2 * *

P<1 Setting 03 Courier Number (Power) 41052 G2 20 Setting 14*V1*I1 40*V1*I1 2*V1*I1 2 *

10 4*V1*I1 40*V1*I1 0.5*V1*I1 2 * *

P>1 Setting 04 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 05 Courier Number (Time) 41054 G2 5 Setting 0 100 0.01 2 * * *

Power1 DO Timer 06 Courier Number (Time) 41055 G2 0 Setting 0 100 0.01 2 * * *

P1 Poledead Inh 07 Indexed String G37 41056 G37 Enabled Setting 0 1 1 2 * * *

Power2 Function 08 Indexed String G102 41057 G102 Disabled Setting 0 3 1 2 *

Low Forward * *

-P>2 Setting 09 Courier Number (Power) 41058 G2 20 Setting 14*V1*I1 40*V1*I1 2*V1*I1 2 *

5 4*V1*I1 40*V1*I1 0.5*V1*I1 2 * *

P<2 Setting 0A Courier Number (Power) 41059 G2 20 Setting 14*V1*I1 40*V1*I1 2*V1*I1 2 *

10 4*V1*I1 40*V1*I1 0.5*V1*I1 2 * *

P>2 Setting 0B 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 0C Courier Number (Time) 41061 G2 2 Setting 0 100 0.01 2 * * *

Power2 DO Timer 0D Courier Number (Time) 41062 G2 0 Setting 0 100 0.01 2 * * *

P2 Poledead Inh 0E Indexed String G37 41063 G37 Enabled Setting 0 1 1 2 * * *

GROUP 1 32 00 * *

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 * *

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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 33 00 * *

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 34 00 * *

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 03 Indexed String G111 41202 G111 IEC S Inverse Setting 0 9 1 2 * *

V Dep OC I> Set 04 Courier Number (Current) 41203 G2 1 Setting 0.8*I1 4*I1 0.01*I1 2 * *

V Dep OC T Dial 05 Courier Number (Decimal) 41204 G2 7 Setting 0.5 15 0.1 2 * *

V Dep OC Reset 06 Indexed String 41205 G60 DT Setting 0 1 1 2 * *OC reset characteritic selection. Apply to US curves only.

V Dep OC Delay 07 Courier Number (Time) 41206 G2 1 Setting 0 100 0.01 2 * * Apply to DT trip characteristic only

V Dep OC TMS 08 Courier Number (Decimal) 41207 G2 1 Setting 0.025 1.2 0.025 2 * * 4>=3403>=1

V Dep OC tRESET 09 Courier Number (Time) 41208 G2 0 Setting 0 100 0.01 2 * *(4>=3403>=0 OR 3406=0)&&(3401>1)

V Dep OC V<1 Set 0A Courier Number (Voltage) 41209 G2 80 Setting 20*V1 120*V1 1*V1 2 * *

V Dep OC V<2 Set 0B Courier Number (Voltage) 41210 G2 60 Setting 20*V1 120*V1 1*V1 2 * *

V Dep OC k Set 0C Courier Number (Decimal) 41211 G2 0.25 Setting 0.25 1 0.05 2 * *

Z<1 Setting 0D Courier Number (Impedance) 41212 G2 70 Setting 2*V1/I1 120*V1/I1 0.5*V1/I1 2 * *

Z<1 Time Delay 0E Courier Number (Time) 41213 G2 5 Setting 0 100 0.01 2 * *

Z<1 tRESET 0F Courier Number (Time) 41214 G2 0 Setting 0 100 0.01 2 * *

Z< Stage 2 10 Indexed String G37 41215 G37 Disabled Setting 0 1 1 2 * *Optional 2nd Stage Underimpedance Phase 2.12

Z<2 Setting 11 Courier Number (Impedance) 41216 G2 70 Setting 2*V1/I1 120*V1/I1 0.5*V1/I1 2 * *

Z<2 Time Delay 12 Courier Number (Time) 41217 G2 5 Setting 0 100 0.01 2 * *

Z<2 tRESET 13 Courier Number (Time) 41218 G2 0 Setting 0 100 0.01 2 * *

GROUP 1 35 00 * * *

OVERCURRENT

I>1 Function 01 Indexed String G43 41250 G43 Disabled Setting 0 10 1 2 * *

IEC S Inverse *

I>1 Direction 02 Indexed String G44 41251 G44 Non-Directional Setting 0 2 1 2 *

I>1 Current Set 03 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 04 Courier Number (Time) 41253 G2 1 Setting 0 100 0.01 2 * * * I>1 Definite Time

I>1 TMS 05 Courier Number (Decimal) 41254 G2 1 Setting 0.025 1.2 0.025 2 * * * 5>=3501>=2

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I>1 Time Dial 06 Courier Number (Decimal) 41255 G2 7 Setting 0.5 15 0.1 2 * * *

I>1 Reset Char 07 Indexed String G60 41256 G60 DT Setting 0 1 1 2 * * *

I>1 tRESET 08 Courier Number (Time) 41257 G2 0 Setting 0 100 0.01 2 * * * 5>=3501>=1 OR 3507=0

I>2 Function 09 Indexed String G43 41258 G43 Disabled Setting 0 10 1 2 * I>2 Overcurrent Status

G105 G105 DT 0 1 1 2 * *

I>2 Direction 0A Indexed String G44 41259 G44 Non-Directional Setting 0 2 1 2 *

I>2 Current Set 0B 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 0C Courier Number (Time) 41261 G2 1 Setting 0 100 0.01 2 *

I>2 TMS 0D Courier Number (Decimal) 41262 G2 1 Setting 0.025 1.2 0.025 2 * 5>=3509>=2

I>2 Time Dial 0E Courier Number (Decimal) 41263 G2 7 Setting 0.5 15 0.1 2 *

I>2 Reset Char 0F Indexed String G60 41264 G60 DT Setting 0 1 1 2 *

I>2 tRESET 10 Courier Number (Time) 41265 G2 0 Setting 0 100 0.01 2 * 5>=3509>=1 OR 350F=0

I>3 Status 11 Indexed String G37 41266 G37 Disabled Setting 0 1 1 2 *


I>3 Current Set 13 Courier Number (Current) 41268 G2 20 Setting 0.08*I1 32*I1 0.01*I1 2 *

I>3 Time Delay 14 Courier Number (Time) 41269 G2 0 Setting 0 100 0.01 2 *

I>4 Status 16 Indexed String G37 41270 G37 Disabled Setting 0 1 1 2 *


I>4 Current Set 18 Courier Number (Current) 41272 G2 20 Setting 0.08*I1 32*I1 0.01*I1 2 *

I>4 Time Delay 19 Courier Number (Time) 41273 G2 0 Setting 0 100 0.01 2 *

I> Char Angle 1A Courier Number (Angle) 41274 G2 30 Setting -95 95 1 2 * I> Characteristic Angle

I> Function Link 1B Binary Flag G14 41275 G14 15 Setting 15 4 1 2 *

GROUP 1 36 00 * * *

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 37 00

Not Used

GROUP 1 38 00 * * *

EARTH FAULT

IN Input 01 Indexed String G49 G49 Derived Data *

Measured * *

IN>1 Function 02 Indexed String G43 41400 G43 IEC S Inverse Setting 0 10 1 2 * * *

IN>1 Direction 03 Indexed String G44 41401 G44 Non-Directional Setting 0 2 1 2 *

IN>1 Current 04 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 Time Delay 05 Courier Number (Time) 41403 G2 1 Setting 0 200 0.01 2 * * * I>1 Definite Time

IN>1 TMS 06 Courier Number (Decimal) 41404 G2 1 Setting 0.025 1.2 0.025 2 * * * 5>=3802>=2

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IN>1 Time Dial 07 Courier Number (Decimal) 41405 G2 7 Setting 0.5 15 0.1 2 * * *

IN>1 Reset Char 08 Indexed String G60 41406 G60 DT Setting 0 1 1 2 * * *

IN>1 tRESET 09 Courier Number (Time) 41407 G2 0 Setting 0 100 0.01 2 * * * 5>=3802>=1 OR 3808=0

IN>2 Function 0A Indexed String G43 41408 G43 Disabled Setting 0 10 1 2 *

G105 G105 Disabled 0 1 1 2 * *

IN>2 Direction 0B Indexed String G44 41409 G44 Non-Directional Setting 0 2 1 2 *

IN>2 Current 0C 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 Time Delay 0D Courier Number (Time) 41411 G2 1 Setting 0 200 0.01 2 *

0 * *

IN>2 TMS 0E Courier Number (Decimal) 41412 G2 1 Setting 0.025 1.2 0.025 2 * 5>=380A>=2

IN>2 Time Dial 0F Courier Number (Decimal) 41413 G2 7 Setting 0.5 15 0.1 2 *

IN>2 Reset Char 10 Indexed String G60 41414 G60 DT Setting 0 1 1 2 *

IN>2 tRESET 11 Courier Number (Time) 41415 G2 0 Setting 0 100 0.01 2 * 5>=380A>=1 OR 3810=0

IN>3 Status 12 Indexed String G37 41416 G37 Disabled Setting 0 1 1 2 *


IN>3 Current 14 Courier Number (Current) 41418 G2 0.5 Setting 0.08*I1 32*I1 0.01*I1 2 *

IN>3 Time Delay 15 Courier Number (Time) 41419 G2 0 Setting 0 200 0.01 2 *

IN>4 Status 16 Indexed String G37 41420 G37 Disabled Setting 0 1 1 2 *


IN>4 Current 18 Courier Number (Current) 41422 G2 0.5 Setting 0.08*I1 32*I1 0.01*I1 2 *

IN>4 Time Delay 19 Courier Number (Time) 41423 G2 0 Setting 0 200 0.01 2 *

IN> Func Link 1A Binary Flags G63 41424 G63 15 Setting 15 4 1 2 *

IN> DIRECTIONAL 1B (Sub Heading) 2 *

IN> Char Angle 1C Courier Number(Angle) 41425 G2 -60 Setting -95 95 1 2 *

IN> Pol 1D Indexed String G46 41426 G46 Zero Sequence Setting 0 1 1 2 *

IN> VNpol Input 1E Indexed String G49 41427 G49 Measured Setting 0 1 1 2 *

IN> VNpol Set 1F 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 20 Courier Number (Voltage) 41429 G2 5 Setting 0.5*V1 25*V1 0.5*V1 2 * IN> V2 Polarising Setting

IN> I2pol Set 21 Courier Number (Current) 41430 G2 0.08 Setting 0.08*I1 1*I1 0.01*I1 2 *

GROUP 1 39 00

Not Used

GROUP 1 3A 00 * * *

SEF/REF PROT'N

SEF/REF Options 01 Indexed String G58 41500 G58 SEF Setting 0 4 1 2 * Protection Options

0 7 1 2 * *

ISEF>1 Function 02 Indexed String G43 41501 G43 DT Setting 0 10 1 2 *

G105 G105 0 1 1 * * (3A01<=3) OR (3A01>=6)

ISEF>1 Direction 03 Indexed String G44 41502 G44 Non-Directional Setting 0 2 1 2 * * * ISEF>1 Directionality

ISEF>1 Current 04 Courier Number (Current) 41503 G2 0.05 Setting 0.005*I3 0.1*I3 0.00025*I3 2 * * * ISEF>1 Current Setting

ISEF>1 Delay 05 Courier Number (Time) 41504 G2 1 Setting 0 200 0.01 2 * * * ISEF>1 Definite Time

ISEF>1 TMS 06 Courier Number (Decimal) 41505 G2 1 Setting 0.025 1.2 0.025 2 * 5>=3A02>=2

ISEF>1 Time Dial 07 Courier Number (Decimal) 41506 G2 7 Setting 0.5 15 0.1 2 *

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Courier

ISEF>1 Reset Chr 08 Indexed String G60 41507 G60 DT Setting 0 1 1 2 *

ISEF>1 tRESET 09 Courier Number (Time) 41508 G2 0 Setting 0 100 0.01 2 *(5>=3A02>=1 OR 3A08=0)&&(3A01<=3)

ISEF>2 Function 0A Indexed String G43 41509 G43 Disabled Setting 0 10 1 2 * ISEF>2 Direction 0B Indexed String G44 41510 G44 Non-Directional Setting 0 2 1 2 *ISEF>2 Current 0C Courier Number (Current) 41511 G2 0.05 Setting 0.005*I3 0.1*I3 0.00025*I3 2 *

ISEF>2 Delay 0D Courier Number (Time) 41512 G2 1 Setting 0 200 0.01 2 *

ISEF>2 TMS 0E Courier Number (Decimal) 41513 G2 1 Setting 0.025 1.2 0.025 2 * 5>=3A0A>=2

ISEF>2 Time Dial 0F Courier Number (Decimal) 41514 G2 7 Setting 0.5 15 0.1 2 *

ISEF>2 Reset Chr 10 Indexed String G60 41515 G60 DT Setting 0 1 1 2 *

ISEF>2 tRESET 11 Courier Number (Time) 41516 G2 0 Setting 0 100 0.01 2 *(5>=3A0A>=1 OR 3A10=0)&&(3A01<=3)

ISEF>3 Status 12 Indexed String G37 41517 G37 Disabled Setting 0 1 1 2 *

ISEF>3 Direction 13 Indexed String G44 41518 G44 Non-Directional Setting 0 2 1 2 * ISEF>3 Directionality

ISEF>3 Current 14 Courier Number (Current) 41519 G2 0.4 Setting 0.005*I3 0.8*I3 0.001*I3 2 * ISEF>3 Current Setting

ISEF>3 Delay 15 Courier Number (Time) 41520 G2 0.5 Setting 0 200 0.01 2 * ISEF>3 Definite Time

ISEF>4 Status 16 Indexed String G37 41521 G37 Disabled Setting 0 1 1 2 *

ISEF>4 Direction 17 Indexed String G44 41522 G44 Non-Directional Setting 0 2 1 2 * ISEF>4 Directionality

