1mrk502016-uen b en application manual generator protection ied reg 670 1.1a

Innovation from ABB

Application manualGenerator protection IEDREG 670

Document ID: 1MRK502016-UENIssued: December 2007

Revision: BIED product version: 1.1

© Copyright 2007 ABB. All rights reserved

COPYRIGHTWE RESERVE ALL RIGHTS TO THIS DOCUMENT, EVEN IN THE EVENTTHAT A PATENT IS ISSUED AND A DIFFERENT COMMERCIALPROPRIETARY RIGHT IS REGISTERED. IMPROPER USE, INPARTICULAR REPRODUCTION AND DISSEMINATION TO THIRDPARTIES, IS NOT PERMITTED.

THIS DOCUMENT HAS BEEN CAREFULLY CHECKED. HOWEVER, INCASE ANY ERRORS ARE DETECTED, THE READER IS KINDLYREQUESTED TO NOTIFY THE MANUFACTURER AT THE ADDRESSBELOW.

THE DATA CONTAINED IN THIS MANUAL IS INTENDED SOLELY FORTHE CONCEPT OR PRODUCT DESCRIPTION AND IS NOT TO BEDEEMED TO BE A STATEMENT OF GUARANTEED PROPERTIES. INTHE INTEREST OF OUR CUSTOMERS, WE CONSTANTLY SEEK TOENSURE THAT OUR PRODUCTS ARE DEVELOPED TO THE LATESTTECHNOLOGICAL STANDARDS. AS A RESULT, IT IS POSSIBLE THATTHERE MAY BE SOME DIFFERENCES BETWEEN THE HW/SWPRODUCT AND THIS INFORMATION PRODUCT.

Manufacturer:

ABB AB

Substation Automation Products

SE-721 59 Västerås

Sweden

Telephone: +46 (0) 21 34 20 00

Facsimile: +46 (0) 21 14 69 18

www.abb.com/substationautomation

Table of contents

Section 1 Introduction.....................................................................11Introduction to the application manual..............................................11

About the complete set of manuals for an IED............................11About the application manual......................................................12Intended audience.......................................................................12Related documents......................................................................13Revision notes.............................................................................13

Section 2 Engineering of the IED...................................................15Introduction.......................................................................................15

The interface between Signal matrix and Configuration tool.......16The configurable LEDs...........................................................17The analog preprocessing function block (SMAI)...................18

Configuration alternatives.................................................................20Adapting a configuration to satisfy special needs.............................21

Signal Matrix Tool (SMT).............................................................21Application configuration tool CAP 531.......................................23

Preparing a specific application configuration of the IED.................23Configuring an IED with CAP531................................................23Using the Signal monitoring tool (SMT).......................................26Using the Event viewer tool.........................................................26

Setting of the IED.............................................................................26Authorization.....................................................................................27

Authorization handling in the tool................................................28Authorization handling in the IED................................................34

Blocking of setting after commissioning of the IED..........................34How to use the configurable logics blocks........................................35Some application ideas....................................................................36

Voltage selection.........................................................................36Fuse failure protection.................................................................37Automatic opening of a transformer disconnector and closingthe ring breakers..........................................................................38Automatic load transfer from bus A to bus B...............................39

Testing of the IED.............................................................................39Engineering checklist........................................................................40

How to use the IED in conjunction with PCM 600 toolbox...........40

Section 3 Requirements.................................................................43Current transformer requirements....................................................43

Current transformer classification................................................43

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Conditions....................................................................................44Fault current................................................................................45Secondary wire resistance and additional load...........................45General current transformer requirements..................................45Rated equivalent secondary e.m.f. requirements........................46

Transformer differential protection.........................................46Current transformer requirements for CTs according to otherstandards.....................................................................................47

Current transformers according to IEC 60044-1,class P, PR.............................................................................47Current transformers according to IEC 60044-1, class PX,IEC 60044-6, class TPS(and old British Standard, class X).........................................48Current transformers according to ANSI/IEEE.......................48

Voltage transformer requirements....................................................49SNTP server requirements...............................................................49

Section 4 IED application...............................................................51General IED application....................................................................51Analog inputs....................................................................................52

Application...................................................................................52Setting guidelines........................................................................52

Setting of the phase reference channel..................................52Setting parameters......................................................................77

Local human-machine interface.......................................................84Human machine interface............................................................84LHMI related functions.................................................................85

Introduction.............................................................................85General setting parameters....................................................85

Indication LEDs...........................................................................85Introduction.............................................................................85Setting parameters.................................................................86

Basic IED functions..........................................................................88Self supervision with internal event list........................................88

Application..............................................................................88Setting parameters.................................................................88

Time synchronization...................................................................89Application..............................................................................89Setting guidelines...................................................................89Setting parameters.................................................................90

Parameter setting groups............................................................94Application..............................................................................94Setting guidelines...................................................................94Setting parameters.................................................................94

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Test mode functionality................................................................95Application..............................................................................95Setting guidelines...................................................................95Setting parameters.................................................................95

IED identifiers..............................................................................96Application..............................................................................96Setting parameters.................................................................97

Rated system frequency (RFR)...................................................97Application..............................................................................97Setting guidelines...................................................................97Setting parameters.................................................................97

Signal matrix for binary inputs (SMBI).........................................97Application..............................................................................97Setting guidelines...................................................................98Setting parameters.................................................................98

Signal matrix for binary outputs (SMBO).....................................98Application..............................................................................98Setting guidelines...................................................................98Setting parameters.................................................................98

Signal matrix for mA inputs (SMMI).............................................98Application..............................................................................98Setting guidelines...................................................................98Setting parameters.................................................................99

Signal matrix for analog inputs (SMAI)........................................99Application..............................................................................99Setting guidelines...................................................................99Setting parameters...............................................................102

Summation block 3 phase (SUM3Ph).......................................104Application............................................................................104Setting guidelines.................................................................104Setting parameters...............................................................105

Authority status (AUTS).............................................................105Application............................................................................105Setting parameters...............................................................106

Goose binary receive.................................................................106Setting parameters...............................................................106

Differential protection......................................................................106Generator differential protection (PDIF, 87G)............................106

Application............................................................................106Setting guidelines.................................................................108Setting parameters...............................................................113

Transformer differential protection (PDIF, 87T).........................115Application............................................................................115

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Setting guidelines.................................................................116Setting example....................................................................123Setting parameters...............................................................135

Restricted earth fault protection (PDIF, 87N)............................141Application............................................................................141Setting guidelines.................................................................147Setting parameters...............................................................149

High impedance differential protection (PDIF, 87).....................150Application............................................................................150Connection examples...........................................................157Setting guidelines.................................................................160Setting parameters...............................................................168

Impedance protection ....................................................................169Full-scheme distance measuring, Mho characteristic, PDIS21...............................................................................................169


Pole slip protection (PPAM, 78).................................................189Application............................................................................190Setting guidelines.................................................................192Setting parameters...............................................................201

Loss of excitation (PDIS, 40).....................................................202Application............................................................................203Setting guidelines.................................................................208Setting parameters...............................................................211

Current protection...........................................................................212Instantaneous phase overcurrent protection (PIOC, 50)...........212


Four step phase overcurrent protection (PTOC, 51_67)...........217Application............................................................................217Setting guidelines.................................................................219Setting parameters...............................................................227

Instantaneous residual overcurrent protection (PIOC, 50N)......233Application............................................................................233Setting guidelines.................................................................234Setting parameters...............................................................236

Four step residual overcurrent protection (PTOC, 51N/67N)...........................................................................................236

Application............................................................................237Setting parameters...............................................................238

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Sensitive directional residual overcurrent and powerprotection (PSDE, 67N) ............................................................245


Thermal overload protection, two time constants (PTTR,49).............................................................................................257

Application............................................................................257Setting guideline...................................................................258Setting parameters...............................................................261

Breaker failure protection (RBRF, 50BF)...................................262Application............................................................................262Setting guidelines.................................................................263Setting parameters...............................................................265

Pole discordance protection (RPLD, 52PD)..............................266Application............................................................................267Setting guidelines.................................................................267Setting parameters...............................................................268

Directional underpower protection (PDUP, 32).........................268Application............................................................................269Setting guidelines.................................................................271Setting parameters...............................................................274

Directional overpower protection (PDOP, 32)...........................275Application............................................................................276Setting guidelines.................................................................278Setting parameters...............................................................281

Voltage protection...........................................................................282Two step undervoltage protection (PTUV, 27)..........................282


Two step overvoltage protection (PTOV, 59)............................289Application............................................................................289Setting guidelines.................................................................290Setting parameters...............................................................293

Two step residual overvoltage protection (PTOV, 59N)............295Application............................................................................296Setting guidelines.................................................................296Setting parameters...............................................................301

Overexcitation protection (PVPH, 24)........................................303Application............................................................................303Setting guidelines.................................................................305Setting parameters...............................................................309

Voltage differential protection (PTOV, 60).................................311

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95% and 100% Stator earthground fault protection based on3rd harmonic .............................................................................315


Rotor earthground fault protection.............................................322Setting guidelines.................................................................322

Frequency protection......................................................................326Underfrequency protection (PTUF, 81).....................................326


Overfrequency protection (PTOF, 81).......................................329Application............................................................................329Setting guidelines.................................................................329Setting parameters...............................................................330

Rate-of-change frequency protection (PFRC, 81).....................330Application............................................................................331Setting guidelines.................................................................331Setting parameters...............................................................332

Multipurpose protection..................................................................332General current and voltage protection (GAPC)........................332


Secondary system supervision.......................................................360Current circuit supervision (RDIF).............................................360


Fuse failure supervision (RFUF)................................................361Application............................................................................362Setting guidelines.................................................................363Setting parameters...............................................................365

Control............................................................................................366Synchronizing, synchrocheck and energizing check (RSYN,25).............................................................................................366

Application............................................................................367Application examples...........................................................371Setting guidelines ................................................................378Setting parameters...............................................................384

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Apparatus control (APC)............................................................386Application............................................................................386Interaction between modules...............................................392Setting guidelines.................................................................394Setting parameters...............................................................396

Interlocking................................................................................399Configuration guidelines.......................................................400Interlocking for line bay (ABC_LINE)....................................400Interlocking for bus-coupler bay (ABC_BC)..........................405Interlocking for transformer bay (AB_TRAFO).....................410Interlocking for bus-section breaker (A1A2_BS)..................412Interlocking for bus-section disconnector (A1A2_DC)..........415Interlocking for busbar earthinggrounding switch(BB_ES)................................................................................423Interlocking for double CB bay (DB).....................................429Interlocking for 1 1/2 CB (BH)..............................................430Horizontal communication via GOOSE for interlocking........432

Logic rotating switch for function selection and LHMIpresentation (SLGGIO)..............................................................432


Selector mini switch (VSGGIO).................................................434Application............................................................................434Setting guidelines.................................................................435Setting parameters...............................................................435

Generic double point function block (DPGGIO).........................435Application............................................................................435Setting guidelines.................................................................436Setting parameters...............................................................436

Single point generic control 8 signals (SPC8GGIO)..................436Application............................................................................436Setting guidelines.................................................................436Setting parameters...............................................................437

Logic...............................................................................................437Tripping logic (PTRC, 94)..........................................................437


Trip matrix logic (GGIO)............................................................443Application............................................................................443Setting guidelines.................................................................444Setting parameters...............................................................444

Configurable logic blocks (LLD).................................................444

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Fixed signal function block (FIXD).............................................446Application............................................................................446Setting parameters...............................................................446

Boolean 16 to Integer conversion B16I.....................................446Application............................................................................446Setting parameters...............................................................447

Boolean 16 to Integer conversion with logic noderepresentation (B16IGGIO).......................................................447


Integer to Boolean 16 conversion (IB16)...................................447Application............................................................................447Setting parameters...............................................................448

Integer to Boolean 16 conversion with logic noderepresentation (IB16GGIO).......................................................448


Monitoring.......................................................................................448Measurements (MMXU)............................................................448


Event counter (GGIO)................................................................474Application............................................................................474Setting parameters...............................................................474

Event function (EV)....................................................................474Application............................................................................475Setting guidelines.................................................................475Setting parameters...............................................................476

Measured value expander block................................................478Application............................................................................478Setting guidelines.................................................................478

Disturbance report (RDRE).......................................................478Application............................................................................479Setting guidelines.................................................................479Setting parameters...............................................................484

Event list (RDRE)......................................................................496Application............................................................................496Setting guidelines.................................................................496

Indications (RDRE)....................................................................497Application............................................................................497

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Setting guidelines.................................................................497Event recorder (RDRE).............................................................498

Application............................................................................498Setting guidelines.................................................................498

Trip value recorder (RDRE).......................................................498Application............................................................................498Setting guidelines.................................................................499

Disturbance recorder (RDRE)...................................................499Application............................................................................499Setting guidelines.................................................................500

Metering..........................................................................................500Pulse counter logic (GGIO).......................................................500


Energy metering and demand handling (MMTR)......................502Application............................................................................502Setting guidelines.................................................................503Setting parameters...............................................................504

Section 5 Station communication.................................................507Overview.........................................................................................507IEC 61850-8-1 communication protocol.........................................507

Application IEC 61850-8-1.........................................................507Setting guidelines......................................................................509Generic single point function block (SPGGIO)..........................509


Generic measured values function block (MVGGIO)................509Application............................................................................509Setting guidelines.................................................................510Setting parameters...............................................................510

Setting parameters....................................................................510LON communication protocol.........................................................511

Application.................................................................................511Setting parameters....................................................................512

SPA communication protocol.........................................................513Application.................................................................................513Setting guidelines......................................................................515Setting parameters....................................................................515

IEC 60870-5-103 communication protocol.....................................516Application.................................................................................516Setting parameters....................................................................522

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Automation bits (AUBI)...................................................................526Application.................................................................................526Setting guidelines......................................................................526Setting parameters....................................................................526

Single command, 16 signals (CD)..................................................541Application.................................................................................541Setting guidelines......................................................................543Setting parameters....................................................................544

Multiple command (CM) and Multiple transmit (MT).......................544Application.................................................................................544Setting guidelines......................................................................544

Settings................................................................................544Setting parameters....................................................................544

Section 6 Remote communication................................................547Binary signal transfer to remote end...............................................547

Application.................................................................................547Communication hardware solutions.....................................548

Setting guidelines......................................................................549Setting parameters....................................................................550

Section 7 Configuration................................................................555Introduction.....................................................................................555Description of REG 670..................................................................555

Introduction................................................................................555Description of configuration A20 .........................................555Description of configuration B30..........................................557Description of configuration C30..........................................558

Section 8 Setting examples..........................................................561Setting examples............................................................................561

REG 670 Example 1..................................................................563

Section 9 Glossary.......................................................................565Glossary.........................................................................................565

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Section 1 Introduction

About this chapterThis chapter introduces the user to the manual as such.

1.1 Introduction to the application manual

1.1.1 About the complete set of manuals for an IEDThe user’s manual (UM) is a complete set of five different manuals:

en06000097.vsd

Applicationmanual

Technicalreference

manual

Installation andcommissioning

manual

Operator´smanual

Engineeringguide

The Application Manual (AM) contains application descriptions, setting guidelinesand setting parameters sorted per function. The application manual should be used tofind out when and for what purpose a typical protection function could be used. Themanual should also be used when calculating settings.

The Technical Reference Manual (TRM) contains application and functionalitydescriptions and it lists function blocks, logic diagrams, input and output signals,setting parameters and technical data sorted per function. The technical referencemanual should be used as a technical reference during the engineering phase,installation and commissioning phase, and during normal service.

The Installation and Commissioning Manual (ICM) contains instructions on howto install and commission the protection IED. The manual can also be used as areference during periodic testing. The manual covers procedures for mechanical andelectrical installation, energizing and checking of external circuitry, setting andconfiguration as well as verifying settings and performing directional tests. Thechapters are organized in the chronological order (indicated by chapter/sectionnumbers) in which the protection IED should be installed and commissioned.

The Operator’s Manual (OM) contains instructions on how to operate the protectionIED during normal service once it has been commissioned. The operator’s manualcan be used to find out how to handle disturbances or how to view calculated andmeasured network data in order to determine the cause of a fault.

Section 1Introduction


11

The IED 670 Engineering guide (EG) contains instructions on how to engineer theIED 670 products. The manual guides to use the different tool components for IED670 engineering. It also guides how to handle the tool component available to readdisturbance files from the IEDs on the basis of the IEC 61850 definitions. The thirdpart is an introduction about the diagnostic tool components available for IED 670products and the PCM 600 tool.

The IEC 61850 Station Engineering guide contains descriptions of IEC 61850station engineering and process signal routing. The manual presents the PCM 600and CCT tool used for station engineering. It describes the IEC 61850 attribute editorand how to set up projects and communication.

1.1.2 About the application manualThe application manual contains the following chapters:

• The chapter “Engineering of the IED” describes the overall procedure regardingthe engineering process of an IED.

• The chapter “Requirements“ describes current and voltage transformerrequirements.

• The chapter “IED application” describes the use of the included softwarefunctions in the IED. The chapter discuss application possibilities and givesguidelines for calculating settings for a particular application.

• The chapter “Station communication“ describes the communication possibilitiesin a SA-system.

• The chapter “Remote communication“ describes the remote end datacommunication possibilities through binary signal transferring.

• The chapter “Configuration” describes the preconfiguration of the IED and itscomplements.

• The chapter “Glossary” is a list of terms, acronyms and abbreviations used inABB technical documentation.

1.1.3 Intended audience

GeneralThe application manual is addressing the system engineer/technical responsible whois responsible for specifying the application of the IED.

RequirementsThe system engineer/technical responsible must have a good knowledge aboutprotection systems, protection equipment, protection functions and the configuredfunctional logics in the protection.