ISEF>4 Current 18 Courier Number (Current) 41523 G2 0.6 Setting 0.005*I3 0.8*I3 0.001*I3 2 * ISEF>4 Current Setting

ISEF>4 Delay 19 Courier Number (Time) 41524 G2 0.25 Setting 0 200 0.01 2 * ISEF>4 Definite Time

ISEF> Func Link 1A Binary Flags G64 41525 G64 15 Setting 15 4 1 2 * (3A01<=3) OR (3A01>=6)

ISEF DIRECTIONAL 1B (Sub Heading) 2 * * * (3A01<=3) OR (3A01>=6)

ISEF> Char Angle 1C Courier Number(Angle) 41526 G2 90 Setting -95 95 1 2 * * * (3A01<=3) OR (3A01>=6)

ISEF>VNpol Input 1D Indexed String G49 41527 G49 Measured Setting 0 1 1 2 * * * (3A01<=3) OR (3A01>=6)

ISEF> VNpol Set 1E Courier Number (Voltage) 41528 G2 5 Setting 0.5*V1 80*V1 0.5*V1 2 * * * (3A01<=3) OR (3A01>=6)

0.5*V3 80*V3 0.5*V3 * * *Change scaling factor for measured VN

WATTMETRIC SEF 1F (Sub Heading) * * * (3A01=3) OR (3A01=6)

PN> Setting 20 Courier Number (Power) 41529 G2 9 Setting 0.0*V1*I3 20*V1*I3 0.05*V1*I3 2 * * * (3A01=3) OR (3A01=6)

0.0*V3*I3 20*V3*I3 0.05*V3*I3 * * *Change scaling factor for Measured VN

RESTRICTED E/F 21 (Sub Heading) * * * Restricted Earth Fault

IREF> k1 22 Courier Number (Percentage) 41530 G2 20 Setting 0 20 1 2 * * REF K1, applied to L Impedance

IREF> k2 23 Courier Number (Percentage) 41531 G2 150 Setting 0 150 1 2 * * REF K2, applied to L impedance

IREF> Is1 24 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 25 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 26 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 3B 00 * * *

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 * * *

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 * * *

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Courier

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 3C 00 *

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 3D 00 * *

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 3E 00 *

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 3F 00 *

V VECTOR SHIFT

V Shift Status 01 Indexed String G37 41750 G37 Enabled Setting 0 1 1 2 *

V Shift Angle 02 Courier Number (Angle) 41751 G2 10 Setting 2 30 1 2 *

GROUP 1 40 00 *

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 *

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Courier

Dead Mach tDO 05 Courier Number (Time) 41804 G2 0.5 Setting 0 10 0.1 2 *

GROUP 1 41 00 *

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 *

GROUP 1 42 00 * * *

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 70*V1 1*V1 2 * * * Phase-Neutral

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 43 00 * * *

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 * * *

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 * * *

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Courier

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 65 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 65 0.01 2 * * *

F>2 Time Delay 15 Courier Number (Time) 42018 G2 1 Setting 0 100 0.01 2 * * *

GROUP 1 44 00 * *

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 * *

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 * *





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Courier







GROUP 1 45 00 * * *

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 *

GROUP 1 46 00 * * *

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 * * *

CTS Time Delay 0C Courier Number (Time) 42159 G2 5 Setting 0 10 1 2 * * *

GROUP 1 47 00 * * *

SENSITIVE POWER

Comp Angle 01 Courier Number (Angle) 42175 G2 0 Setting -5 5 0.1 2 * * *

Sen Power1 Func 02 Indexed String G102 42176 G102 Reverse Setting 0 3 1 2 * * *

Sen -P>1 Setting 03 Courier Number (Power) 42177 G2 0.5*V1*I3 Setting 0.3*V1*I3 15*V1*I3 0.1*V1*I3 2 * * *

Sen P<1 Setting 04 Courier Number (Power) 42178 G2 0.5*V1*I3 Setting 0.3*V1*I3 15*V1*I3 0.1*V1*I3 2 * * *

Sen P>1 Setting 05 Courier Number (Power) 42179 G2 50*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen Power1 Delay 06 Courier Number (Time) 42180 G2 5 Setting 0 100 0.01 2 * * *

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Courier

Power1 DO Timer 07 Courier Number (Time) 42181 G2 0 Setting 0 100 0.01 2 * * *

P1 PoleDead Inh 08 Indexed String G37 42182 G37 Enabled Setting 0 1 1 2 * * *

Sen Power2 Func 09 Indexed String G102 42183 G102 Low Forward Setting 0 3 1 2 * * *

Sen -P>2 Setting 0A Courier Number (Power) 42184 G2 0.5*V1*I3 Setting 0.3*V1*I3 15*V1*I3 0.1*V1*I3 2 * * *

Sen P<2 Setting 0B Courier Number (Power) 42185 G2 0.5*V1*I3 Setting 0.3*V1*I3 15*V1*I3 0.1*V1*I3 2 * * *

Sen P>2 Setting 0C Courier Number (Power) 42186 G2 50*V1*I3 Setting 0.3*V1*I3 100*V1*I3 0.1*V1*I3 2 * * *

Sen Power2 Delay 0D Courier Number (Time) 42187 G2 2 Setting 0 100 0.01 2 * * *

Power2 DO Timer 0E Courier Number (Time) 42188 G2 0 Setting 0 100 0.01 2 * * *

P2 PoleDead Inh 0F Indexed String G37 42189 G37 Enabled Setting 0 1 1 2 * * *

GROUP 1 48 00

NOT USED

GROUP 1 49 00 *

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 G1 42259 G1 1 Setting 1 20 1 2 *

Zone2 Slip Count 0C Unsigned Integer G1 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 4A 00 * * *

INPUT LABELS

Opto Input 1 01 ASCII Text (16 chars) 42300 42307 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings









Opto Input 10 0A ASCII Text (16 chars) 42372 42379 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Opto Input 11 0B ASCII Text (16 chars) 42380 42387 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Opto Input 12 0C ASCII Text (16 chars) 42388 42395 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Opto Input 13 0D ASCII Text (16 chars) 42396 42403 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Opto Input 14 0E ASCII Text (16 chars) 42404 42411 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Opto Input 15 0F ASCII Text (16 chars) 42412 42419 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings



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Courier








Opto Input 25 19 ASCII Text (16 chars) 42492 42499 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 26 1A ASCII Text (16 chars) 42500 42507 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 27 1B ASCII Text (16 chars) 42508 42515 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 28 1C ASCII Text (16 chars) 42516 42523 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 29 1D ASCII Text (16 chars) 42524 42531 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 30 1E ASCII Text (16 chars) 42532 42539 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 31 1F ASCII Text (16 chars) 42540 42547 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Opto Input 32 20 ASCII Text (16 chars) 42548 42555 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

GROUP 1 4B 00 * * *

OUTPUT LABELS

Relay 1 01 ASCII Text (16 chars) 42556 42563 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings









Relay 10 0A ASCII Text (16 chars) 42628 42635 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Relay 11 0B ASCII Text (16 chars) 42636 42643 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Relay 12 0C ASCII Text (16 chars) 42644 42651 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Relay 13 0D ASCII Text (16 chars) 42652 42659 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Relay 14 0E ASCII Text (16 chars) 42660 42667 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings

Relay 15 0F ASCII Text (16 chars) 42668 42675 G3 ** Setting 32 163 1 2 * * * ** Refer to Default PSL Settings










Relay 25 19 ASCII Text (16 chars) 42748 42755 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Relay 26 1A ASCII Text (16 chars) 42756 42763 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Relay 27 1B ASCII Text (16 chars) 42764 42771 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Relay 28 1C ASCII Text (16 chars) 42772 42779 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

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Courier

Relay 29 1D ASCII Text (16 chars) 42780 42787 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Relay 30 1E ASCII Text (16 chars) 42788 42795 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Relay 31 1F ASCII Text (16 chars) 42796 42803 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

Relay 32 20 ASCII Text (16 chars) 42804 42811 G3 ** Setting 32 163 1 2 * ** Refer to Default PSL Settings

GROUP 1 4C 00 * * 0927=1 AND 091F=1 AND

RTD LABELS 0006="P34????B*"

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 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 Data * * *Product Specific Bit Flags Targetting

Start Elements1 03 Binary Flag (32 Bits) Indexed String 0..31 0..311 bit per elementLSB

String..MSB StringData * * *

Product Specific Bit Flags Targetting

Start Elements2 04 Binary Flag (32 Bits) Indexed String 0..31 0..311 bit per elementLSB


Trip Elements1 05 Binary Flag (32 Bits) Indexed String 0..31 0..311 bit per elementLSB



Trip Elements2 06 Binary Flag (32 Bits) Indexed String 0..31 0..311 bit per elementLSB



Fault Alarms 07 Binary Flag (32 Bits) Indexed String 0..31 0..311 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 *

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Courier

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 * * *

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 label 27 Courier Number (Temperature) Data * *



RTD 4 label 2A Courier Number (Temperature) Data * *

RTD 5 label 2B Courier Number (Temperature) Data * *

RTD 6 label 2C Courier Number (Temperature) Data * *

RTD 7 label 2D Courier Number (Temperature) Data * *

RTD 8 label 2E Courier Number (Temperature) Data * *

RTD 9 label 2F Courier Number (Temperature) Data * *


df/dt 31 Courier Number (Hz/s) Data *

V Vector Shift 32 Courier Number (Angle) Data *

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 (No N/A B2 00

Domain 04 Indexed String G57 PSL Settings Setting 0 1 1 2 * * *

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Courier

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 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 0 0 Samples Data * * *

Reserved for future use 03-1F * * *

RECORDER EXTRACTION 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

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Courier

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 DataNo. of Disturbance Records (0 to 200)

30801 G1 DataOldest Stored Dist. Record (1 to 65535)

30802 G1 DataNumber of Registers in Current Page

30803 30929 G1 DataDisturbance 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 (Hi N/A B5 * * *

Cal Soft Version 01 ASCII text 16 chars * * *

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 (HN/A B6 00 Note: No text in column text * * *

Bus Comms Err Count Front 01 UINT32 * * *

Bus Message Count Front 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 * * *

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Courier

Reset Demand 04 None (Reset Menu Cell) Data(but supports Reset Menu cell) * * *

UNUSED 05 * * *

Block Xfer Ref 06 Menu Cell(2) B200 Data * * *

DIAGNOSTICS (hidden) E0 00 * * *

Enable Column 01 Indexed String G11 G11 0 (No) Setting 0 1 1 2 * * * CPU Load Measurements

CPU Load-Instant 11 Unsigned Integer (32 bits) G25 Data * * *

CPU Load-Average 12 Unsigned Integer (32 bits) G25 Data * * *

CPU Load-Min 13 Unsigned Integer (32 bits) G25 Data * * *

CPU Load-Max 14 Unsigned Integer (32 bits) G25 Data * * *

CPU Load Reset 1F Indexed String G11 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 * * *

UINT32 - 1 31 Unsigned Integer (32 bits) Setting 0 2^32-1 1 2 * * *Debug variables - default: Not used

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) G24 Data * * *





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TYPE VALUE/BIT MASK

G1 UNSIGNED INTEGER

eg. 5678 stored as 5678

G2 NUMERIC SETTING

Modbus value = (relay setting - minimum setting)/step size

G3 ASCII TEXT CHARACTERS

0x00FF Second character

0xFF00 First character

G4 PLANT STATUS (2 REGISTERS)

(Second reg, First Reg)

0x0000,0x0001 CB1 Open (0 = Off, 1 = On)

0x0000,0x0002 CB1 Closed (0 = Off, 1 = On)

0x0000,0x0004 Not Used (0 = Off, 1 = On)

0x0000,0x0008 Not Used (0 = Off, 1 = On)

0x0000,0x0010 Not Used (0 = Off, 1 = On)

0x0000,0x0020 Not Used (0 = Off, 1 = On)

0x0000,0x0040 Not Used (0 = Off, 1 = On)

0x0000,0x0080 Not Used (0 = Off, 1 = On)

0x0000,0x0100 Not Used (0 = Off, 1 = On)

0x0000,0x0200 Not Used (0 = Off, 1 = On)

0x0000,0x0400 Not Used (0 = Off, 1 = On)

0x0000,0x0800 Not Used (0 = Off, 1 = On)

0x0000,0x1000 Not Used (0 = Off, 1 = On)

0x0000,0x2000 Not Used (0 = Off, 1 = On)

0x0000,0x4000 Not Used (0 = Off, 1 = On)

0x0000,0x8000 Not Used (0 = Off, 1 = On)

G5 CONTROL STATUS (2 REGISTERS)

Data Types

DESCRIPTION

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TYPE VALUE/BIT MASK DESCRIPTION


0x0000,0x0001 Not Used (0 = Off, 1 = On)

0x0000,0x0002 Not Used (0 = Off, 1 = On)

0x0000,0x0004 Not Used (0 = Off, 1 = On)

0x0000,0x0008 Not Used (0 = Off, 1 = On)

0x0000,0x0010 Not Used (0 = Off, 1 = On)

0x0000,0x0020 Not Used (0 = Off, 1 = On)

0x0000,0x0040 Not Used (0 = Off, 1 = On)

0x0000,0x0080 Not Used (0 = Off, 1 = On)

0x0000,0x0100 Not Used (0 = Off, 1 = On)

0x0000,0x0200 Not Used (0 = Off, 1 = On)

0x0000,0x0400 Not Used (0 = Off, 1 = On)

0x0000,0x0800 Not Used (0 = Off, 1 = On)

0x0000,0x1000 Not Used (0 = Off, 1 = On)

0x0000,0x2000 Not Used (0 = Off, 1 = On)

0x0000,0x4000 Not Used (0 = Off, 1 = On)

0x0000,0x8000 Not Used (0 = Off, 1 = On)

G6 Record Control Command Register

0 No operation

1 Clear Event records

2 Clear Fault Record

3 Clear Maintenance Records

4 Reset Indications

G7 VTS Indicate/Block

0 Blocking

1 Indication

G8

P341 P342 P343

0x0000,0x0001 Opto 1 Input State (0=Off, 1=On) Opto 1 Input State (0=Off, 1=On) Opto 1 Input State (0=Off, 1=On)