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1.1.4 Related documentsDocuments related to REG 670 Identity numberOperator’s manual 1MRK 502 014-UEN

Installation and commissioning manual 1MRK 502 015-UEN

Technical reference manual 1MRK 502 013-UEN

Application manual 1MRK 502 016-UEN

Buyer’s guide 1MRK 502 019-BEN

Setting example 1MRK 502 020-WEN

Connection and Installation components 1MRK 013 003-BEN

Test system, COMBITEST 1MRK 512 001-BEN

Accessories for IED 670 1MRK 514 012-BEN

Getting started guide IED 670 1MRK 500 080-UEN

SPA and LON signal list for IED 670, ver. 1.1 1MRK 500 083-WEN

IEC 61850 Data objects list for IED 670, ver. 1.1 1MRK 500 084-WEN

Generic IEC 61850 IED Connectivity package 1KHA001027-UEN

Protection and Control IED Manager PCM 600 Installation sheet 1MRS755552

Engineering guide IED 670 products 1MRK 511 179-UEN

Buyer’s guide REG 216 1MRB520004-BEN

Latest versions of the described documentation can be found on www.abb.com/substationautomation

1.1.5 Revision notesRevision DescriptionB No functionality added. Minor changes made in content due to problem reports.



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HTTP://WWW.ABB.COM/SUBSTATIONAUTOMATION

Section 2 Engineering of the IED

About this chapterThis chapter describes the overall procedure regarding the engineering process of anIED.

2.1 Introduction

The IED 670 includes all the necessary functions to build any application.

The functions are available in a software library and there is a basic library offunctions always included in any supply that are sufficient for most applications.

For special applications there is a number of software options which must be orderedseparately.

The function library with available basic functions and options are shown in figurebelow.

To allow applications on different voltage levels and station arrangements there isalso a choice of hardware to be included. The IED can be ordered in 1/1 resp 1/2 size19” rack with 6U height cases and with a small or medium size HMI as a local userinterface.

The cases can be mounted in 19” rack, flushed or wall mounted as preferred.

The engineering is done with use of the PCM 600 engineering toolbox.

Install the PCM 600 toolbox with the connectivity package for IED 670 series andopen it from the Start menu or from the short-cut on the desktop.

The PCM 600 platform includes following components:

• Application Configuration tool• Signal matrix tool• Parameter setting tool• Disturbance recorder tools for upload and viewing• Graphical Mimic editing tool• Signal monitoring tool• Event viewer tool

Section 2Engineering of the IED


15

2.1.1 The interface between Signal matrix and Configuration toolThe complete configuration of an IED 670 includes both the configuration with thegraphic configuration tool and the configuration of the hardware done with the SignalMatrix Tool SMT.

The Application configuration tool is used to set up the included hardware structureand the software functions.

The hardware is set-up under the Edit/Function selector menu where for each locationthe physical analog and digital IO is defined. The figure 1 shows an example fromthis set-up.

Figure 1: The Function selector options allows definition of the specifichardware.

The hardware also includes e.g. the configurable LEDs and the remote end line datacommunication module LDCM. These are also important parts of the physicalinterface and will be shown with the signal matrix tool.

The graphical configuration includes a number of virtual elements forming theinterface between the software functions and the hardware. These function blocks areconfigured at all interface points where a physical IO is foreseen to be required.

These virtual IO blocks are:

• Analog pre-processing function block SMAI• Virtual binary input function block SMBI• Virtual binary output function block SMBO



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Figure 2 shows an example for RET 670 of these function blocks configured for usein the signal matrix tool.

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Figure 2: Virtual IO blocks SMBI and SMBO configured in an applicationconfiguration

These function blocks will, as the graphical configuration has been compiled, show-up in the signal matrix tool when this has been opened. The use of the Signal Matrixtool is described below.

2.1.1.1 The configurable LEDs.

The fifteen configurable LEDs can be connected to virtual inputs or virtual outputsonly with the signal matrix tool This means that signals foreseen to be used on anLED such as group signals must be connected through an OR function block to avirtual output for use by the LED. Naturally the same signal can be connected to aphysical output e.g. for SCADA signaling. The six first LEDs are red and theremaining nine are yellow.



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2.1.1.2 The analog preprocessing function block (SMAI).

This function block is vital for the IED 670 functionality. Interfaces both to localanalog inputs as well as remote analog inputs through the LDCM communicationmodule are connected through this function block. The signals from this block isconnected to the different applications. Some important comments for theunderstanding of the function:

• The function block can be used for voltage inputs or current inputs. Which of thetwo is defined as a setting parameter (TYPE input) on the function block.

• The output AI3P is a general output for all of the phases. It is normally connectedto the functions. The only difference is the Disturbance recorder block where theindividual channels are connected to individual channels. The four individualoutputs are the three phases and the neutral where the neutral is residuallysummated from the phases if no physical connection is made to the fourth inputwith the signal matrix tool. If the physical connection is made the physical inputis used instead. When e.g. a neutral overcurrent protection is connected to thefunction block output AI3P it will measure the fourth neutral channel. For eachapplication it can then be decided if this is the residual sum or e.g. if a neutralcurrent transformer is connected there.

• The physical inputs can be connected phase-phase instead of phase to neutral,where acceptable. The setting of the pre-processing block (under Settings/GeneralSettings/Analog modules/3PhaseAnalogGroup) Connection Type mustthen be set to Phase to phase. The pre-processing block will then use the physicalvalues as phase to phase values and calculate the phase to neutral values.

• The name of the pre-processing block and the names of the four inputs are thenames shown on the signal matrix tool and the function block name should beselected for simple understanding what the input means.



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en05000531.vsd

Figure 3: The analog preprocessing block.

The analog pre-processing blocks can also be configured to have the correct frequencytracking for DFT caculations (i.e. adapt to the signal frequency). This is included inthe SMAI function blocks. Each block in a task time group is provided with apossibility to keep track of the frequency for adjustment of the fouriers filter to thecorrect frequency. In principle each block in the series should have the DFT ref settingfor the group set to preferable group positive sequence voltage input, e.g. ifDFTReference for PR01 is set to AdDFTRefCh7, the PRO7 positive sequence voltagefrequency will then be the frequency reference for group 1. If SMAI block for othertask times (e.g.13-24 resp 25-36) also are included they can be given the samereference by connecting the output SPFCOUT to input DFTSPSC on the functionblocks SMAI 13 resp 25. Function blocks within these task time groups must thenhave setting e.g. DFTReference=ExternalDFTRef.



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The first function block in the task time group containing the function block sendingthe signal must have the setting of the DFT reference output set to e.g.DFTRefExtOut= AdDFTRefCh7.

Settings DFTRefExtOut and DFTReference shall be set to defaultvalue InternalDFTRef if no VT inputs are available.

2.2 Configuration alternatives

There are four different software alternatives with which the IED can be managed.The intention is that these configurations shall suit most applications with minor orno changes.

The configurations are:

• Single breaker arrangement. Three phase tripping arrangement.• Single breaker arrangement. Single phase tripping arrangement.• Multi breaker arrangement. Three phase tripping arrangement.• Multi breaker arrangement. Single phase tripping arrangement

The Multi breaker arrangement includes One- and a half, Double breaker and Ringbreaker arrangements.

The number of IO must be ordered to the application where more IO is foreseen forthe Single phase tripping arrangements along with Multi-breaker arrangement.

The basic ordering includes one Binary input module (16 inputs) and one BinaryOutput module (24 outputs), sufficient for the default configured IO to trip and closecircuit breaker and with possible communication interface.

Each of the four alternative solutions is of course possible to re-configure to an user-defined configuration.

Optional functions and optional IO ordered will not be configured at delivery. As thestandard delivered hardware only includes one binary input and one binary outputmodule only the key functions such as tripping are connected to the outputs in thesignal matrix tool.

The required total IO must be calculated and specified at ordering and the IO adaptedwith help of the Signal Matrix Tool (SMT).

Typical connection diagrams are provided in following appendices available inseparate documents, refer to section "Related documents"



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1MRK002801-BA Single breaker arrangement. Three phase tripping arrangement.

1MRK002801-CA Single breaker arrangement. Single phase tripping arrangement.

1MRK002801-DA Multi breaker arrangement. Three phase tripping arrangement.

1MRK002801-EA Multi breaker arrangement. Single phase tripping arrangement.

The diagrams show an example of how to connect the primary apparatuses to the IEDwhen also the control functionality is required. It is intended as a reference for thealternative applications. As there normally is two sub-systems and not always allfunctions in both there is a need for exchange of data between the sub-systems. Theconfigurations are prepared to cover for the most common applications but not allpossibilities.

The Application configuration tool CAP 531, which is part of the PCM600engineering platform, will further to the four arrangements above include alsoalternatives for each of them with all of the software options configured. These canthen be used directly or as assistance where only minor adaptation will be necessary.

The detailed configuration diagrams are available in separate documents, refer tosection "Related documents"

The configurations are as far as found necessary provided with application commentsto explain why the signals have been connected in the special way. This is of coursefor the special application features created not standard functionality.

2.3 Adapting a configuration to satisfy specialneeds

It is recognized that each application is unique. The IED thus offers full flexibilityand simple changes and adjustments can easily be made to the deliveredconfiguration. Note also that special user configurations will be supported and IEDcan thus be delivered with your specific configuration. ABB is of course glad to assistin developing the adapted configuration.

When the IED has been received, or before from the configuration templates, thereare two possibilities to adapt to the specific needs.

2.3.1 Signal Matrix Tool (SMT)The PCM 600 engineering platform includes a Signal Matrix Tool (SMT). From thistool inputs and outputs are available and can be tied together in the desirable way.For example. if more signal outputs are required, outputs from functions can beconnected to the physical IO with the signal matrix tool.

The signal matrix tool uses information from the compiled application configurationperformed with CAP 531. At saving the information will be sent to the SMT tool.



21

Open the Signal Matrix Tool by a right click on the IED in the Plant structure of PCM600.

The physical IO will show up on the horizontal axis and the virtual IO on the verticalaxis. The user has then full freedom for each application to connect the virtual signalfrom the graphical configuration to analog or digital IO. The physical IO is set upunder Application configuration tool in menu Edit/Function selector.

In this menu the included IO boards is edited and must match the ordered hardware.It is commonly required that this menu is edited, the configuration compiled anddownloaded and then the PST tool can be used to connect the physical inputs withthe virtual IO.

This is done by entering an X at the connection point between the two.

One virtual signal on the vertical axis can be connected to several physical binary IO.

One analog input may also be connected to several preprocessing elements for theanalog signals.

Figure 4: Example (RET 670) from signal matrix tool tabs for binary input defines the connection betweenthe physical and virtual IO.



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This gives the user flexibility to connect any signal he needs to an IO without doingany changes in the graphical configuration. To allow full flexibility a number oflogically prepared signals has also been generated.

2.3.2 Application configuration tool CAP 531The application configuration tool allows free configuration of the IED withadditional use of any logic element to create special logic e.g. for Auto Switching ofDisconnectors in Multi-breaker arrangements. The logic is created by inserting logicblocks and connecting them together.

Interface elements to make signals available in the signal matrix tool can also beadded so that in future applications the same configuration can be used and theadaptation made with the signal matrix tool.

en05000532.vsd

Figure 5: A typical view from the application configuration tool showing anadded AND element during wiring.

2.4 Preparing a specific application configuration ofthe IED

2.4.1 Configuring an IED with CAP531The application configuration tool can be utilized to prepare an adapted IED withspecial functions when required. Here we are giving some basic guidelines of how toprepare a configuration.

It is advisable to start from one of the four basic configurations and delete and addfunction blocks and connections in the selected configuration, closest to theapplication. Refer to the “Help in CAP 531” for more information. For the basicconfiguration available in the ordered IED and the alternative configurations availableas templates refer to the chapter "Configuration".

The PCM 600 toolbox with the configuration tool CAP 531 shall be installed priorto the below sequence.



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Procedure

1. Open the configuration program CAP 531 under the PCM 600 platform byopening Start/Programs/ABB/PCM 600.The below view will show up.

Figure 6: Open view for PCM 600

2. Start the configuration tool under the menu or by clicking the wrench symbol.In the configuration tool open the template to start from under Edit. Note thatthe IED has default configuration as ordered, open the correct or a more suitablealternative template.Default password is ”abb”Information on how to log on as an administrators is available in “Operator'smanual”. Please refer to section "Related documents".The template will be installed and you can see the worksheets used in thetemplate.

3. Open the worksheets to be addition. Check in the configuration diagrams andverify what you need to change e.g. logic added or IO signals modification.Following guidelines can be given.



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New function blocks are added by selecting the function from the functionlibrary. It is also possible to copy an existing one by marking it and copying itusing Ctrl+C.The following view is shown.

Figure 7: Adding a new function block

The new function block is selected and added to the worksheet. Note that allinputs needs to be connected either with a signal or with a True (On) or False(Off) signal.

4. Click the input and take key “v” or click the “var” symbol to add a variable onan input or output.

5. Type the name you want to use for the signal. Type True or False for fixed Onor Off.

This is defined on the outputs On-Off for binary status on theFixed signals function block. The designations there must beused for fixed binary status.

6. If the input shall be connected to the output on a function close by, take the linetool and connect the two.In case the connection inputs and outputs are in different sheets, variables nameswill be used and with the same variable name you connect inputs and outputs.An output can be connected to several inputs, e.g. on IO boards, on Trip functionblock, on an OR, AND or TIMER function block etc.Inputs cannot be connected to several places without an OR gate.When you select your function blocks e.g. logic elements to build a logic youmust, for high speed circuits, keep track of the processing order. The processingnumber is shown on each function block. A sequence should have raising tasknumbers not to loose one processor loop, e.g. 1, 3, 8 or even 100 ms.



25

You can copy and paste variables and function blocks/logic elements. You willat pasting of e.g. an OR gate be requested to select the new one with the correctsequence number.

7. When you are satisfied with the logic you have created, save, close and click onthe IED symbol and Compile the configuration.You will then get warnings and errors for all mistakes. All errors must becorrected, warnings can be checked to see if they are acceptable, mostly due toconnection of function blocks with different cycle times.

8. Click on the Errors and Warnings in the Error list to directly open the worksheetwhere the problem is found. Correct all mistakes, save and compile again.

9. When no errors occur, download the configuration to the IED.You must have the correct IP address and you must have either a straightEthernet cable with a HUB in between or a crossed Ethernet cable when youare directly connected PC-IED.

2.4.2 Using the Signal monitoring tool (SMT)The Signal Monitoring Tool is opened by right clicking and selecting the tool. It givesaccess to measured values from Binary Inputs, Binary Outputs and Measuringfunction blocks (MMXU). The status update can with a menu symbol be updated.

2.4.3 Using the Event viewer toolThe Event List tool gives access to the locally stored Event lists. It gives access bothto the internal signal event list and to the Disturbance report event list where the last1000 events are stored in a FIFO (First-In-First-Out) list.

2.5 Setting of the IED

The IED are set using the PCM 600 setting tool. The IED is delivered with a defaultsetting where many parameters are selected to be one of the most likely or suitablesettings. However of course all important settings such as currents, impedances andtimes always need to be set.

To simplify the use the tool has a normal user view and an advanced user view. Thenormal user does not need to set parameters defined as parameters for the advanceduser. Switching is simply done from the symbols on the toolbar.

Setting can be done locally from the HMI or from the engineering tool. The settingsare always under password control and the user must log-in with an authority levelto match the settings to be changed.

The IED has the settings available in six setting groups and switching between thesesetting groups can be performed either from physical IO or from a SA system or theSCADA system over the communication link. The special function blockACTGROUP is used for this purpose and this switching is not password controlled.



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The function block includes a definition how many setting groups are used to preventswitching to a not set group.

The local setting can be blocked after commissioning by activating a digital input orfrom SA system as defined in the configuration. Default there is a software switchwhich can be set to block the setting from the HMI.

Figure 8: A typical view from the PCM 600 setting tool

A special function block is included for block of setting changes,locally of from the tool. This should be activated from a physical inputat the end of commissioning to prevent changes of setting in acommissioned station as setting changes requires newcommissioning. If setting changes are required these should beprepared in a separate setting group and tested and activated by asetting group switching.

2.6 Authorization

To safeguard the interests of our customers, both the IED 670 and the tools that areaccessing the IED 670 are protected, subject of authorization handling. The conceptof authorization, as it is implemented in the IED 670 and the associated tools is basedon the following facts:



27

• There are two types of points of access to the IED 670:• local, through the local HMI• remote, through the communication ports

• There are different levels (or types) of users that can access or operate differentareas of the IED and tools functionality; the pre-defined user types are definedas follows:

User type Access rightsGuest Read only

SuperUser Full access

SPAGuest Read only + control

SystemOperator Control from LHMI, no bypass

ProtectionEngineer All settings

DesignEngineer Application configuration (including SMT, GDE and CMT)

UserAdministrator User and password administration for the IED

The IED users can be created, deleted and edited only with the User ManagementTool (UMT) within PCM 600. The user can only LogOn or LogOff on the LHMI ofthe IED, there are no users, groups or functions that can be defined on the IED LHMI.

2.6.1 Authorization handling in the toolUpon the creation of an IED in the Plant Structure, the User Management Tool isimmediately accessible, by right – clicking with the mouse on that specific IED name:



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Figure 9: Right-clicking to get the User Management Tool – “IED Users”.

By left-clicking on the “IED Users” submenu, the tool will open in the right-sidepanel:



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Figure 10: User Manager Tool opened in the right-side panel.

By default, the IEDs are delivered so that users are not required to log on to operatethe IED. The default user is the SuperUser. Before doing any changes to the UserManagement in the IED it is recommendable that the administrator uploads the Usersand Groups existent in the IED.

If situation requires so, one can restore the factory settings, overwriting all existingsettings in the User Management Tool database.

Even if the administrator empties the tool database, the userspreviously defined are still in the IED. They cannot be erased bydownloading the empty list into the IED (the tool won’t download anempty list), so it is strongly recommended that before you create anyuser you create one that belongs to the SuperUser group.

If the administrator marks the check box “User must logon to this IED”, then thefields under the “User Management” tab are becoming accessible and one can add,delete and edit users.

To add a new user, the administrator will press the button that is marked with a blackarrow, see figure 11 on the “User” subtab:



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Figure 11: User subtab and creation of a new user.