LOGIC INPUT STATUS

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0x0001,0x0000 Opto 17 Input State (0=Off, 1=On)
















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0x8000,0x0000 Not Used Not Used Opto 32 Input State (0=Off, 1=On)

G9

P341 P342 P343

0x0000,0x0001 Relay 1 (0=Off, 1=On) Relay 1 (0=Off, 1=On) Relay 1 (0=Off, 1=On)
















0x0001,0x0000 Relay 17 (0=Off, 1=On)

0x0002,0x0000 Relay 18 (0=Off, 1=On)

0x0004,0x0000 Relay 19 (0=Off, 1=On)

0x0008,0x0000 Relay 20 (0=Off, 1=On)

0x0010,0x0000 Relay 21 (0=Off, 1=On)

0x0020,0x0000 Relay 22 (0=Off, 1=On)

0x0040,0x0000 Relay 23 (0=Off, 1=On)

0x0080,0x0000 Relay 24 (0=Off, 1=On)

0x0100,0x0000 Relay 25 (0=Off, 1=On)

0x0200,0x0000 Relay 26 (0=Off, 1=On)

0x0400,0x0000 Relay 27 (0=Off, 1=On)

RELAY OUTPUT STATUS

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0x0800,0x0000 Relay 28 (0=Off, 1=On)

0x1000,0x0000 Relay 29 (0=Off, 1=On)

0x2000,0x0000 Relay 30 (0=Off, 1=On)

0x4000,0x0000 Relay 31 (0=Off, 1=On)

0x8000,0x0000 Relay 32 (0=Off, 1=On)

G10 SIGNED FIXED POINT NUMBER - 1 DECIMAL PLACE

-3276.8 to 3276.7 e.g. display of temperature

G11 YES/NO

0 No

1 Yes

G12 TIME AND DATE (4 REGISTERS - IEC870 FORMAT)

0x007F First register - Years

0x0FFF Second register - Month of year / Day of month / Day of week

0x9FBF Third Register - Summertime and hours / Validity and minutes

0xFFFF Fourth Register - Milli-seconds

G13 EVENT RECORD TYPE

0 Latched alarm active

1 Latched alarm inactive

2 Self reset alarm active

3 Self reset alarm inactive

4 Relay event

5 Opto event

6 Protection event

7 Platform event

8 Fault logged event

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9 Maintenance record logged event

G14

P341 P342 P343

Bit 0 I>1 VTS Block (0=Non-dir, I=VTS Blk) Not Used Not Used




Bit 4 Not Used Not Used Not Used




G15 DISTURBANCE RECORD INDEX STATUS

0 No Record

1 Un-extracted

2 Extracted

G16 FAULTED PHASE

0x0001 Start A

0x0002 Start B

0x0004 Start C

0x0008 Start N

0x0010 Trip A

0x0020 Trip B

0x0040 Trip C

0x0080 Trip N

G17 IRIG-B STATUS

0 Card not fitted

1 Card failed

2 Signal healthy

3 No signal

G18 Record Selection Command Register (MODBUS)

I> FUNCTION LINK

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0x0000 No Operation

0x0001 Select next event

0x0002 Accept Event

0x0004 Select next Disurbance Record

0x0008 Accept disturbance record

0x0010 Select Next Disturbance record page

G19 LANGUAGE

0 English

1 Francais

2 Deutsch

3 Espanol

G20 (Second reg, First Reg) PASSWORD (2 REGISTERS)

0x0000, 0x00FF First password character

0x0000, 0xFF00 Second password character

0x00FF, 0x0000 Third password character

0xFF00, 0x0000 Fourth password character

NOTE THAT WHEN REGISTERS OF THIS TYPE ARE READ THE SLAVE WILL

ALWAYS INDICATE AN "*" IN EACH CHARACTER POSITION TO PRESERVE

THE PASSWORD SECURITY.

G21 IEC60870 Interface

0 RS485

1 Fibre Optic

G22 PASSWORD CONTROL ACCESS LEVEL

0 Level 0 - Passwords required for levels 1 & 2.

1 Level 1 - Password required for level 2.

2 Level 2 - No passwords required.

G23 Voltage and V/Hz Curve selection

0 Disabled

1 DT

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2 IDMT

G24 2 REGISTERS UNSIGNED LONG VALUE, 3 DECIMAL PLACES

High order word of long stored in 1st register

Low order word of long stored in 2nd register

Example 123456.789 stored as 123456789

G25 1 REGISTER UNSIGNED VALUE, 3 DECIMAL PLACES

Example 50.050 stored as 50050

G26 RELAY STATUS

0x0001 Out of Service

0x0002 Minor self test failure

0x0004 Event

0x0008 Time Synchronisation

0x0010 DISTURB Flag

0x0020 Fault

0x0040 Unused

0x0080 Unused

0x0100 Unused

0x0200 Unused

0x0400 Unused

0x0800 Unused

0x1000 Unused

0x2000 Unused

0x4000 Unused

0x8000 Unused

G27 2 REGISTERS UNSIGNED LONG VALUE

High order word of long stored in 1st register

Low order word of long stored in 2nd register

Example 123456 stored as 123456

G28 1 REGISTER SIGNED VALUE POWER & WATT-HOURS

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Power = (Secondary power/CT secondary) * (100/VT secondary)

G29 3 REGISTER POWER MULTIPLER

All power measurments use a signed value of type G28 and a

2 register unsigned long multiplier of type G27

Value = Real Value*110/(CTsecondary*VTsecondary)

For Primary Power Multipler = CTprimary * VTprimary/110

For Secondary Power Multipler = CTsecondary * VTsecondary/110

G30 1 REGISTER SIGNED VALUE, 2 DECIMAL PLACES

G31 ANALOGUE CHANNEL ASSIGNMENT SELECTOR

P341 P342 P343

0 VAN VAN VAN

1 VBN VBN VBN

2 VCN VCN VCN

3 VN VN VN

4 IA IA IA-1

5 IB IB IB-1

6 IC IC IC-1

7 IN Sensitive IN IN

8 IN Sensitive IN Sensitive

9 IA-2

10 IB-2

11 IC-2

G32

P341 P342 P343

0 Unused Unused Unused

1 R1 IN>1 Start R1 Trip CB R1 Trip CB

2 R2 I>1 Start R2 Trip PrimeMov R2 Trip PrimeMov

3 R3 Any Trip R3 Any Trip R3 Any Trip

4 R4 General Alarm R4 General Alarm R4 General Alarm

5 R5 CB Fail R5 CB Fail R5 CB Fail

DIGITAL CHANNEL ASSIGNMENT SELECTOR

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6 R6 Control Close R6 E/F trip R6 E/F Trip

7 R7 Control Trip R7 V or F Trip R7 Volt Trip

8 R8 Not Used R8 Not Used R8 Freq Trip

9 R9 Not Used R9 Not Used R9 Diff Trip

10 R10 Not Used R10 Not Used R10 SysBack Trip

11 R11 Not Used R11 Not Used R11 NPS Trip

12 R12 Not Used R12 Not Used R12 Ffail Trip

13 R13 Not Used R13 Not Used R13 Power trip

14 R14 Not Used R14 Not Used R14 V/Hz trip

15 R15 Not Used R15 Not Used R15 Not Used










25 L1 Setting group L1 Setting Group R25 Not Used

26 L2 Setting group L2 Setting Group R26 Not Used

27 L3 Block IN>3&4 L3 Block IN>2 R27 Not Used

28 L4 Block I> 3&4 L4 Block I>2 R28 Not Used

29 L5 Reset L5 Reset R29 Not Used

30 L6 Ext Prot Trip L6 Ext Prot Trip R30 Not Used

31 L7 52a L7 52a R31 Not Used

32 L8 52b L8 52b R32 Not Used

33 L9 Not Used L9 Not Used L1 Setting Group

34 L10 Not Used L10 Not Used L2 Setting Group

35 L11 Not Used L11 Not Used L3 Block IN>2

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36 L12 Not Used L12 Not Used L4 Block I>2

37 L13 Not Used L13 Not Used L5 Reset

38 L14 Not Used L14 Not Used L6 Ext Prot Trip

39 L15 Not Used L15 Not Used L7 52a

40 L16 Not Used L16 Not Used L8 52b

41 L17 Not Used L17 Not Used L9 Not Used








49 LED 1 LED 1 L17 Not Used








57 SG-opto Invalid SG-opto Invalid L25 Not Used

58 Prot'n Disabled Prot'n Disabled L26 Not Used

59 VT Fail Alarm VT Fail Alarm L27 Not Used

60 CT Fail Alarm CT Fail Alarm L28 Not Used

61 CB Fail Alarm CB Fail Alarm L29 Not Used

62 I^ Maint Alarm I^ Maint Alarm L30 Not Used

63 I^ Lockout Alarm I^ Lockout Alarm L31 Not Used

64 CB Ops Maint CB Ops Maint L32 Not Used

65 CB Ops Lockout CB Ops Lockout LED 1

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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 User Alarm 1 RTD Thermal Alm CB Fail Alarm

78 User Alarm 2 RTD Open Cct I^ Maint Alarm

79 User Alarm 3 RTD short Cct I^ Lockout Alarm

80 df/dt Trip RTD Data Error CB Ops Maint

81 V Shift Trip RTD Board Fail CB Ops Lockout

82 IN>1 Trip Freq Prot Alm CB Op Time Maint

83 IN>2 Trip Voltage Prot Alm CB Op Time Lock

84 IN>3 Trip User Alarm 1 Fault Freq Lock

85 IN>4 Trip User Alarm 2 CB Status Alarm

86 IREF> Trip User Alarm 3 Man CB Trip Fail

87 ISEF>1 Trip Field Fail1 Trip Man CB Cls Fail

88 ISEF>2 Trip Field Fail2 Trip Man CB Unhealthy

89 ISEF>3 Trip NPS Trip NPS Alarm

90 ISEF>4 Trip V Dep OC Trip Thermal Alarm

91 VN>1 Trip V Dep OC Trip A V/Hz Alarm

92 VN>2 Trip V Dep OC Trip B Field Fail Alarm

93 V<1 Trip V Dep OC Trip C RTD Thermal Alm

94 V<1 Trip A/AB V/Hz Trip RTD Open Cct

95 V<1 Trip B/BC RTD 1 Trip RTD short Cct

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96 V<1 Trip C/CA RTD 2 Trip RTD Data Error

97 V<2 Trip RTD 3 Trip RTD Board Fail

98 V<2 Trip A/AB RTD 4 Trip Freq Prot Alm

99 V<2 Trip B/BC RTD 5 Trip Voltage Prot Alm

100 V<2 Trip C/CA RTD 6 Trip User Alarm 1

101 V>1 Trip RTD 7 Trip User Alarm 2

102 V>1 Trip A/AB RTD 8 Trip User Alarm 3

103 V>1 Trip B/BC RTD 9 Trip 100% ST EF Trip

104 V>1 Trip C/CA RTD 10 Trip DeadMachine Trip

105 V>2 Trip Any RTD Trip Gen Diff Trip

106 V>2 Trip A/AB IN>1 Trip Gen Diff Trip A

107 V>2 Trip B/BC IN>2 Trip Gen Diff Trip B

108 V>2 Trip C/CA IREF> Trip Gen Diff Trip C

109 F<1 Trip ISEF>1 Trip Field Fail1 Trip

110 F<2 Trip VN>1 Trip Field Fail2 Trip

111 F<3 Trip VN>2 Trip NPS Trip

112 F<4 Trip V<1 Trip V Dep OC Trip

113 F>1 Trip V<1 Trip A/AB V Dep OC Trip A

114 F>2 Trip V<1 Trip B/BC V Dep OC Trip B

115 Power1 Trip V<1 Trip C/CA V Dep OC Trip C

116 Power2 Trip V<2 Trip V/Hz Trip

117 I>1 Trip V<2 Trip A/AB RTD 1 Trip

118 I>1 Trip A V<2 Trip B/BC RTD 2 Trip

119 I>1 Trip B V<2 Trip C/CA RTD 3 Trip

120 I>1 Trip C V>1 Trip RTD 4 Trip

121 I>2 Trip V>1 Trip A/AB RTD 5 Trip

122 I>2 Trip A V>1 Trip B/BC RTD 6 Trip

123 I>2 Trip B V>1 Trip C/CA RTD 7 Trip

124 I>2 Trip C V>2 Trip RTD 8 Trip

125 I>3 Trip V>2 Trip A/AB RTD 9 Trip

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126 I>3 Trip A V>2 Trip B/BC RTD 10 Trip

127 I>3 Trip B V>2 Trip C/CA Any RTD Trip

128 I>3 Trip C F<1 Trip IN>1 Trip

129 I>4 Trip F<2 Trip IN>2 Trip

130 I>4 Trip A F<3 Trip IREF> Trip

131 I>4 Trip B F<4 Trip ISEF>1 Trip

132 I>4 Trip C F>1 Trip VN>1 Trip

133 Bfail1 Trip 3ph F>2 Trip VN>2 Trip

134 Bfail2 Trip 3ph Power1 Trip V<1 Trip

135 SPower1 Trip Power2 Trip V<1 Trip A/AB

136 SPower2 Trip I>1 Trip V<1 Trip B/BC

137 Thermal O/L Trip I>1 Trip A V<1 Trip C/CA

138 Any Start I>1 Trip B V<2 Trip

139 VN>1 Start I>1 Trip C V<2 Trip A/AB

140 VN>2 Start I>2 Trip V<2 Trip B/BC

141 V<1 Start I>2 Trip A V<2 Trip C/CA

142 V<1 Start A/AB I>2 Trip B V>1 Trip

143 V<1 Start B/BC I>2 Trip C V>1 Trip A/AB

144 V<1 Start C/CA Bfail1 Trip 3ph V>1 Trip B/BC

145 V<2 Start Bfail2 Trip 3ph V>1 Trip C/CA

146 V<2 Start A/AB SPower1 Trip V>2 Trip

147 V<2 Start B/BC SPower2 Trip V>2 Trip A/AB

148 V<2 Start C/CA Thermal O/L Trip V>2 Trip B/BC

149 V>1 Start Z<1 Trip V>2 Trip C/CA

150 V>1 Start A/AB Z<1 Trip A F<1 Trip

151 V>1 Start B/BC Z<1 Trip B F<2 Trip

152 V>1 Start C/CA Z<1 Trip C F<3 Trip

153 V>2 Start Z<2 Trip F<4 Trip

154 V>2 Start A/AB Z<2 Trip A F>1 Trip

155 V>2 Start B/BC Z<2 Trip B F>2 Trip

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P341/EN GC/D22

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156 V>2 Start C/CA Z<2 Trip C Power1 Trip