Upon pressing this button, a window will appear, enabling the administrator to enterdetails about the user, assign an access password and (after pressing “Next” andadvancing to the next window) assign the user to a group:

Figure 12: Enter details about the user.



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Figure 13: Assign the user to a group.

Once the new user is created, it will appear in the list of users. Once in the list, thereare several operations that can be performed on the users, shown in figure 14

Figure 14: Operations on users in the users list.

No. Description1 Delete selected user

2 Change password

3 Add another group to the user permissions

The “Group” subtab is displaying all the pre-defined groups and gives short detailsof the permissions allowed to the members of a particular group:



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Figure 15: The “Groups” subtab.

It also allows the administrator to add another (already created) user to a group, inthe same way it could assign one more group to an user, on the “Users” subtab.

The “Functions” subtab is a descriptional area, showing in detail what Read/Writepermissions has each user group, in respect to various tools and components.

Finally, after the desired users are created and permissions assigned to them by meansof user groups, the whole list must be downloaded in the IED, in the same way asfrom the other tools:

No. Description1 Upload from IED

2 Download to IED



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2.6.2 Authorization handling in the IEDAt delivery the default user is the superuser. No LogOn is required to operate the IEDuntil a user has been created with the UMT(User Management Tool). See Applicationmanual for more details.

Once a user is created and downloaded into the IED, that user can perform a LogOn,introducing the password assigned in the tool.

If there is no user created, an attempt to log on will cause the display to show a messagebox saying: “No user defined!”

If one user leaves the IED without logging off, then after the timeout (set in Settings\General Settings\HMI\Screen\ Display Timeout ) elapses, the IED will return to aGuest state, when only reading is possible. The display time out is set to 60 minutesat delivery.

If there are one or more users created with the UMT and downloaded into the IED,then, when a user intentionally attempts a LogOn or when the user attempts to performan operation that is password protected, the LogOn window will appear

The cursor is focused on the “User identity” field, so upon pressing the “E” key, onecan change the user name, by browsing the list of users, with the “up” and “down”arrows. After choosing the right user name, the user must press the “E” key again.When it comes to password, upon pressing the “E” key, the following character willshow up: “$”. The user must scroll for every letter in the pasword. After all the lettersare introduced (passwords are case sensitive!) choose OK and press “E” key again.

If everything is O.K. at a voluntary LogOn the LHMI returns to the Authorizationscreen. If the LogOn is OK, when required to change for example a passwordprotected setting, the LHMI returns to the actual setting folder. If the LogOn hasfailed, then the LogOn window will pop-up again, until either the user makes it rightor presses “Cancel”.

2.7 Blocking of setting after commissioning of theIED

It is important to ensure that a commissioned station may not be changed without anew commissioning. Settings or configurations may not be changed without a newcommissioning with a new test record. To prevent changes a CHANGE LOCKfunction block is used and activated when commissioning is finalized. This block ispreferably enabled by a field contact input from a key switch. This can be done bymapping the ChangeLock input to a binary input in the relay, which is energized bythe key switch input or a disconnecting terminal link when commissioning isfinalized, see figure 16..



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Alternatively it can be arranged with an internal blocking e.g. by a General switchwhich can be controlled from the HMI and switched “On” when commissioning isfinalized. It should require a special knowledge to open up the change possibility soit advisable to use this function block.

Refer to below figure.

ChangeLock+

Disconnectable terminalor key-switch

en05000754.vsd

Figure 16: Blocking of setting

For example, the COMBIFLEX key selector or an FT switch can be used for thispurpose.

2.8 How to use the configurable logics blocks

The IED has a very powerful logic capability.

Logic blocks of each type are available in different task times and task orders. Thisallows the user to define own logic with all the logic elements and function in thecorrect sequence. At creating the logic the elements sequence number and task timesshould always be checked and logic components with the suitable values selected.

An example of a logic with increasing sequence number throughout the logic.

en05000537.vsd

Figure 17: It is important to ensure that the task numbers are in sequence tohave a fast processing of logic.



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2.9 Some application ideas

The advanced logic capabilities and the flexible functions give the user a possibilityto manage any type of application.

Below some examples are given to show the possibilities.

2.9.1 Voltage selectionThe Busbar voltage must in many cases be used as reference for line or bay protection.

Examples are:

Line distance protection where the busbar is provided with three phase voltagetransformers and the lines with only single-phase sets for Synchronism checkreference.

The Synchronism check function in IED 670 has a built-in voltageselection.

Bus voltage protection e.g. Over- and Undervoltage, Over- and Underfrequencyprotection functions in the bay.

Voltage reference for metering functions - where three phase voltage transformersdoes not exist on the object.

A voltage selection can be created in IED 670 with a user defined logic wherepositions of disconnectors (and breakers) are used to create the required voltageselection.

An example is shown in figure 18 where the voltage transformers for a double bussystem are connected to the line protection function, which may be line distance relaysor voltage or frequency relays.

Supervision of the fuse/MCB failures can be fed through the same logic and connectedto e.g. block operation of undervoltage functions.

It is also a possible to block functions when both disconnectors are open.



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Figure 18: The voltage selection logic for busbar voltage transformers in a double bus arrangement.

2.9.2 Fuse failure protectionIt is possible to create a fuse failure protection (60) based on comparison from twofuse groups on the same voltage transformer or two fuses on separate voltagetransformers windings or voltage transformers on the same bus. The signal can beused to block protection functions and give alarms.

The proposed scheme is based on comparison of not simultaneous occurring negativesequence voltage on the two voltage sources.

Overvoltage functions measuring negative sequence voltage and Undervoltagefunction measuring positive sequence voltages are combined as shown in figure 19.

The negative sequence part will detect one and two phase fuse failures and the positivesequence part will detect three phase fuse failures. Due to the combination it candetect failures of fuses as well as MCB’s.



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Figure 19: Arrangement of Multipurpose functions to measure fuse failures

2.9.3 Automatic opening of a transformer disconnector and closingthe ring breakersThe available function blocks to create user defined logic can be utilized for manyfunctions. One example is to open the transformer High voltage disconnector atinternal transformer faults in multi-breaker arrangements and then close the ring orone- and a half breaker diameter.

The logic can include status supervision before the fault was tripped to ensure thatthe sequence is only closing apparatuses already closed before the fault, informationabout the fault to ensure it was a transformer fault, check that the disconnector is openbefore the breaker/s is/are closed and verification that the new status has been reachedbefore next sequence is started.

Detailed pictures are not shown here for want of space. Please contact ABB for moredetails on such special logic schemes.



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2.9.4 Automatic load transfer from bus A to bus BWith transformer applications it is sometimes required to automatically transfer theload from one transformer to the other. It includes closing bus tie and closingtransformer breakers. It mostly also involves switching back after the normal supplyhas been restored to the original transformer. The load transfer scheme includes acombination of advance logic checking apparatus positions and the measurement ofbus and transformer voltage and the use of Synchronism check device to control theclosing.

An advanced alternative exists for generating stations where the unit transformersupplies will need to synchronize at switching and this synchronizing is done on adecaying bus voltage on voltage level as well as frequency level depending on theavailable synchronous and asynchronous machines maintaining the bus voltage.

It shall be noticed that the exchange of information between IEDs of the twotransformers can be with peer- to-peer communication across IEC61850-8-1 or overLON bus as alternative to a hardwire connection. With the fast Goose IO transfertimes are in the level 4 ms which is sufficient also for this type of logic. Detailedpictures are not shown here for want of space. Please contact ABB for more detailson such special logic schemes.

2.10 Testing of the IED

The testing requirement is minimized with the use of an advanced internal selfsupervision. This in, combination with the numerical design and the use of measuredvalues in the substation control, means that the need of scheduled maintenance testingdoes not exist. However, during commissioning, changes in the system with settingor configuration changes etc. there is a need of simple access to test the IED 670.

The test interface is preferably done with test switches from the ABB FT Switch orCOMBITEST test system. These COMBITEST test switches and test handles orplugs provide a high amount of IO allowing test of integrated IEDs such as the IED670 family.

Test switch contacts should be provided on selected inputs and outputs to allowverification of setting values such as current, voltage, impedance and set timers. Dueto the high amount of functionality some interfaces must be switched off in software.It is then important to ensure that e.g. times to trip can be measured from other signalswith test switches. In the connection diagrams for the four configurations, the typicallocation of test switch contacts is indicated. The outputs without test switches musteither be provided with a second test switch or blocked by software. This can be donee.g. by blocking virtual outputs SMBO with “In test” condition. The “In test” is withCOMBTEST test switches RTXP24 provided by contact 29-30 (early closing)activating a binary input and connected to the test function block. Alternatively a testswitch finger from FT can be wired to the binary input to achieve similar function.



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2.11 Engineering checklist

2.11.1 How to use the IED in conjunction with PCM 600 toolboxThe below check list gives a short guideline of how to use the protection and controlIED with help of the PCM 600 toolbox. Uploading of disturbance record is notincluded below but is available from PCM 600.

Procedure

1. Select the IED configuration.The IED is available with four alternative configurations as described above.

2. Select and order the IED which best suits the application.There are a number of templates including options for your use. Check whichone is the most suitable for your application.

3. Adjust the configuration if required by adjusting the input and outputs with theSignal Matrix Tool (SMT) in PCM 600.If you have added physical IO compared to the default single Binary inputmodule and Binary output module you need to add this in CAP 531 under Edit/Function selector. This is required to have the physical IO showing up in theSMT tool. Also decide on how many setting groups you will be using.

4. Select the number of setting groups in CAP 531 on the Activate setting groupfunction block.If more logic adjustments are necessary open the configuration tool CAP 531and perform the changes, add logic gates, change connections, add connectionsetc.

5. Save the IED, compile and download to the relay.

At compilations you can get warnings and errors. Warnings arenormal as e.g. warnings for different cycle times connectedwhich is bound to happen. Errors are defined as mistakesneeding to be corrected. Click the error in the error list, this willopen up the location on the worksheet with the error and allowyou to find the mistake.

6. Set the IED with use of the PCM 600 Parameter Setting Tool PST.7. Adjust the setting to the values suitable for your application.

Remember to also do the general settings. General setting values have only oneset and are the basic parameters such as CT and VT ratios etc.

8. Download to the IED, you can download from any level in your structure butensure to download all parts.

The active setting group function block ACGR has a settingparameter where the number of setting groups in use can be set.This is important and will minimize the risk of someoneswitching to a setting group which has not been verified atcommissioning. The default setting is use of one group and this



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setting will also decide how many setting groups are initiated inthe parameter setting menu.

9. Test the IED. Use the Debug tool in the CAP 531 configuration tool to see on-line the status of digital signals.This simplifies the evaluation. Note that faults need to be put on continuouslyto follow a fault signal as the debug update time is on second level.

10. Check also Measurements/Functions where each function measured result canbe seen.This shows mistakes in CT or VT settings, mistakes in setting function ON-OFFetc. If values do not show up the most probably reason is that it is OFF, secondlyit can be incorrect configured. If the function is ON, open the CAP, not in debugmode, and upload options from the relay.

11. Click the Red-Green Leaf and update the function block from the occurring list.You will notice if e.g. the function has not been ordered as it will not show upas available.

12. Save, Compile and download again.If that does not take care of the problem, contact ABB SA-T Supportline.

Exercise caution when high currents are applied which mightthermally stress the relay.



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Section 3 Requirements

About this chapterThis chapter describes current and voltage transformer requirements.

3.1 Current transformer requirements

The performance of a protection function will depend on the quality of the measuredcurrent signal. Saturation of the current transformer (CT) will cause distortion of thecurrent signal and can result in a failure to operate or cause unwanted operations ofsome functions. Consequently CT saturation can have an influence on both thedependability and the security of the protection. This protection IED has beendesigned to permit heavy CT saturation with maintained correct operation.

3.1.1 Current transformer classificationTo guarantee correct operation, the current transformers (CTs) must be able tocorrectly reproduce the current for a minimum time before the CT will begin tosaturate. To fulfil the requirement on a specified time to saturation the CTs must fulfilthe requirements of a minimum secondary e.m.f. that is specified below.

There are several different ways to specify CTs. Conventional magnetic core CTs areusually specified and manufactured according to some international or nationalstandards, which specify different protection classes as well. There are many differentstandards and a lot of classes but fundamentally there are three different types of CTs:

• High remanence type CT• Low remanence type CT• Non remanence type CT

The high remanence type has no limit for the remanent flux. This CT has a magneticcore without any airgap and a remanent flux might remain almost infinite time. Inthis type of transformers the remanence can be up to around 80% of the saturationflux. Typical examples of high remanence type CT are class P, PX, TPS, TPXaccording to IEC, class P, X according to BS (old British Standard) and nongappedclass C, K according to ANSI/IEEE.

The low remanence type has a specified limit for the remanent flux. This CT is madewith a small airgap to reduce the remanence to a level that does not exceed 10% ofthe saturation flux. The small airgap has only very limited influence on the otherproperties of the CT. Class PR, TPY according to IEC are low remanence type CTs.

Section 3Requirements


43

The non remanence type CT has practically negligible level of remanent flux. Thistype of CT has relatively big airgaps in order to reduce the remanence to practicallyzero level. In the same time, these airgaps reduce the influence of the DC-componentfrom the primary fault current. The airgaps will also decrease the measuring accuracyin the non-saturated region of operation. Class TPZ according to IEC is a nonremanence type CT.

Different standards and classes specify the saturation e.m.f. in different ways but itis possible to approximately compare values from different classes. The ratedequivalent limiting secondary e.m.f. Eal according to the IEC 60044 – 6 standard isused to specify the CT requirements for IED 670. The requirements are also specifiedaccording to other standards.

3.1.2 ConditionsThe requirements are a result of investigations performed in our network simulator.The current transformer models are representative for current transformers of highremanence and low remanence type. The results may not always be valid for nonremanence type CTs (TPZ).

The performances of the protection functions have been checked in the range fromsymmetrical to fully asymmetrical fault currents. Primary time constants of at least120 ms have been considered at the tests. The current requirements below are thusapplicable both for symmetrical and asymmetrical fault currents.

Depending on the protection function phase-to-earth, phase-to-phase and three-phasefaults have been tested for different relevant fault positions e.g. close in forward andreverse faults, zone 1 reach faults, internal and external faults. The dependability andsecurity of the protection was verified by checking e.g. time delays, unwantedoperations, directionality, overreach and stability.

The remanence in the current transformer core can cause unwanted operations orminor additional time delays for some protection functions. As unwanted operationsare not acceptable at all maximum remanence has been considered for fault casescritical for the security, e.g. faults in reverse direction and external faults. Because ofthe almost negligible risk of additional time delays and the non-existent risk of failureto operate the remanence have not been considered for the dependability cases. Therequirements below are therefore fully valid for all normal applications.

It is difficult to give general recommendations for additional margins for remanenceto avoid the minor risk of an additional time delay. They depend on the performanceand economy requirements. When current transformers of low remanence type (e.g.TPY, PR) are used, normally no additional margin is needed. For current transformersof high remanence type (e.g. P, PX, TPS, TPX) the small probability of fullyasymmetrical faults, together with high remanence in the same direction as the fluxgenerated by the fault, has to be kept in mind at the decision of an additional margin.Fully asymmetrical fault current will be achieved when the fault occurs atapproximately zero voltage (0°). Investigations have shown that 95% of the faults in



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the network will occur when the voltage is between 40° and 90°. In addition fullyasymmetrical fault current will not exist in all phases at the same time.

3.1.3 Fault currentThe current transformer requirements are based on the maximum fault current forfaults in different positions. Maximum fault current will occur for three-phase faultsor single-phase-to-earth faults. The current for a single phase-to-earth fault willexceed the current for a three-phase fault when the zero sequence impedance in thetotal fault loop is less than the positive sequence impedance.

When calculating the current transformer requirements, maximum fault current forthe relevant fault position should be used and therefore both fault types have to beconsidered.

3.1.4 Secondary wire resistance and additional loadThe voltage at the current transformer secondary terminals directly affects the currenttransformer saturation. This voltage is developed in a loop containing the secondarywires and the burden of all relays in the circuit. For earth faults the loop includes boththe phase and neutral wire, normally twice the resistance of the single secondary wire.For three-phase faults the neutral current is zero and it is just necessary to considerthe resistance up to the point where the phase wires are connected to the commonneutral wire. The most common practice is to use four wires secondary cables so itnormally is sufficient to consider just a single secondary wire for the three-phase case.

The conclusion is that the loop resistance, twice the resistance of the single secondarywire, must be used in the calculation for phase-to-earth faults and the phase resistance,the resistance of a single secondary wire, may normally be used in the calculation forthree-phase faults.

As the burden can be considerable different for three-phase faults and phase-to-earth faults it is important to consider both cases. Even in a case where the phase-to-earth fault current is smaller than the three-phase fault current the phase-to-earth faultcan be dimensioning for the CT depending on the higher burden.

In isolated or high impedance earthed systems the phase-to-earth fault is not thedimensioning case and therefore the resistance of the single secondary wire alwayscan be used in the calculation, for this case.

3.1.5 General current transformer requirementsThe current transformer ratio is mainly selected based on power system data like e.g.maximum load. However, it should be verified that the current to the protection ishigher than the minimum operating value for all faults that are to be detected withthe selected CT ratio. The minimum operating current is different for differentfunctions and normally settable so each function should be checked.



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The current error of the current transformer can limit the possibility to use a verysensitive setting of a sensitive residual overcurrent protection. If a very sensitivesetting of this function will be used it is recommended that the current transformershould have an accuracy class which have an current error at rated primary currentthat is less than ±1% (e.g. 5P). If current transformers with less accuracy are used itis advisable to check the actual unwanted residual current during the commissioning.

3.1.6 Rated equivalent secondary e.m.f. requirementsWith regard to saturation of the current transformer all current transformers of highremanence and low remanence type that fulfill the requirements on the ratedequivalent secondary e.m.f. Eal below can be used. The characteristic of the nonremanence type CT (TPZ) is not well defined as far as the phase angle error isconcerned. If no explicit recommendation is given for a specific function we thereforerecommend contacting ABB to confirm that the non remanence type can be used.