157 Power1 Start Any Start Power2 Trip

158 Power2 Start VN>1 Start I>1 Trip

159 I>1 Start VN>2 Start I>1 Trip A

160 I>1 Start A V<1 Start I>1 Trip B

161 I>1 Start B V<1 Start A/AB I>1 Trip C

162 I>1 Start C V<1 Start B/BC I>2 Trip

163 I>2 Start V<1 Start C/CA I>2 Trip A

164 I>2 Start A V<2 Start I>2 Trip B

165 I>2 Start B V<2 Start A/AB I>2 Trip C

166 I>2 Start C V<2 Start B/BC Bfail1 Trip 3ph

167 I>3 Start V<2 Start C/CA Bfail2 Trip 3ph

168 I>3 Start A V>1 Start SPower1 Trip

169 I>3 Start B V>1 Start A/AB SPower2 Trip

170 I>3 Start C V>1 Start B/BC PSlipz Z1 Trip

171 I>4 Start V>1 Start C/CA PSlipz Z2 Trip

172 I>4 Start A V>2 Start Thermal O/L Trip

173 I>4 Start B V>2 Start A/AB Z<1 Trip

174 I>4 Start C V>2 Start B/BC Z<1 Trip A

175 IN>1 Start V>2 Start C/CA Z<1 Trip B

176 IN>2 Start Power1 Start Z<1 Trip C

177 IN>3 Start Power2 Start Z<2 Trip

178 IN>4 Start I>1 Start Z<2 Trip A

179 ISEF>1 Start I>1 Start A Z<2 Trip B

180 ISEF>2 Start I>1 Start B Z<2 Trip C

181 ISEF>3 Start I>1 Start C Any Start

182 ISEF>4 Start I>2 Start VN>1 Start

183 F<1 Start I>2 Start A VN>2 Start

184 F<2 Start I>2 Start B V<1 Start

185 F<3 Start I>2 Start C V<1 Start A/AB

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P341/EN GC/D22

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186 F<4 Start IN>1 Start V<1 Start B/BC

187 F>1 Start IN>2 Start V<1 Start C/CA

188 F>2 Start ISEF>1 Start V<2 Start

189 I> BlockStart F<1 Start V<2 Start A/AB

190 IN/SEF>Blk Start F<2 Start V<2 Start B/BC

191 df/dt Start F<3 Start V<2 Start C/CA

192 IA< Start F<4 Start V>1 Start

193 IB< Start F>1 Start V>1 Start A/AB

194 IC< Start F>2 Start V>1 Start B/BC

195 ISEF< Start IA< Start V>1 Start C/CA

196 SPower1 Start IB< Start V>2 Start

197 SPower2 Start IC< Start V>2 Start A/AB

198 VTS Fast Block ISEF< Start V>2 Start B/BC

199 VTS Slow Block IN< Start V>2 Start C/CA

200 CTS Block V/Hz Start Power1 Start

201 Control Trip FFail1 Start Power2 Start

202 Control Close FFail2 Start I>1 Start

203 Close in Prog V Dep OC Start I>1 Start A

204 Reconnection V Dep OC Start A I>1 Start B

205 Lockout Alarm V Dep OC Start B I>1 Start C

206 CB Open 3 ph V Dep OC Start C I>2 Start

207 CB Closed 3 ph SPower1 Start I>2 Start A

208 Field volts fail SPower2 Start I>2 Start B

209 All Poles Dead Z<1 Start I>2 Start C

210 Any Pole Dead Z<1 Start A IN>1 Start

211 Pole Dead A Z<1 Start B IN>2 Start

212 Pole Dead B Z<1 Start C ISEF>1 Start

213 Pole Dead C Z<2 Start 100% ST EF Start

214 Z<2 Start A F<1 Start

215 Z<2 Start B F<2 Start

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P341/EN GC/D22

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216 Z<2 Start C F<3 Start

217 VTS Fast Block F<4 Start

218 VTS Slow Block F>1 Start

219 CTS Block F>2 Start

220 RTD 1 Alarm IA< Start

221 RTD 2 Alarm IB< Start

222 RTD 3 Alarm IC< Start

223 RTD 4 Alarm ISEF< Start

224 RTD 5 Alarm IN< Start

225 RTD 6 Alarm V/Hz Start

226 RTD 7 Alarm FFail1 Start

227 RTD 8 Alarm FFail2 Start

228 RTD 9 Alarm V Dep OC Start

229 RTD 10 Alarm V Dep OC Start A

230 Lockout Alarm V Dep OC Start B

231 CB Open 3 ph V Dep OC Start C

232 CB Closed 3 ph SPower1 Start

233 Field volts fail SPower2 Start

234 All Poles Dead PSlipz Z1 Start

235 Any Pole Dead PSlipz Z2 Start

236 Pole Dead A PSlipz LensStart

237 Pole Dead B PSlipz BlindStrt

238 Pole Dead C PSlipz ReactStrt

239 Z<1 Start

240 Z<1 Start A

241 Z<1 Start B

242 Z<1 Start C

243 Z<2 Start

244 Z<2 Start A

245 Z<2 Start B

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P341/EN GC/D22

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246 Z<2 Start C

247 VTS Fast Block

248 VTS Slow Block

249 CTS Block

250 RTD 1 Alarm

251 RTD 2 Alarm

252 RTD 3 Alarm

253 RTD 4 Alarm

254 RTD 5 Alarm

255 RTD 6 Alarm

256 RTD 7 Alarm

257 RTD 8 Alarm

258 RTD 9 Alarm

259 RTD 10 Alarm

260 Lockout Alarm

261 CB Open 3 ph

262 CB Closed 3 ph

263 Field volts fail

264 All Poles Dead

265 Any Pole Dead

266 Pole Dead A

267 Pole Dead B

268 Pole Dead C

G33 Not Used

G34 TRIGGER MODE

0 Single

1 Extended

G35 Numeric Setting (as G2 but 2 registers)

Number of steps from minimum value

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P341/EN GC/D22

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expressed as 2 register 32 bit unsigned int

G36 REAL NUMBERS

0 Polar

1 Rectangular

G37 ENABLED / DISABLED

0 Disabled

1 Enabled

G38m COMMUNICATION BAUD RATE (MODBUS)

0 9600 bits/s

1 19200 bits/s

2 38400 bits/s

G38v COMMUNICATION BAUD RATE (IEC 60870)

0 9600 bits/s

1 19200 bits/s

G38d COMMUNICATION BAUD RATE (DNP 3.0)

0 1200 bits/s

1 2400 bits/s

2 4800 bits/s

3 9600 bits/s

4 19200 bits/s

5 38400 bits/s

G39 COMMUNICATIONS PARITY

0 Odd

1 Even

2 None

G40 CHECK SYNC INPUT SELECTION

0 A-N

1 B-N

2 C-N

3 A-B

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P341/EN GC/D22

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4 B-C

5 C-A

G41 CHECK SYNC VOLTAGE BLOCKING

0 None

1 Undervoltage

2 Differential

3 Both

G42 CHECK SYNC SLIP CONTROL

0 None

1 Timer

2 Frequency

3 Both

G43 IDMT CURVE TYPE

0 Disabled

1 DT

2 IEC S Inverse

3 IEC V Inverse

4 IEC E Inverse

5 UK LT Inverse

6 IEEE M Inverse

7 IEEE V Inverse

8 IEEE E Inverse

9 US Inverse

10 US ST Inverse

G44 DIRECTION

0 Non-Directional

1 Directional Fwd

2 Directional Rev

G45 VTS BLOCK

0 Block

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P341/EN GC/D22

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1 Non-Directional

G46 POLARISATION

0 Zero Sequence

1 Neg Sequence

G47 MEASURING MODE

0 Phase-Phase

1 Phase-Neutral

G48 OPERATION MODE

0 Any Phase

1 Three Phase

G49 VN OR IN INPUT

0 Measured

1 Derived

G50 RTD SELECT

0x0001 RTD Input #1

0x0002 RTD Input #2

0x0004 RTD Input #3

0x0008 RTD Input #4

0x0010 RTD Input #5

0x0020 RTD Input #6

0x0040 RTD Input #7

0x0080 RTD Input #8

0x0100 RTD Input #9

0x0200 RTD Input #10

G51 FAULT LOCATION

0 Distance

1 Ohms

2 % of Line

G52 DEFAULT DISPLAY

0 3Ph + N Current

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P341/EN GC/D22

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1 3 Ph-neutral Voltage

2 Power

3 Date and Time

4 Description

5 Plant Reference

6 Frequency

7 Access Level

G53 SELECT FACTORY DEFAULTS

0 No Operation

1 All Settings

2 Setting Group 1

3 Setting Group 2

4 Setting Group 3

5 Setting Group 4

G54 SELECT PRIMARY SECONDARY MEASUREMENTS

0 Primary

1 Secondary

G55 CIRCUIT BREAKER CONTROL

0 No Operation

1 Trip

2 Close

G56 PHASE MEASUREMENT REFERENCE

0 VA

1 VB

2 VC

3 IA

4 IB

5 IC

G57 Data Transfer Domain

0 PSL Settings

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P341/EN GC/D22

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1 PSL Configuration

G58

P341 P342 P343

0 SEF SEF SEF

1 SEF cos(PHI) SEF cos(PHI) SEF cos(PHI)

2 SEF sin (PHI) SEF sin (PHI) SEF sin (PHI)

3 Wattmetric Wattmetric Wattmetric

4 Hi Z REF Hi Z REF Hi Z REF

5 Lo Z REF Lo Z REF

6 Lo Z REF+SEF Lo Z REF+SEF

7 Lo Z REF+Wattmet Lo Z REF+Wattmet

G59 BATTERY STATUS

0 Dead

1 Healthy

G60 Time Delay Selection

0 DT

1 Inverse

G61 ACTIVE GROUP CONTROL

0 Select via Menu

1 Select via Opto

G62 SAVE AS

0 No Operation

1 Save

2 Abort

G63

P341 P342 P343

Bit 0 IN>1 VTS Block(0=Non-dir, 1=VTS blk) Not Used Not Used




SEF/REF SELECTION

IN> Function Link

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P341/EN GC/D22

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G64

P341 P342 P343

Bit 0 ISEF>1 VTS Block(0=Non-dir,1=Block) ISEF>1 VTS Block(0=Non-dir,1=Block) ISEF>1 VTS Block(0=Non-dir,1=Block)

Bit 1 ISEF>2 VTS Block(0=Non-dir,1=Block) Not Used Not Used







G65 F< Function Link

Bit 0 F<1 Poledead Blk




Bit 4 Not Used

Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G66 DISTURBANCE RECORDER DIGITAL CHANNEL TRIGGER

0 No Trigger

1 Trigger L/H

2 Trigger H/L

G67 THERMAL OVERLOAD

0 Single

ISEF> Func Link

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P341/EN GC/D22

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1 Dual

G68 CB Fail Reset Options

0 I< Only

1 CB Open & I<

2 Prot Reset & I<

G69 VTS RESET MODE

0 Manual

1 Auto

G70 AUTORECLOSE MODE

0 Opto set

1 Auto

2 User Set

3 Pulse Set

G71 PROTOCOL

0 Courier

1 IEC870-5-103

2 Modbus

3 DNP 3.0

G72 START DEAD TIME

0 Protection Reset

1 CB Trips

G73 AUTORECLOSE RECLAIM TIME EXTENSION

0 On Prot Start

1 No Operation

G74 RESET LOCKOUT

0 User Interface

1 Select NonAuto

G75 Auto-Reclose after Manual Close

0 Enabled

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P341/EN GC/D22

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1 Inhibited

G76 TRANSFER MODE

0 Prepare Rx

1 Complete Rx

2 Prepare Tx

3 Complete Tx

4 Rx Prepared

5 Tx Prepared

6 OK

7 Error

G77 Auto-Reclose

0 Out of Service

1 In Service

G78 Autoreclose Telecontrol commands

0 No Operation

1 Auto

2 Non-auto

G79 Custom Settings

0 Disabled

1 Basic

2 Complete

G80 Visible/Invisible

0 Invisible

1 Visible

G81 Reset Lockout by

0 User Interface

1 CB Close

G82 Autoreclose Protection blocking

0 No Block

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P341/EN GC/D22

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1 Block Inst Prot

G83 Autoreclose Status

0 Auto Mode

1 Non-auto Mode

2 Live Line

G84 Modbus value+bit pos

(Second reg, First Reg) P341 P342 P343

0x0000,0x0001 General Start

0x0000,0x0002 Start Power1

0x0000,0x0004 Start Power2

0x0000,0x0008 Start FFail1 Start FFail1

0x0000,0x0010 Start FFail2 Start FFail2

0x0000,0x0020 Start V Dep O/C Start V Dep O/C

0x0000,0x0040 Start I>1 Start I>1 Start I>1

0x0000,0x0080 Start I>2 Start I>2 Start I>2

0x0000,0x0100 Start I>3

0x0000,0x0200 Start I>4

0x0000,0x0400 Start IN>1 Start IN>1 Start IN>1

0x0000,0x0800 Start IN>2 Start IN>2 Start IN>2

0x0000,0x1000 Start IN>3

0x0000,0x2000 Start IN>4

0x0000,0x4000 Start ISEF>1 Start ISEF>1 Start ISEF>1

0x0000,0x8000 Start ISEF>2



0x0004,0x0000 Start NVD VN>1

0x0008,0x0000 Start NVD VN>2

0x0010,0x0000 Start 100% ST EF

0x0020,0x0000 Start Sen Power1 Start Sen Power1 Start Sen Power1

0x0040,0x0000 Start Sen Power2 Start Sen Power2 Start Sen Power2

Started Elements (1)