The CT requirements for the different functions below are specified as a ratedequivalent limiting secondary e.m.f. Eal according to the IEC 60044-6 standard.Requirements for CTs specified in different ways are given at the end of this section.

3.1.6.1 Transformer differential protection

The current transformers must have a rated equivalent secondary e.m.f. Eal that islarger than the maximum of the required secondary e.m.f. Ealreq below:

sn Ral alreq nt CT L 2

pn r

I SE E 30 I R RI I

æ ö³ = × × × + +ç ÷

è ø (Equation 1)

sn Ral alreq tf CT L 2

pn r

I SE E 2 I R RI I

æ ö³ = × × × + +ç ÷

è ø (Equation 2)

where:

Int The rated primary current of the power transformer (A)

Itf Maximum primary fundamental frequency current that passes two main CTs andthe power transformer (A)

Ipn The rated primary CT current (A)

Isn The rated secondary CT current (A)

Ir The rated current of the protection IED (A)

Table continued on next page



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RCT The secondary resistance of the CT (W)

RL The resistance of the secondary wire and additional load (W). The loop resistancecontaining the phase and neutral wires must be used for faults in solidly earthedsystems. The resistance of a single secondary wire should be used for faults inhigh impedance earthed systems.

SR The burden of an IED 670 current input channel (VA). SR=0.020 VA/channel forIr=1 A and Sr=0.150 VA/channel for Ir=5 A

In substations with breaker-and-a-half or double-busbar double-breaker arrangement,the fault current may pass two main CTs for the transformer differential protectionwithout passing the power transformer. In such cases and if both main CTs have equalratios and magnetization characteristics the CTs must satisfy equation 1 andequation 3.

sn Ral alreq f CT L 2

pn r

I SE E I R RI I

æ ö³ = × × + +ç ÷

è ø (Equation 3)

where:

If Maximum primary fundamental frequency current that passes two main CTs without passingthe power transformer (A)

3.1.7 Current transformer requirements for CTs according to otherstandardsAll kinds of conventional magnetic core CTs are possible to use with REx 670 IEDsif they fulfill the requirements corresponding to the above specified expressed as therated equivalent secondary e.m.f. Eal according to the IEC 60044-6 standard. Fromdifferent standards and available data for relaying applications it is possible toapproximately calculate a secondary e.m.f. of the CT comparable with Eal. Bycomparing this with the required secondary e.m.f. Ealreq it is possible to judge if theCT fulfills the requirements. The requirements according to some other standards arespecified below.

3.1.7.1 Current transformers according to IEC 60044-1, class P, PR

A CT according to IEC 60044-1 is specified by the secondary limiting e.m.f. E2max.The value of the E2max is approximately equal to the corresponding Eal according toIEC 60044-6. Therefore, the CTs according to class P and PR must have a secondarylimiting e.m.f. E2max that fulfills the following:

2 max alreqE max imum of E>(Equation 4)



47

3.1.7.2 Current transformers according to IEC 60044-1, class PX, IEC60044-6, class TPS (and old British Standard, class X)

CTs according to these classes are specified approximately in the same way by a ratedknee-point e.m.f. Eknee (Ek for class PX, EkneeBS for class X and the limiting secondaryvoltage Ual for TPS). The value of the Eknee is lower than the corresponding Ealaccording to IEC 60044-6. It is not possible to give a general relation between theEknee and the Eal but normally the Eknee is approximately 80 % of the Eal. Therefore,the CTs according to class PX, X and TPS must have a rated knee-point e.m.f.Eknee that fulfills the following:

Eknee » Ek » EkneeBS » Ual > 0.8 · (maximum of Ealreq) (Equation 5)

3.1.7.3 Current transformers according to ANSI/IEEE

Current transformers according to ANSI/IEEE are partly specified in different ways.A rated secondary terminal voltage UANSI is specified for a CT of class C. UANSI isthe secondary terminal voltage the CT will deliver to a standard burden at 20 timesrated secondary current without exceeding 10 % ratio correction. There are a numberof standardized UANSI values e.g. UANSI is 400 V for a C400 CT. A correspondingrated equivalent limiting secondary e.m.f. EalANSI can be estimated as follows:

Ea lANSI 20 Isn RCT UA NSI+× × 20 Isn RC T× × 20 Isn ZbANSI× ×+= =(Equation 6)

where:

ZbANSI The impedance (i.e. complex quantity) of the standard ANSI burden for the specific C class(W)

UANSI The secondary terminal voltage for the specific C class (V)

The CTs according to class C must have a calculated rated equivalent limitingsecondary e.m.f. EalANSI that fulfills the following:

alANSI alreqE max imum of E>(Equation 7)

A CT according to ANSI/IEEE is also specified by the knee-point voltageUkneeANSI that is graphically defined from an excitation curve. The knee-point voltageUkneeANSI normally has a lower value than the knee-point e.m.f. according to IEC andBS. UkneeANSI can approximately be estimated to 75 % of the corresponding Ealaccording to IEC 60044 6. Therefore, the CTs according to ANSI/IEEE must have aknee-point voltage UkneeANSI that fulfills the following:

EkneeANSI > 0.75 · (maximum of Ealreq) (Equation 8)



REG 670

3.2 Voltage transformer requirements

The performance of a protection function will depend on the quality of the measuredinput signal. Transients caused by capacitive voltage transformers (CVTs) can affectsome protection functions.

Magnetic or capacitive voltage transformers can be used.

The capacitive voltage transformers (CVTs) should fulfill the requirements accordingto the IEC 60044–5 standard regarding ferro-resonance and transients. The ferro-resonance requirements of the CVTs are specified in chapter 7.4 of the standard.

The transient responses for three different standard transient response classes, T1, T2and T3 are specified in chapter 15.5 of the standard. CVTs according to all classescan be used.

The protection IED has effective filters for these transients, which gives secure andcorrect operation with CVTs.

3.3 SNTP server requirements

The SNTP server to be used shall be connected to the local network, i.e. not morethan 4-5 switches/routers away from the IED. The SNTP server shall be dedicatedfor its task, or at least equipped with at real-time operating system, i.e. not a PC withSNTP server software. The SNTP server shall be stable, i.e. either synchronized froma stable source like GPS, or local i.e. without synchronization. Using a local SNTPserver i.e. without synchronization as primary or secondary server in a redundantconfiguration is not recommended.



49

Section 4 IED application

About this chapterThis chapter describes the use of the included software functions in the IED. Thechapter discuss application possibilities and gives guidelines for calculating settingsfor a particular application.

4.1 General IED application

The REG 670 IED is used for protection, control and monitoring of generators andgenerator-transformer blocks from relatively small units up to the largest generatingunits. The IED has a comprehensive function library, covering the requirements formost generator applications. The large number of analog inputs available enables,together with the large functional library, integration of many functions in one IED.In typical applications two units can provide total functionality, also providing a highdegree of redundancy. REG 670 can as wll be used for protection and control of shuntreactors.

The protection function library includes differential protection for generator, block,auxiliary transformer and the whole generator block. Stator earth fault protection,both traditional 95% protection as well as 100% 3rd harmonic based stator earth faultprotection are included. The 100% protection uses a differential voltage approachgiving high sensitivity and a high degree of security. Well proven algorithms for poleslip, underexcitation, rotor earth fault, negative sequence current protections, etc. areincluded in the IED.

The generator differential protection in the REG 670 IED adapted to operate correctlyfor generator applications where factors as long DC time constants and requirementon short trip time have been considered.

As many of the protection functions can be used as multiple instances there arepossibilities to protect more than one object in one IED. It is possible to haveprotection for an auxiliary power transformer integrated in the same IED having mainprotections for the generator. The concept thus enables very cost effective solutions.

The REG 670 IED also enables valuable monitoring possibilities as many of theprocess values can be transferred to an operator HMI.

The wide application flexibility makes this product an excellent choice for both newinstallations and for refurbishment in existing power plants.

Serial data communication is via optical connections to ensure immunity againstdisturbances.

Section 4IED application


51

The wide application flexibility makes this product an excellent choice for both newinstallations and the refurbishment of existing installations.

4.2 Analog inputs

4.2.1 ApplicationIn order to get correct measurement results as well as correct protection operationsthe analog input channels must be configured and properly set. For power measuringand all directional and differential functions the directions of the input currents mustbe properly defined. The measuring and protection algorithms in IED 670 are usingprimary system quantities and the set values are done in primary quantities as well.Therefore it is extremely important to properly set the data about the connected currentand voltage transformers.

In order to make Service Values reading easier it is possible to define a referencePhaseAngleRef. Then this analog channels phase angle will be always fixed to zerodegree and all other angle information will be shown in relation to this analog input.During testing and commissioning of the IED the reference channel can be freelychange in order to facilitate testing and service values reading.

VT inputs are sometimes not available depending on ordered type ofTransformer Input Module (TRM).

4.2.2 Setting guidelines

The available setting parameters related to analog inputs aredepending on the actual hardware (TRM) and the logic configurationmade in PCM 600.