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P341/EN GC/D22

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0x0080,0x0000 Start z PSlip Z1

0x0100,0x0000 Start z PSlip Z2

0x0200,0x0000 Start Z<1 Start Z<1 Start Z<1

0x0400,0x0000 Start Z<1 Start Z<1 Start Z<1

0x0800,0x0000

0x1000,0x0000

0x2000,0x0000

0x4000,0x0000

0x8000,0x0000



0x0000,0x0001 Any Trip Any Trip Any Trip

0x0000,0x0002 Trip Gen Diff Trip Gen Diff

0x0000,0x0004 Trip Power1 Trip Power1 Trip Power1

0x0000,0x0008 Trip Power2 Trip Power2 Trip Power2

0x0000,0x0010 Trip FFail1 Trip FFail1

0x0000,0x0020 Trip FFail2 Trip FFail2

0x0000,0x0040 Trip NPS Trip NPS

0x0000,0x0080 Trip V Dep O/C Trip V Dep O/C

0x0000,0x0100 Trip I>1 Trip I>1 Trip I>1

0x0000,0x0200 Trip I>2 Trip I>2 Trip I>2

0x0000,0x0400 Trip I>3

0x0000,0x0800 Trip I>4

0x0000,0x1000 Trip IN>1 Trip IN>1 Trip IN>1

0x0000,0x2000 Trip IN>2 Trip IN>2 Trip IN>2

0x0000,0x4000 Trip IN>3

0x0000,0x8000 Trip IN>4

0x0001,0x0000 Trip ISEF>1 Trip ISEF>1 Trip ISEF>1

0x0002,0x0000 Trip ISEF>2


Tripped Elements (1)

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P341/EN GC/D22

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0x0010,0x0000 Trip IREF> Trip IREF> Trip IREF>

0x0020,0x0000 Trip NVD VN>1 Trip NVD VN>1 Trip NVD VN>1

0x0040,0x0000 Trip NVD VN>2 Trip NVD VN>2 Trip NVD VN>2

0x0080,0x0000 Trip 100% ST EF

0x0100,0x0000 Trip Dead Mach

0x0200,0x0000 Trip Sen Power1 Trip Sen Power1 Trip Sen Power1

0x0400,0x0000 Trip Sen Power2 Trip Sen Power2 Trip Sen Power2

0x0800,0x0000 Trip z PSlip Z1

0x1000,0x0000 Trip z PSlip Z2

0x2000,0x0000 Trip Thermal O/L Trip Thermal O/L Trip Thermal O/L

0x4000,0x0000 Trip Z<1 Trip Z<1 Trip Z<1

0x8000,0x0000 Trip Z<2 Trip Z<2 Trip Z<2

G86 Bit Description


0x0000,0x0001 Trip V<1 Trip V<1 Trip V<1

0x0000,0x0002 Trip V<2 Trip V<2 Trip V<2

0x0000,0x0004 Trip V< A/AB Trip V< A/AB Trip V< A/AB

0x0000,0x0008 Trip V< B/BC Trip V< B/BC Trip V< B/BC

0x0000,0x0010 Trip V< C/CA Trip V< C/CA Trip V< C/CA

0x0000,0x0020 Trip V>1 Trip V>1 Trip V>1

0x0000,0x0040 Trip V>2 Trip V>2 Trip V>2

0x0000,0x0080 Trip V> A/AB Trip V> A/AB Trip V> A/AB

0x0000,0x0100 Trip V> B/BC Trip V> B/BC Trip V> B/BC

0x0000,0x0200 Trip V> C/CA Trip V> C/CA Trip V> C/CA

0x0000,0x0400 Trip F<1 Trip F<1 Trip F<1




0x0000,0x4000 Trip F>1 Trip F>1 Trip F>1

Tripped Elements (2)

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P341/EN GC/D22

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0x0000,0x8000 Trip F>2 Trip F>2 Trip F>2

0x0001,0x0000 Trip V/Hz Trip V/Hz

0x0002,0x0000 Trip df/dt

0x0004,0x0000 Trip V Shift

0x0008,0x0000 Trip RTD 1 Trip RTD 1










0x2000,0x0000

0x4000,0x0000

0x8000,0x0000

G87 Bit Description Fault Alarms


0x0000,0x0001 CB Fail 1 CB Fail 1 CB Fail 1

0x0000,0x0002 CB Fail 2 CB Fail 2 CB Fail 2

0x0000,0x0004 VTS VTS VTS

0x0000,0x0008 CTS CTS CTS

0x0000,0x0010 Alarm FFail Alarm FFail

0x0000,0x0020 Alarm NPS Alarm NPS

0x0000,0x0040 Alarm V/Hz Alarm V/Hz

0x0000,0x0080 Alarm RTD 1 Alarm RTD 1




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P341/EN GC/D22

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0x0002,0x0000 Alarm Thermal Alarm Thermal Alarm Thermal

0x0004,0x0000

0x0008,0x0000

0x0010,0x0000

0x0020,0x0000

0x0040,0x0000

0x0080,0x0000

0x0100,0x0000

0x0200,0x0000

0x0400,0x0000

0x0800,0x0000

0x1000,0x0000

0x2000,0x0000

0x4000,0x0000

0x8000,0x0000

G88 Alarms

0 Alarm Disabled

1 Alarm Enabled

G89 Main VT Location

0 Line

1 Bus

G90 Group Selection

0 Group 1

1 Group 2

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P341/EN GC/D22

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2 Group 3

3 Group 4

G91 A/R Protection Blocking

0 Allow Tripping

1 Block Tripping

G92 Lockout

0 No Lockout

1 Lockout

G93 Commission Test

0 No Operation

1 Apply Test

2 Remove Test

G94 Commission Test

0 No Operation

1 Apply Test

G95 System Function Links

Bit 0 Trip led self reset (1 = enable self reset)

Bit 1 Not Used

Bit 2 Not Used

Bit 3 Not used

Bit 4 Not Used

Bit 5 Not Used

Bit 6 Not Used

Bit 7 Not Used

G96 Bit Position

P341 P342 P343

0 Battery Fail Battery Fail Battery Fail

1 Field Volt Fail Field Volt Fail Field Volt Fail

2 SG-opto Invalid SG-opto Invalid SG-opto Invalid

3 Prot'n Disabled Prot'n Disabled Prot'n Disabled

Indexed Strings

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P341/EN GC/D22

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4 VT Fail Alarm VT Fail Alarm VT Fail Alarm

5 CTS Fail Alarm CTS Fail Alarm CTS Fail Alarm

6 CB Fail CB Fail CB Fail

7 I^ Maint Alarm I^ Maint Alarm I^ Maint Alarm

8 I^ Maint Lockout I^ Maint Lockout I^ Maint Lockout

9 CB OPs Maint CB OPs Maint CB OPs Maint

10 CB OPs Lock CB OPs Lock CB OPs Lock

11 CB Time Maint CB Time Maint CB Time Maint

12 CB Time Lockout CB Time Lockout CB Time Lockout

13 Fault Freq Lock Fault Freq Lock Fault Freq Lock

14 CB Status Alarm CB Status Alarm CB Status Alarm

15 CB Trip Fail

16 CB Close Fail

17 Man CB Unhealthy

18 F out of Range NPS Alarm NPS Alarm

19 Thermal Alarm Thermal Alarm Thermal Alarm

20 V/Hz Alarm V/Hz Alarm

21 Field Fail Alarm Field Fail Alarm

22 RTD Thermal Alm RTD Thermal Alm

23 RTD Open Cct RTD Open Cct

24 RTD short Cct RTD short Cct

25 RTD Data Error RTD Data Error

26 RTD Board Fail RTD Board Fail

27 Freq Prot Alm Freq Prot Alm Freq Prot Alm

28 Voltage Prot Alm Voltage Prot Alm Voltage Prot Alm

29 User Alarm 1 User Alarm 1 User Alarm 1



G97 Distance Unit

0 Kilometres

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P341/EN GC/D22

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1 Miles

G98 Copy to

0 No Operation

1 Group 1

2 Group 2

3 Group 3

4 Group 4

G99 CB Control

0 Disabled

1 Local

2 Remote

3 Local+Remote

4 Opto

5 Opto+local

6 Opto+Remote

7 Opto+Rem+local

G101 Gen Diff Function Select

0 Disabled

1 Percentage Bias

2 High Impedance

G102 Power Function Select

0 Disabled

1 Reverse

2 Low Forward

3 Over

G103 System Backup Function Select

0 Disabled

1 Underimpedance

2 Volt controlled

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P341/EN GC/D22

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3 Volt restrained

G104 System Backup Vector Rotation

0 None

1 Delta-Star

G105 DEFINITE TIME OVERCURRENT SELECTION

0 Disabled

1 DT



0x0000,0x0001 Start V<1 Start V<1 Start V<1

0x0000,0x0002 Start V<2 Start V<2 Start V<2

0x0000,0x0004 Start V< A/AB Start V< A/AB Start V< A/AB

0x0000,0x0008 Start V< B/BC Start V< B/BC Start V< B/BC

0x0000,0x0010 Start V< C/CA Start V< C/CA Start V< C/CA

0x0000,0x0020 Start V>1 Start V>1 Start V>1

0x0000,0x0040 Start V>2 Start V>2 Start V>2

0x0000,0x0080 Start V> A/AB Start V> A/AB Start V> A/AB

0x0000,0x0100 Start V> B/BC Start V> B/BC Start V> B/BC

0x0000,0x0200 Start V> C/CA Start V> C/CA Start V> C/CA

0x0000,0x0400 Start F<1 Start F<1 Start F<1




0x0000,0x4000 Start F>1 Start F>1 Start F>1

0x0000,0x8000 Start F>2 Start F>2 Start F>2

0x0001,0x0000 Start V/Hz Start V/Hz

0x0002,0x0000 Start df/dt

0x0004,0x0000

0x0008,0x0000

0x0010,0x0000

Started Elements (2)

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P341/EN GC/D22

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0x0020,0x0000

0x0040,0x0000

0x0080,0x0000

0x0100,0x0000

0x0200,0x0000

0x0400,0x0000

0x0800,0x0000

0x1000,0x0000

0x2000,0x0000

0x4000,0x0000

0x8000,0x0000

G108 Bit position RTD Open Circuit Flags

0 RTD 1 label

1 RTD 2 label

2 RTD 3 label

3 RTD 4 label

4 RTD 5 label

5 RTD 6 label

6 RTD 7 label

7 RTD 8 label

8 RTD 9 label

9 RTD 10 label

G109 Bit position RTD Short Circuit Flags

0 RTD 1 label

1 RTD 2 label

2 RTD 3 label

3 RTD 4 label

4 RTD 5 label

5 RTD 6 label

6 RTD 7 label

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P341/EN GC/D22

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7 RTD 8 label

8 RTD 9 label

9 RTD 10 label

G110 Bit position RTD Data Error

0 RTD 1 label

1 RTD 2 label

2 RTD 3 label

3 RTD 4 label

4 RTD 5 label

5 RTD 6 label

6 RTD 7 label

7 RTD 8 label

8 RTD 9 label

9 RTD 10 label

G111 IDMT CURVE TYPE

0 DT

1 IEC S Inverse

2 IEC V Inverse

3 IEC E Inverse

4 UK LT Inverse

5 IEEE M Inverse

6 IEEE V Inverse

7 IEEE E Inverse

8 US Inverse

9 US ST Inverse

G112 100% Stator Earth Fault Protection

0 Disabled

1 VN3H< Enabled

2 VN3H> Enabled

G113 Pole Slipping Operating Mode

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P341/EN GC/D22

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0 Generating

1 Motoring

2 Both

G114 SEF/REF/Spower Selection

0 Disabled

1 SEF/REF

2 Sensitive Power

G118 CB Control Logic Input Assignments

0 None

1 52A

2 52B

3 Both 52A and 52B

G119 TEST MODE

0 Disabled

1 Test Mode

2 Blocked

G125 2 REGISTERS IEEE FLOATING POINT FORMAT

Bit 31 = sign

Bits 30-23 = e7 - e0

Implicit 1.

Bits 22-0 = f22 - f0

G200 Global Opto Nominal Voltage Selection

0 24-27V

1 30-34V

2 48-54V

3 110-125V

4 220-250V

5 Custom

G201 Single Opto Nominal Voltage Selection

0 24-27V

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P341/EN GC/D22

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1 30-34V

2 48-54V

3 110-125V

4 220-250V

G202 Control Input Status (2 REGISTERS)

(2nd Reg, 1st Reg)

0x0000,0x0001 Control Input 1 (0 = Reset, 1 = Set)
























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P341/EN GC/D22

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G203 Virtual Input

0 No Operation

1 Set

2 Reset

G210 CS103 Blocking

0 Disabled

1 Monitor Blocking

2 Command Blocking

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P341/EN GC/D22

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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:

GI

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 *

DDB OrdinalInterpretationModel Number

Earth Fault Indications

Status Indications

System Functions

ASDU TYPE COT FUN Description

Supervision Indications

9600 or 19200bps (User Setting)

Common Address of ASDU = Link Address

Application Layer

Compatible Range Information Numbers in Monitor Direction

IEC60870-5-103: Device ProfileAlstom T&D Ltd., Protection & Control

P340 Generator Protection

INF NO.

P341****3**05**

P342****3**05**

P343****3**05**

Note: Indentification message in ASDU 5: "ALSTOM P" + 16bit model + 8bit major version + 1 character minor version e.g. "ALSTOM P" + 343 + 05 + 'C'

Physical Layer

1 for one protection equipment

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P341/EN GC/D22

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GI

1 2 3 4 5 6DDB OrdinalInterpretation

Model NumberASDU TYPE COT FUN Description

INF NO.

1 1,7,9 224 51 Earth Fault Fwd *

1 1,7,9 224 52 Earth Fault Rev *

Fault Indications

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 *

Measurands

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

* * *

Generic Functions

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

Note unavailable measurands sent as invalid

Auto-Reclose Indications

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P341/EN GC/D22

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GI



INF NO.

GI

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

Test Mode * * * * *

Blocking of monitor direction * * * * *

Disturbance data * * * * *

Generic services * *

Private data * * * * *

Miscellaneous Max. MVAL = times rated value

Measurands

Current L1 *

Current L2 *

Current L3 *

Voltage L1-E *

Voltage L2-E *

Voltage L3-E *

Active Power P *

Reactive Power Q *

Frequency F *

Voltage L1-L2

GI

1 2 3 4 5 6

1 1,7,9 226 0 Contact 1 * * * * Output Relay 1 0








Interpretation DDB Ordinal

Interpretation DDB Ordinal

Generic Functions

Basic Application Functions

2.4

Private Range Information Numbers in Monitor Direction

ASDU TYPE COTModel Number

1.2

Model Number

Compatible Range Information Numbers in Control Direction

ASDU TYPE COT FUN DescriptionINF NO.

System Functions

General Commands

FUN NF NO Description

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P341/EN GC/D22

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GI



INF NO.

















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

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P341/EN GC/D22

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GI



INF NO.








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

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GI



INF NO.

226 117 117

226 118 118

226 119 119

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

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GI



INF NO.


168


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

226 204 204

226 205 205

226 206 206

226 207 207

226 208 208

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GI



INF NO.

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








227 8 264

227 9 265

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P341/EN GC/D22

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GI



INF NO.

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 Alarm

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

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

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P341/EN GC/D22

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GI



INF NO.

1 1,7,9 227 60 Voltage Prot Alm * * * * Voltage protection alarm 316

1 1,7,9 227 61 User Alarm 1 * * * * User settable alarm 1 317



227 64 320

227 65 321

227 66 322

227 67 323

227 68 324

227 69 325

227 70 326

227 71 327

227 72 328

227 73 329

227 74 330

227 75 331

227 76 332

227 77 333

227 78 334

227 79 335

227 80 336

227 81 337

227 82 338

227 83 339

227 84 340

227 85 341

227 86 342

227 87 343

227 88 344

227 89 345

227 90 346

227 91 347

227 92 348

227 93 349

227 94 350

227 95 351

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

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GI



INF NO.

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

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

227 137 393

227 138 394

227 139 395

227 140 396

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

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GI



INF NO.

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

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

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INF NO.

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

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 Stage 1 Trip

495

2 1,7 227 240 SPower2 Trip * * *Sensitive A Phase Power Stage 2 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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 91/158

GI



INF NO.

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

227 252 508

227 253 509

227 254 510

227 255 511

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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 92/158

GI



INF NO.

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

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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 93/158

GI



INF NO.

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

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 Stage 1 Start

643

2 1,7,9 228 132 SPower2 Start * * * *Sensitive A Phase Power Stage 2 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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 94/158

GI



INF NO.

2 1,7,9 228 136 PSlipz BlindStrt * *Pole Slip (impedance) Blinder Start

648

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

228 146 658

228 147 659

228 148 660

228 149 661

228 150 662

228 151 663

228 152 664

228 153 665

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

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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 95/158

GI



INF NO.

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










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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 96/158

GI



INF NO.

1 1,7,9 228 244 Field volts fail * * * * Field Voltage Failure 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

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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 97/158

GI



INF NO.

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
































229 96 GOOSE VIP 1 864

229 97 GOOSE VIP 2 865

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 98/158

GI



INF NO.

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








229 152 Direct Ctrl 1 920



Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 99/158

GI



INF NO.






229 160 PSL Int. 1 * * * PSL Internal Node 1 928




















































Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 100/158

GI



INF NO.












































1 1,7 229 255 Battery Fail * * *

GI

1 2 3 4 5 6

20 20 229 64 Control Input 1 * * * Control Input 832











DDB OrdinalInterpretationDescriptionModel Number

Private Range Information Numbers in Control Direction

ASDU TYPE COT FUNINF NO.

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 101/158

GI



INF NO.






















ACC Standard

0 Global

1 IL1

2 IL2

3 IL3

4 IN

5 VL1E

6 VL2E

7 VL3E

8 VEN

64 -

65 -

66 -

67 -

245 -

Disturbance Data Actual Channel Identifiers

Interpretation

Null Channel

VAN

IA

IB

IC

IN

VBN

VCN

VN

IN Sensitive

IA-2

IB-2

IC-2

SampleTime

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 102/158

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 Input 1 see 4A01 * * *









41 OPTO Opto Input 10 see 4A0A * * *

42 OPTO Opto Input 11 see 4A0B * * *

43 OPTO Opto Input 12 see 4A0C * * *

44 OPTO Opto Input 13 see 4A0D * * *

45 OPTO Opto Input 14 see 4A0E * * *

46 OPTO Opto Input 15 see 4A0F * * *


Digital Data Bus

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 103/158


0123456789ABCDEFP341 P342 P343









56 OPTO Opto Input 25 see 4A19 *

57 OPTO Opto Input 26 see 4A1A *

58 OPTO Opto Input 27 see 4A1B *

59 OPTO Opto Input 28 see 4A1C *

60 OPTO Opto Input 29 see 4A1D *

61 OPTO Opto Input 30 see 4A1E *

62 OPTO Opto Input 31 see 4A1F *

63 OPTO Opto Input 32 see 4A20 *

64 Output Condition Programmable LED 1 LED 1 * * *








72 UNUSED

73 UNUSED

74 UNUSED

75 UNUSED

76 UNUSED

77 UNUSED

78 UNUSED

79 UNUSED

80 PSL Input to LED Output Condition LED Cond IN 1 * * *








88 UNUSED

89 UNUSED

90 UNUSED

91 UNUSED

92 UNUSED

93 UNUSED

94 UNUSED

95 UNUSED

96 UNUSED

97 UNUSED

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 104/158


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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 105/158


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 Input to Relay Output Condition Relay Cond 1 * * *


162 PSL Input to Relay Output Condition Any Trip * * *






















184 PSL Input to Relay Output Condition Relay Cond 25 *








192 UNUSED

193 UNUSED

194 UNUSED

195 UNUSED

196 UNUSED

197 UNUSED

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 106/158


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 Input to Auxiliary Timer 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

Relay Menu Database

MiCOM P341

P341/EN GC/D22

Page 107/158


0123456789ABCDEFP341 P342 P343

248 UNUSED

249 UNUSED

250 UNUSED

251 UNUSED

252 UNUSED

253 UNUSED

254 UNUSED

255 UNUSED

256 Auxiliary Timer Output from Auxiliary Timer 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 Trigger for Fault Recorder Fault REC TRIG * * *

289 UNUSED

290 Group Selection Setting Group via opto invalid Alarm SG-opto Invalid * * *

291 Commission Test Test Mode Enabled Alarm 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 No of CB Ops Maintenance Alarm CB Ops Maint * * *

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P341/EN GC/D22

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0123456789ABCDEFP341 P342 P343

298 CB Monitoring No of CB Ops Maintenance Lockout CB Ops Lockout * * *

299 CB Monitoring Excessive CB Op Time Maintenance Alarm CB Op Time Maint * * *

300 CB Monitoring Excessive CB Op Time Lockout Alarm CB Op Time Lock * * *

301 CB Monitoring Excessive Fault Frequency Lockout Alarm Fault Freq Lock * * *

302 CB Status CB Status Alarm (Invalid CB auxilliary contacts) CB Status Alarm * * *

303 CB Control CB Failed to Trip Alarm Man CB Trip Fail * * *

304 CB Control CB Failed to Close Alarm Man CB Cls Fail * * *

305 CB Control CB Unhealthy on Control Close Alarm 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 PSL User settable alarm 1 User Alarm 1 * * *



320 UNUSED

321 UNUSED

322 UNUSED

323 UNUSED

324 UNUSED

325 UNUSED

326 UNUSED

327 UNUSED

328 UNUSED

329 UNUSED

330 UNUSED

331 UNUSED

332 UNUSED

333 UNUSED

334 UNUSED

335 UNUSED

336 UNUSED

337 UNUSED

338 UNUSED

339 UNUSED

340 UNUSED

341 UNUSED

342 UNUSED

343 UNUSED

344 UNUSED

345 UNUSED

346 UNUSED

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P341/EN GC/D22

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0123456789ABCDEFP341 P342 P343

347 UNUSED

348 UNUSED

349 UNUSED

350 UNUSED

351 UNUSED

352 PSL Block Voltage Dependent time delay VDepOC Timer Blk * *

353 PSL Block Under Impedance time delay UnderZ Timer Blk * *

354 PSL Block Phase O/C 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 4 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 Overload Thermal State Reset ThermalO/L * * *

391 PSL Blocks most IEC60870-5-103 commands Monitor Blocked * * *

392 PSL Blocks IEC60870-5-103 'General Command'. Command Blocked * * *

393 UNUSED

394 UNUSED

395 UNUSED

396 UNUSED

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P341/EN GC/D22

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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 Input To 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 start Field Fail1 Trip * *

423 Field Failure Field failure Stage 2 start Field Fail2 Trip * *

424 NPS Thermal Negative Phase Sequence Trip NPS Trip * *

425 System Backup Voltage Dependent O/C Trip 3ph V Dep OC Trip * *

426 System Backup Voltage Dependent O/C Trip A V Dep OC Trip A * *

427 System Backup Voltage Dependent O/C Trip B V Dep OC Trip B * *

428 System Backup Voltage Dependent O/C 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 df/ft Rate of change of frequency Trip Any RTD Trip * *

440 RTD Thermal Any RTD 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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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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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 Under Impedance Stage 1 Trip 3 Ph Z<1 Trip * *

501 System Backup Under Impedance Stage 1 Trip A Z<1 Trip A * *

502 System Backup Under Impedance Stage 1 Trip B Z<1 Trip B * *

503 System Backup Under Impedance Stage 1 Trip C Z<1 Trip C * *

504 System Backup Under Impedance Stage 2 Trip 3 Ph Z<2 Trip * *

505 System Backup Under Impedance Stage 2 Trip A Z<2 Trip A * *

506 System Backup Under Impedance Stage 2 Trip B Z<2 Trip B * *

507 System Backup Under Impedance Stage 2 Trip C Z<2 Trip C * *

508 UNUSED

509 UNUSED

510 UNUSED

511 UNUSED

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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P341/EN GC/D22

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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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P341/EN GC/D22

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596 Power Power stage 1 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, inhibited by CB Fail I> BlockStart *

629 Over Current IN/ISEF> Blocked O/C Start, inhibited by CB Fail 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 Dependent Overcurrent Start V Dep OC Start * *

640 System Backup Voltage Dependent Overcurrent Start A V Dep OC Start A * *

641 System Backup Voltage Dependent Overcurrent Start B V Dep OC Start B * *

642 System Backup Voltage Dependent 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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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 Under Impedance Stage 1 Start Z<1 Start * *

651 System Backup Under Impedance Stage 1 Start A Z<1 Start A * *

652 System Backup Under Impedance Stage 1 Start B Z<1 Start B * *

653 System Backup Under Impedance Stage 1 Start C Z<1 Start C * *

654 System Backup Under Impedance Stage 2 Start Z<2 Start * *

655 System Backup Under Impedance Stage 2 Start A Z<2 Start A * *

656 System Backup Under Impedance Stage 2 Start B Z<2 Start B * *

657 System Backup Under Impedance Stage 2 Start C Z<2 Start C * *

658 UNUSED

659 UNUSED

660 UNUSED

661 UNUSED

662 UNUSED

663 UNUSED

664 UNUSED

665 UNUSED

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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P341/EN GC/D22

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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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P341/EN GC/D22

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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 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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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 Control Input 1 * * *














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864 UNUSED GOOSE VIP 1
































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P341/EN GC/D22

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0123456789ABCDEFP341 P342 P343

896 UNUSED GOOSE VOP 1








904 UNUSED InterLogic I/P 1








912 UNUSED InterLogic O/P 1








920 UNUSED Direct Ctrl 1








928 PSLINT PSL Internal Node 1 PSL Int. 1 * * *


















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Binary Flag (24 bits) * *

Binary Flag (32 bits) *

Value contains new opto input status

Binary Flag (24 bits) * *

Binary Flag (32 bits) *

Value contains new output contact status

Unsigned integer (32 bits)

Bit position for alarm

Battery Fail ON/OFF Battery Fail 2/3 0022 0 * * *

Field Volt Fail ON/OFF Field Voltage Fail 2/3 0022 1 * * *

SG-opto Invalid ON/OFF Setting Group via opto invalid 2/3 0022 2 * * *

Prot'n Disabled ON/OFF Protection Disabled 2/3 0022 3 * * *

VT Fail Alarm ON/OFF VTS Alarm 2/3 0022 4 * * *

CT Fail Alarm ON/OFF CTS Alarm 2/3 0022 5 * * *

CB Fail Alarm ON/OFF CB Trip Fail Protection 0/1 0022 6 * * *

I^ Maint Alarm ON/OFF Broken Current Maintenance Alarm 2/3 0022 7 * * *

I^ Lockout Alarm ON/OFF Broken Current Lockout Alarm 2/3 0022 8 * * *

CB Ops Maint ON/OFF No of CB Ops Maintenance Alarm 2/3 0022 9 * * *

CB Ops Lockout ON/OFF No of CB Ops Maintenance Lockout 2/3 0022 10 * * *

CB Op Time Maint ON/OFF CB Op Time Maintenance Alarm 2/3 0022 11 * * *

CB Op Time Lock ON/OFF CB Op Time Lockout Alarm 2/3 0022 12 * * *

Fault Freq Lock ON/OFF Excessive Fault Frequency Lockout Alarm 2/3 0022 13 * * *

CB Status Alarm ON/OFF CB Status Alarm 0/1 0022 14 * * *

P343Additional

TextEvent Text Event Description

Modbus Event Type

G13

Courier Cell Ref

Value DDB No. P341 P342

Alarm Events

4 0021

Event Record Data Format

Logic Inputs Changes in opto input status 5 0020

Output Contacts Changes in output contact status


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P343Additional


Modbus Event Type

G13

Courier Cell Ref


Man CB Trip Fail ON/OFF CB Failed to Trip 0/1 0022 15 *

Man CB Cls Fail ON/OFF CB Failed to Close 0/1 0022 16 *

Man CB Unhealthy ON/OFF No Healthy Control Close 0/1 0023 17 *

F out of range ON/OFF Frequency out of range 2/3 0022 18 *

NPS Alarm ON/OFF Negative Phase Sequence Alarm 0/1 0022 18 * *

Thermal Alarm ON/OFF Thermal Overload Alarm 0/1 0023 19 * * *

V/Hz Alarm ON/OFF Volts Per Hz Alarm 0/1 0022 20 * *

Field Fail Alarm ON/OFF Field failure Alarm (Latched) 0/1 0022 21 * *

RTD Thermal Alm ON/OFF RTD thermal Alarm (Latched) 0/1 0022 22 * *

RTD Open Cct ON/OFF RTD open circuit failure (Latched) 0/1 0022 23 * *

RTD short Cct ON/OFF RTD short circuit failure (Latched) 0/1 0022 24 * *

RTD Data Error ON/OFF RTD data inconsistency error (Latched) 0/1 0022 25 * *

RTD Board Fail ON/OFF RTD Board failure (Latched) 0/1 0022 26 * *

Freq Prot Alm ON/OFFUser definable frequency protection alarm (Latched)

0/1 0022 27 * * *

Voltage Prot Alm ON/OFFUser definable voltage protection alarm (Latched)

0/1 0022 28 * * *

User Alarm 1 ON/OFF User Definable Alarm 1 (Latched) 0/1 0022 29 * * *

User Alarm 2 ON/OFF User Definable Alarm 2 (Latched) 0/1 0022 30 * * *

User Alarm 3 ON/OFF User Definable Alarm 3 (Self Reset) 2/3 0022 31 * * *

Unsigned integer (32 bits)

Bit position for event

100% ST EF Trip ON/OFF 100% Stator Earth Fault Trip 6 0F2D 0 416 *

DeadMachine trip ON/OFF Dead machine protection Trip 6 0F2D 1 417 *

Gen Diff Trip ON/OFF Generator Differential trip 3ph 6 0F2D 2 418 *

Gen Diff Trip A ON/OFF Generator Differential Trip A 6 0F2D 3 419 *

Protection Events


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P343Additional


Modbus Event Type

G13

Courier Cell Ref


Gen Diff Trip B ON/OFF Generator Differential Trip B 6 0F2D 4 420 *

Gen Diff Trip C ON/OFF Generator Differential Trip C 6 0F2D 5 421 *

Field Fail1 Trip ON/OFF Field failure Stage 1 Trip 6 0F2D 6 422 * *

Field Fail2 Trip ON/OFF Field failure Stage 2 Trip 6 0F2D 7 423 * *

NPS Trip ON/OFF Negative Phase Sequence Trip 6 0F2D 8 424 * *

V Dep O/C Trip ON/OFF Voltage Dependent Overcurrent Trip 3ph 6 0F2D 9 425 * *

V Dep O/C Trip A ON/OFF Voltage Dependent Overcurrent Trip A 6 0F2D 10 426 * *

V Dep O/C Trip B ON/OFF Voltage Dependent Overcurrent Trip B 6 0F2D 11 427 * *

V Dep O/C Trip C ON/OFF Voltage Dependent Overcurrent Trip C 6 0F2D 12 428 * *

V/Hz Trip ON/OFF Volts per Hz Trip 6 0F2D 13 429 * *

RTD 1 Trip ON/OFF RTD 1 TRIP 6 0F2D 14 430 * *










df/dt Trip ON/OFF Rate of change of frequency Trip 6 0F2D 24 440 *

Any RTD Trip ON/OFF Any RTD Trip 6 0F2D 24 440 * *

V Shift Trip ON/OFF Voltage vector shift trip 6 0F2D 25 441 *

IN>1 Trip ON/OFF 1st Stage EF Trip 6 0F2D 26 442 * * *

IN>2 Trip ON/OFF 2nd Stage EF Trip 6 0F2D 27 443 * * *


M iCO M P341

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P343Additional


Modbus Event Type

G13

Courier Cell Ref


IN>3 Trip ON/OFF 3rd Stage EF Trip 6 0F2D 28 444 *

IN>4 Trip ON/OFF 4th Stage EF Trip 6 0F2D 29 445 *

IREF> Trip ON/OFF REF Trip 6 0F2D 30 446 * * *

ISEF>1 Trip ON/OFF 1st Stage SEF Trip 6 0F2D 31 447 * * *

ISEF>2 Trip ON/OFF 2nd Stage SEF Trip 6 0F2E 0 448 *

ISEF>3 Trip ON/OFF 3rd Stage SEF Trip 6 0F2E 1 449 *

ISEF>4 Trip ON/OFF 4th Stage SEF Trip 6 0F2E 2 450 *

VN>1 Trip ON/OFF 1st Stage Residual O/V Trip 6 0F2E 3 451 * * *

VN>2 Trip ON/OFF 2nd Stage Residual O/V Trip 6 0F2E 4 452 * * *

V<1 Trip ON/OFF 1st Stage Phase U/V Trip 3ph 6 0F2E 5 453 * * *

V<1 Trip A/AB ON/OFF 1st Stage Phase U/V Trip A/AB 6 0F2E 6 454 * * *

V<1 Trip B/BC ON/OFF 1st Stage Phase U/V Trip B/BC 6 0F2E 7 455 * * *

V<1 Trip C/CA ON/OFF 1st Stage Phase U/V Trip C/CA 6 0F2E 8 456 * * *

V<2 Trip ON/OFF 2nd Stage Phase U/V Trip 3ph 6 0F2E 9 457 * * *

V<2 Trip A/AB ON/OFF 2nd Stage Phase U/V Trip A/AB 6 0F2E 10 458 * * *

V<2 Trip B/BC ON/OFF 2nd Stage Phase U/V Trip B/BC 6 0F2E 11 459 * * *

V<2 Trip C/CA ON/OFF 2nd Stage Phase U/V Trip C/CA 6 0F2E 12 460 * * *

V>1 Trip ON/OFF 1st Stage Phase O/V Trip 3ph 6 0F2E 13 461 * * *

V>1 Trip A/AB ON/OFF 1st Stage Phase O/V Trip A/AB 6 0F2E 14 462 * * *

V>1 Trip B/BC ON/OFF 1st Stage Phase O/V Trip B/BC 6 0F2E 15 463 * * *

V>1 Trip C/CA ON/OFF 1st Stage Phase O/V Trip C/CA 6 0F2E 16 464 * * *

V>2 Trip ON/OFF 2nd Stage Phase O/V Trip 3ph 6 0F2E 17 465 * * *

V>2 Trip A/AB ON/OFF 2nd Stage Phase O/V Trip A/AB 6 0F2E 18 466 * * *

V>2 Trip B/BC ON/OFF 2nd Stage Phase O/V Trip B/BC 6 0F2E 19 467 * * *

V>2 Trip C/CA ON/OFF 2nd Stage Phase O/V Trip C/CA 6 0F2E 20 468 * * *


M iCO M P341

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P343Additional


Modbus Event Type

G13

Courier Cell Ref


F<1 Trip ON/OFF Under frequency Stage 1 trip 6 0F2E 21 469 * * *




F>1 Trip ON/OFF Over frequency Stage 1 Trip 6 0F2E 25 473 * * *

F>2 Trip ON/OFF Over frequency Stage 2 Trip 6 0F2E 26 474 * * *

Power1 Trip ON/OFF Power stage 1 trip 6 0F2E 27 475 * * *

Power2 Trip ON/OFF Power stage 2 trip 6 0F2E 28 476 * * *

I>1 Trip ON/OFF 1st Stage O/C Trip 3ph 6 0F2E 29 477 * * *

I>1 Trip A ON/OFF 1st Stage O/C Trip A 6 0F2E 30 478 * * *

I>1 Trip B ON/OFF 1st Stage O/C Trip B 6 0F2E 31 479 * * *

I>1 Trip C ON/OFF 1st Stage O/C Trip C 6 0F2F 0 480 * * *

I>2 Trip ON/OFF 2nd Stage O/C Trip 3ph 6 0F2F 1 481 * * *

I>2 Trip A ON/OFF 2nd Stage O/C Trip A 6 0F2F 2 482 * * *

I>2 Trip B ON/OFF 2nd Stage O/C Trip B 6 0F2F 3 483 * * *

I>2 Trip C ON/OFF 2nd Stage O/C Trip C 6 0F2F 4 484 * * *

I>3 Trip ON/OFF 3rd Stage O/C Trip 3ph 6 0F2F 5 485 *

I>3 Trip A ON/OFF 3rd Stage O/C Trip A 6 0F2F 6 486 *

I>3 Trip B ON/OFF 3rd Stage O/C Trip B 6 0F2F 7 487 *

I>3 Trip C ON/OFF 3rd Stage O/C Trip C 6 0F2F 8 488 *

I>4 Trip ON/OFF 4th Stage O/C Trip 3ph 6 0F2F 9 489 *

I>4 Trip A ON/OFF 4th Stage O/C Trip A 6 0F2F 10 490 *

I>4 Trip B ON/OFF 4th Stage O/C Trip B 6 0F2F 11 491 *

I>4 Trip C ON/OFF 4th Stage O/C Trip C 6 0F2F 12 492 *

Bfail1 Trip 3ph ON/OFF tBF1 Trip 3Ph 6 0F2F 13 493 * * *


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P343Additional


Modbus Event Type

G13

Courier Cell Ref


Bfail2 Trip 3ph ON/OFF tBF2 Trip 3Ph 6 0F2F 14 494 * * *

SPower1 Trip ON/OFF Sensitive A Phase Power Stage 1 Trip 6 0F2F 15 495 * * *

SPower2 Trip ON/OFF Sensitive A Phase Power Stage 2 Trip 6 0F2F 16 496 * * *

PSlipz Z1 Trip ON/OFF Pole Slip (Impedance) Zone1 Trip 6 0F2F 17 497 *

PSlipz Z2 Trip ON/OFF Pole Slip (Impedance) Zone2 Trip 6 0F2F 18 498 *

Thermal O/L Trip ON/OFF Thermal Overload Trip 6 0F2F 19 499 * *

Z<1 Trip ON/OFF Under Impedance Stage 1 Trip 3 Ph 6 0F2F 20 500 * *

Z<1 Trip A ON/OFF Under Impedance Stage 1 Trip A 6 0F2F 21 501 * *

Z<1 Trip B ON/OFF Under Impedance Stage 1 Trip B 6 0F2F 22 502 * *

Z<1 Trip C ON/OFF Under Impedance Stage 1 Trip C 6 0F2F 23 503 * *

Z<2 Trip ON/OFF Under Impedance Stage 2 Trip 3 Ph 6 0F2F 24 504 * *

Z<2 Trip A ON/OFF Under Impedance Stage 2 Trip A 6 0F2F 25 505 * *

Z<2 Trip B ON/OFF Under Impedance Stage 2 Trip B 6 0F2F 26 506 * *

Z<2 Trip C ON/OFF Under Impedance Stage 2 Trip C 6 0F2F 27 507 * *

Any Start ON/OFF Any Start 6 0F32 0 576 * * *

VN>1 Start ON/OFF 1st Stage Residual O/V Start 6 0F32 1 577 * * *

VN>2 Start ON/OFF 2nd Stage Residual O/V Start 6 0F32 2 578 * * *

V<1 Start ON/OFF 1st Stage Phase U/V Start 3ph 6 0F32 3 579 * * *

V<1 Start A/AB ON/OFF 1st Stage Phase U/V Start A/AB 6 0F32 4 580 * * *

V<1 Start B/BC ON/OFF 1st Stage Phase U/V Start B/BC 6 0F32 5 581 * * *

V<1 Start C/CA ON/OFF 1st Stage Phase U/V Start C/CA 6 0F32 6 582 * * *

V<2 Start ON/OFF 2nd Stage Phase U/V Start 3ph 6 0F32 7 583 * * *

V<2 Start A/AB ON/OFF 2nd Stage Phase U/V Start A/AB 6 0F32 8 584 * * *

V<2 Start B/BC ON/OFF 2nd Stage Phase U/V Start B/BC 6 0F32 9 585 * * *

V<2 Start C/CA ON/OFF 2nd Stage Phase U/V Start C/CA 6 0F32 10 586 * * *


M iCO M P341

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P343Additional


Modbus Event Type

G13

Courier Cell Ref


V>1 Start ON/OFF 1st Stage Phase O/V Start 3ph 6 0F32 11 587 * * *

V>1 Start A/AB ON/OFF 1st Stage Phase O/V Start A/AB 6 0F32 12 588 * * *

V>1 Start B/BC ON/OFF 1st Stage Phase O/V Start B/BC 6 0F32 13 589 * * *

V>1 Start C/CA ON/OFF 1st Stage Phase O/V Start C/CA 6 0F32 14 590 * * *

V>2 Start ON/OFF 2nd Stage Phase O/V Start 3ph 6 0F32 15 591 * * *

V>2 Start A/AB ON/OFF 2nd Stage Phase O/V Start A/AB 6 0F32 16 592 * * *

V>2 Start B/BC ON/OFF 2nd Stage Phase O/V Start B/BC 6 0F32 17 593 * * *

V>2 Start C/CA ON/OFF 2nd Stage Phase O/V Start C/CA 6 0F32 18 594 * * *

Power1 Start ON/OFF Power Stage 1 start 6 0F32 19 595 * * *

Power2 Start ON/OFF Power stage 1 start 6 0F32 20 596 * * *

I>1 Start ON/OFF 1st Stage O/C Start 3ph 6 0F32 21 597 * * *

I>1 Start A ON/OFF 1st Stage O/C Start A 6 0F32 22 598 * * *

I>1 Start B ON/OFF 1st Stage O/C Start B 6 0F32 23 599 * * *

I>1 Start C ON/OFF 1st Stage O/C Start C 6 0F32 24 600 * * *

I>2 Start ON/OFF 2nd Stage O/C Start 3ph 6 0F32 25 601 * * *

I>2 Start A ON/OFF 2nd Stage O/C Start A 6 0F32 26 602 * * *

I>2 Start B ON/OFF 2nd Stage O/C Start B 6 0F32 27 603 * * *

I>2 Start C ON/OFF 2nd Stage O/C Start C 6 0F32 28 604 * * *

I>3 Start ON/OFF 3rd Stage O/C Start 3ph 6 0F32 29 605 *

I>3 Start A ON/OFF 3rd Stage O/C Start A 6 0F32 30 606 *

I>3 Start B ON/OFF 3rd Stage O/C Start B 6 0F32 31 607 *

I>3 Start C ON/OFF 3rd Stage O/C Start C 6 0F33 0 608 *

I>4 Start ON/OFF 4th Stage O/C Start 3ph 6 0F33 1 609 *

I>4 Start A ON/OFF 4th Stage O/C Start A 6 0F33 2 610 *

I>4 Start B ON/OFF 4th Stage O/C Start B 6 0F33 3 611 *


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P343Additional


Modbus Event Type

G13

Courier Cell Ref


I>4 Start C ON/OFF 4th Stage O/C Start C 6 0F33 4 612 *

IN>1 Start ON/OFF 1st Stage EF Start 6 0F33 5 613 * * *

IN>2 Start ON/OFF 2nd Stage EF Start 6 0F33 6 614 * * *

IN>3 Start ON/OFF 3rd Stage EF Start 6 0F33 7 615 *

IN>4 Start ON/OFF 4th Stage EF Start 6 0F33 8 616 *

ISEF>1 Start ON/OFF 1st Stage SEF Start 6 0F33 9 617 * * *

ISEF>2 Start ON/OFF 2nd Stage SEF Start 6 0F33 10 618 *

ISEF>3 Start ON/OFF 3rd Stage SEF Start 6 0F33 11 619 *

ISEF>4 Start ON/OFF 4th Stage SEF Start 6 0F33 12 620 *

100% ST EF Start ON/OFF 100% Stator Earth Fault Start 6 0F33 13 621 *

F<1 Start ON/OFF Under frequency Stage 1 START 6 0F33 14 622 * * *




F>1 Start ON/OFF Over frequency Stage 1 START 6 0F33 18 626 * * *

F>2 Start ON/OFF Over frequency Stage 2 START 6 0F33 19 627 * * *

I> BlockStart ON/OFF I> Blocked O/C Start, inhibited by CB Fail 6 0F33 20 628 *

IN/SEF>Blk Start ON/OFFIN/ISEF> Blocked O/C Start, inhibited by CB Fail

6 0F33 21 629 *

df/dt Start ON/OFF Rate of change of frequency Start 6 0F33 22 630 *

IA< Start ON/OFF IA< operate 6 0F33 23 631 * * *

IB< Start ON/OFF IB< operate 6 0F33 24 632 * * *

IC< Start ON/OFF IC< operate 6 0F33 25 633 * * *

ISEF< Start ON/OFF ISEF< operate 6 0F33 26 634 * * *

IN< Start ON/OFF IN< operate 6 0F33 27 635 * *


M iCO M P341

P341/EN GC/D22

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P343Additional


Modbus Event Type

G13

Courier Cell Ref


V/Hz Start ON/OFF Volts per Hz Start 6 0F33 28 636 * *

FFail1 Start ON/OFF Field failure Stage 1 start 6 0F33 29 637 * *

FFail2 Start ON/OFF Field failure Stage 2 start 6 0F33 30 638 * *

V Dep OC Start ON/OFF Voltage Dependent Overcurrent Start 6 0F33 31 639 * *

V Dep OC Start A ON/OFF Voltage Dependent Overcurrent Start A 6 0F34 0 640 * *

V Dep OC Start B ON/OFF Voltage Dependent Overcurrent Start B 6 0F34 1 641 * *

V Dep OC Start C ON/OFF Voltage Dependent Overcurrent Start C 6 0F34 2 642 * *

SPower1 Start ON/OFF Sensitive A Phase Power Stage 1 Start 6 0F34 3 643 * * *

SPower2 Start ON/OFF Sensitive A Phase Power Stage 2 Start 6 0F34 4 644 * * *

PSlipz Z1 Start ON/OFF Pole Slip (Impedance) Zone1 Start 6 0F34 5 645 *

PSlipz Z2 Start ON/OFF Pole Slip (Impedance) Zone2 Start 6 0F34 6 646 *

PSlipz LensStart ON/OFF Pole Slip (impedance) Lens Start 6 0F34 7 647 *

PSlipz BlindStrt ON/OFF Pole Slip (impedance) Blinder Start 6 0F34 8 648 *

PSlipz ReactStrt ON/OFF Pole Slip (impedance) Reactance Line Start 6 0F34 9 649 *

Z<1 Start ON/OFF Under Impedance Stage 1 Start 6 0F34 10 650 * *

Z<1 Start A ON/OFF Under Impedance Stage 1 Start A 6 0F34 11 651 * *

Z<1 Start B ON/OFF Under Impedance Stage 1 Start B 6 0F34 12 652 * *

Z<1 Start C ON/OFF Under Impedance Stage 1 Start C 6 0F34 13 653 * *

Z<2 Start ON/OFF Under Impedance Stage 2 Start 6 0F34 14 654 * *

Z<2 Start A ON/OFF Under Impedance Stage 2 Start A 6 0F34 15 655 * *

Z<2 Start B ON/OFF Under Impedance Stage 2 Start B 6 0F34 16 656 * *

Z<2 Start C ON/OFF Under Impedance Stage 2 Start C 6 0F34 17 657 * *

Control Trip ON/OFF Control Trip 6 0F37 3 739 *

Control Close ON/OFF Control Close 6 0F37 4 740 *

Close in Prog ON/OFF Control Close in Progress 6 0F37 5 741 *


M iCO M P341

P341/EN GC/D22

Page 132/158

P343Additional


Modbus Event Type

G13

Courier Cell Ref


RTD 1 Alarm ON/OFF RTD 1 Alarm 6 0F37 7 743 *










CB Open 3 ph ON/OFF 3 ph CB Open 6 0F37 18 754 * *

CB Closed 3 ph ON/OFF 3 ph CB Closed 6 0F37 19 755 * *

General Events Unsigned integer (32 bits)

Alarms Cleared Relay Alarms Cleared 7 FFFF 0 * * *

Events Cleared Relay Event Records Cleared 7 0B01 1 * * *

Faults Cleared Relay Fault Records Cleared 7 0B02 2 * * *

Maint Cleared Relay Maintenance Records Cleared 7 0B03 3 * * *

PW Unlocked UI Password Unlocked via User Interface 7 0002 4 * * *

PW Invalid UI Invalid Password entered on User Interface 7 0002 5 * * *

PW1 Modified UI Password Level 1 Modified on User Interface 7 0002 6 * * *

PW2 Modified UI Password Level 2 Modified on User Interface 7 0002 7 * * *

PW Expired UI Password unlock expired User Interface 7 0002 8 * * *

PW Unlocked F Password Unlocked via Front Port 7 0002 9 * * *

PW Invalid F Invalid Password entered on Front Port 7 0002 10 * * *

PW1 Modified F Password Level 1 Modified on Front Port 7 0002 11 * * *


M iCO M P341

P341/EN GC/D22

Page 133/158

P343Additional


Modbus Event Type

G13

Courier Cell Ref


PW2 Modified F Password Level 2 Modified on Front Port 7 0002 12 * * *

PW Expired F Password unlock expired Front Port 7 0002 13 * * *

PW Unlocked R Password Unlocked via Rear Port 7 0002 14 * * *

PW Invalid R Invalid Password entered on Rear Port 7 0002 15 * * *

PW1 Modified R Password Level 1 Modified on Rear Port 7 0002 16 * * *

PW2 Modified R Password Level 2 Modified on Rear Port 7 0002 17 * * *

PW Expired R Password unlock expired Rear Port 7 0002 18 * * *

IRIG-B Active IRIG-B Timesync Active (Valid Signal) 7 0805 19 * * *

IRIG-B Inactive IRIG-B Timesync Inactive (No Signal) 7 0805 20 * * *

Time Synch Relay Clock Adjusted 7 0801 21 * * *

C&S Changed Control and Support Settings Changed 7 FFFF 22 * * *

Dist Changed Disturbance Recorder Settings Changed 7 0904 23 * * *

Group 1 Changed Change to Protection Setting Group 1 7 0904 24 * * *




Act Grp Changed Active Group Selection Changed 7 0903 28 * * *

Indication Reset Relay Indications Reset 7 01FF 29 * * *

Power On Relay Powered Up 7 FFFF 30 * * *

Text Fault Recorder Cell Ref Value Record No.

Fault Recorded Fault Records 8 0100 0 B000 16bit UINT

Text Self Monitoring Cell Ref Value Record No.

Maint Recorded Maintenance Records 9 FFFF 0 B100 16bit UINT

Description Continuous P341 P342 P343

Fast W'Dog Error Fast Watchdog Error * * *

Extraction Column

Extraction Column

Maintenance Record Text


M iCO M P341

P341/EN GC/D22

Page 134/158

P343Additional


Modbus Event Type

G13

Courier Cell Ref


Battery Failure Battery Failure * * * *

BBRAM Failure Battery Back RAM Failure * * * *

Field Volt Fail Field Voltage Failure * * * *

Bus Reset Error Bus Error * * *

Slow W'Dog Error Slow Watchdog Error * * *

SRAM Failure Bus SRAM Bus Failure * * * *

SRAM Failure Blk SRAM Block Failure * * * *

FLASH Failure Flash checksum Error * * * *

Code Verify Fail Software Code Verification Failure * * * *

EEPROM Failure EEPROM Failure * * * *

Software Failure Software Error * * * *

Hard Verify Fail Hardware Verification Error * * *

Non Standard General Error * * * *



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Relay Menu D

atabaseP341/EN

GC

/D22

MiC

OM

P341Page 153/158

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MiCOM P341 PROGRAMMABLE SCHEME LOGIC

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External Connection P341/EN CO/D22DiagramsMiCOM P341

EXTERNAL CONNECTIONDIAGRAMS

P341/EN CO/D22 External ConnectionDiagrams

MiCOM P341

External Connection P341/EN CO/D22DiagramsMiCOM P341 Page 1/8

Figure 1: Comms Options MiCOM Px40 Platform


Page 2/8 MiCOM P341

Figure 2: Interconnection Protection Relay (40TE) for Embedded Generation Using VEEConnected VT's (8 I/P & 7 O/P)


Figure 3: Interconnection Protection Relay (40TE) for Embedded Generation(8 I/P & 7 O/P)


Page 4/8 MiCOM P341



Page 6/8 MiCOM P341



Page 8/8 MiCOM P341

Hardware/Software Version P341/EN VC/C22History and CompatibilityMiCOM P341

HARDWARE / SOFTWARE VERSIONHISTORY AND COMPATIBILITY

(Note: Includes versions released and supplied to customers only)

P341/EN VC/C22 Hardware/Software VersionHistory and Compatibility

MiCOM P341

Hardw

are/Software Version

P341/EN VC

/C22

History and C

ompatibility

MiC

OM

P341Page 1 /4

Relay type: P341…..

Backward CompatibilitySoftwareVersion

Date ofIssue Full Description of Changes S1 Compatibility

PSL Setting Files Menu TextFiles

01 11/10/1999 First release to Production V1.09

Refer to manual reference TG8617A for software version 01.

02 19/10/2000 Released to production

DNP 3.0 included

Courier Bay Module compatibilitymodification

Modbus Bay Module compatibilitymodification

Modifications to IEC60870-5-103 TestMode

Poledead logic DDB signals madevisible in PSL

Foreign language text updated

V1.10 OK OK OK

Refer to manual reference P341/EN T/B11 for software version 02.


Includes event filtering

V2 OK OK OK


P341/EN VC

/C22

Hardw


History and C

ompatibility

Page 2/4M

iCO

M P341






Includes sensitive reverse power

Neutral voltage displacementthreshold, VN>1/2, increased from 50to 80 V (100/120 V), 200 to 320(380/480V)

Earth fault polarising voltagethreshold, Vnpol, increased from 22 to88 V(100/120 V) and 88 to 352 V(380/480V)

V2.02a OK OK OK



Includes thermal overload protection

Includes control inputs

Enhancements to IEC60870-5-103builds to include private codes,monitor blocking and disturbancerecord extraction

PSL DDB list of signals increased from512 to 1023 signals

V2.05 X OK X

Hardw


P341/EN VC

/C22

History and C

ompatibility

MiC

OM

P341Page 3 /4





PSL Data menu included with PSLReference information for versionhistory

Optional additional opto inputs andoutput contacts with a larger case sizeoption available

New ‘Universal’ wide ranging optoinputs (Model number suffix B)

New outputput contacts with betterbreak and continuous carry ratings(Model number suffix B)

Refer to manual reference P341/EN T/C22 for software version 05.

P341/EN VC/C22 Hardware/Software VersionHistory and Compatibility

Page 4/4 MiCOM P341

TRANSMISSION & DISTRIBUTION Energy Automation & Information [email protected] www.areva.com

micom p341

Documents

ap ap ap ap ap

amended data

amended figure

voltage protection paragraph

paragraph data

ap ap section page amendments

power protection paragraph

sentences of paragraph