4.2.2.1 Setting of the phase reference channel

All phase angles are calculated in relation to a defined reference. An appropriateanalog input channel is selected and used as phase reference. The parameterPhaseAngleRef defines the analog channel that is used as phase angle reference

ExampleThe setting PhaseAngleRef=7 shall be used if a phase-to-earth voltage (usually theL1 phase-to-earth voltage connected to VT channel number 7 of the analog card) isselected to be the phase reference.



REG 670

Setting of current channelsThe direction of a current to the IED is depending on the connection of the CT. Unlessindicated otherwise, the main CTs are supposed to be star connected and can beconnected with the star point to the object or from the object. This information mustbe set to the IED. The convention of the directionality is defined as follows: A positivevalue of current, power etc means that the quantity has the direction into the objectand a negative value means direction out from the object. For directional functionsthe direction into the object is defined as Forward and the direction out from the objectis defined as Reverse. See figure 20

Protected ObjectLine, transformer, etc

ForwardReverse

Definition of directionfor directional functions

Measured quantity ispositive when flowing

towards the object

e.g. P, Q, I

ReverseForward


e.g. P, Q, IMeasured quantity ispositive when flowing

towards the object

Set parameterCTStarPoint

Correct Setting is"ToObject"

Set parameterCTStarPoint

Correct Setting is"FromObject"

en05000456.vsd

Figure 20: Internal convention of the directionality in IED 670.

With correct setting of the primary CT direction, CTStarPoint set to FromObject orToObject, a positive quantities always flowing towards the object and a directiondefined as Forward always is looking towards the object. The following examplesshow the principle.

Example 1Two IEDs used for protection of two objects



53

Transformerprotection

TransformerLine

Line

Setting of current input:Set parameter

CTStarPoint withTransformer as

reference object.Correct setting is

"ToObject"

ForwardReverse


Line protection




"ToObject"


CTStarPoint withLine as


"FromObject"

en05000753.vsd

IsIs

Ip Ip Ip

Figure 21: Example how to set CTStarPoint parameters in IED 670

The figure 21 shows the most normal case where the objects have their own CTs. Thesettings for CT direction shall be done according to the figure. To protect the line thedirection of the directional functions of the line protection shall be set to Forward.This means that the protection is looking towards the line.

Example 2Two IEDs used for protection of two objects and sharing a CT



REG 670

Transformerprotection

TransformerLine




"ToObject"

ForwardReverse


Line protection




"ToObject"


CTStarPoint withLine as


"FromObject"

en05000460.vsd

Figure 22: Example how to set CTStarPoint parameters in IED 670.

This example is similar to example 1 but the transformer is feeding just one line andthe line protection uses the same CT as the transformer protection does. The CTdirection is set with different reference objects for the two IEDs though it is the samecurrent from the same CT that is feeding two IEDs. With these settings the directionalfunctions of the line protection shall be set to Forward to look towards the line.

Example 3One IED used to protect two objects



55

Transformer andLine protection

TransformerLine




"ToObject"

ReverseForward

Definition of directionfor directionalline functions




"ToObject"

en05000461.vsd

Figure 23: Example how to set CTStarPoint parameters in IED 670

In this example one IED includes both transformer and line protection and the lineprotection uses the same CT as the transformer protection does. For both current inputchannels the CT direction is set with the transformer as reference object. This meansthat the direction Forward for the line protection is towards the transformer. To looktowards the line the direction of the directional functions of the line protection mustbe set to Reverse. The direction Forward/Reverse is related to the reference objectthat is the transformer in this case.

When a function is set to Reverse and shall protect an object in reverse direction itshall be noted that some directional functions are not symmetrical regarding the reachin forward and reverse direction. It is in first hand the reach of the directional criteriathat can differ. Normally it is not any limitation but it is advisable to have it in mindand check if it is acceptable for the application in question.

If the IED has a sufficient number of analog current inputs an alternative solution isshown in figure 24. The same currents are fed to two separate groups of inputs andthe line and transformer protection functions are configured to the different inputs.The CT direction for the current channels to the line protection is set with the line asreference object and the directional functions of the line protection shall be set toForward to protect the line.



REG 670

Transformer andLine protection

TransformerLine

Setting of current inputfor transformer functions:

Set parameterCTStarPoint withTransformer as


"ToObject"

ForwardReverse

Definition of directionfor directionalline functions

Setting of current inputfor transformer functions:

Set parameterCTStarPoint withTransformer as


"ToObject"

Setting of current inputfor line functions:

Set parameterCTStarPoint with

Line asreference object.Correct setting is

"FromObject"

en05000462.vsd

Figure 24: Example how to set CTStarPoint parameters in IED 670.



57

BusbarProtection

Busbar

1

2

2

1

en06000196.vsd

Figure 25: Example how to set CTStarPoint parameters for REB 670

For busbar protection it is possible to set the CTStarPoint parameters in two ways.

The first solution will be to use busbar as a reference object. In that case for all CTinputs marked with 1 in figure 25, set CTStarPoint=ToObject, and for all CT inputsmarked with 2 in figure 25, set CTStarPoint=FromObject.

The second solution will be to use all connected bays as reference objects. In thatcase for all CT inputs marked with 1 in figure 25, set CTStarPoint=FromObject, andfor all CT inputs marked with 2 in figure 25, set CTStarPoint=ToObject.

Regardless which one of the above two options is selected busbar differentialprotection will behave correctly.



REG 670

The main CT ratios must also be set. This is done by setting the two parametersCTsec and CTprim for each current channel. For a 1000/1 A CT the following settingshall be used: CTprim=1000 (value in A) CTsec=1 (value in A).

Examples how to connect, configure and set CT inputs for mostcommonly used CT connectionsFigure 26 defines the marking of current transformers terminals commonly usedaround the world:

ISec

I Pri

S1 (X1)

P1(H1)

P2(H2)

S2 (X2)

P2(H2)

P1(H1)

x x

a) b) c)

en06000641.vsd

S2 (X2) S1 (X1)

Figure 26: Commonly used markings of CT terminals

Where:

a) is symbol and terminal marking used in this document. Terminals marked with a dot indicatesthe primary and secondary winding terminals with the same (i.e. positive) polarity

b) and c) are equivalent symbols and terminal marking used by IEC (ANSI) standard for CTs. Note thatfor this two cases the CT polarity marking is correct!

It shall be noted that depending on national standard and utility practices ratedsecondary current of a CT has typically one of the following values:

• 1A• 5A

However in some cases the following rated secondary currents are as well used:

• 2A• 10A

IED 670 fully supports all of these rated secondary values.

It is recommended to:



59

• use 1A rated CT input into IED 670 in order to connect CTs with1A and 2A secondary rating

• use 5A rated CT input into IED 670 in order to connect CTs with5A and 10A secondary rating

Example how to connect starwye connected three-phase CT set to IED670Figure 27 gives an example how to connect the star connected three-phase CT set toIED 670. It as well gives overview of required actions by the user in order to makethis measurement available to the built-in protection and control functions within IED670.

789

101112

123456

L1

IL1

IL2

IL3

L2 L3

Protected Object

CT 600/5Star Connected

IL1

IL2

IL3

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

IR

IED 670

en06000642.vsd

1

2

34

5

6

#3Ph I Star#IL1#IL2#IL3#IR#2

Figure 27: Star connected three-phase CT set with star point towards the protected object

Where:

1) shows how to connect three individual phase currents from star connected three-phase CTset to three CT inputs in IED 670.

2) shows how to connect residual/neutral current from the three-phase CT set to the fourth inputsin IED 670. It shall be noted that if this connection is not made the IED 670 will still calculatethis current internally by vectorial summation of the three individual phase currents.




REG 670

3) is TRM module where these current inputs are located. It shall be noted that for all thesecurrent inputs the following setting values shall be entered.

• CTprim=600A• CTsec=5A• CTStarPoint=ToObject

Inside IED 670 only the ratio of the first two parameters is used. The third parameter as setin this example will have no influence on the measured currents (i.e. currents are alreadymeasured towards the protected object).

4) are three connections made in Signal Matrix Tool (i.e. SMT) which connect these three currentinputs to first three input channels of the preprocessing function block 6). Depending on typeof functions which need this current information, more then one preprocessing block mightbe connected in parallel to these three CT inputs.

5) is a connection made in Signal Matrix Tool (i.e. SMT) which connect the residual/neutralcurrent input to the fourth input channel of the preprocessing function block 6). Note that thisconnection in SMT shall not be done if the residual/neutral current is not connected to IED670. In that case the pre-processing block will calculate it by vectorial summation of the threeindividual phase currents.

6) Preprocessing block has a task to digitally filter the connected analog inputs and calculate:

• fundamental frequency phasors for all four input channels• harmonic content for all four input channels• positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequencequantities)

These calculated values are then available for all built-in protection and control functionswithin IED 670, which are connected to this preprocessing function block in the configurationtool. For this application most of the preprocessing settings can be left to the default values.If frequency tracking and compensation is required (this feature is typically required only forIEDs installed in the generating stations) then the setting parameters DFTReference shall beset accordingly.

Another alternative is to have the star point of the three-phase CT set as shown infigure 28:



61

789101112

123456

L1

IL1

IL2

IL3

L2 L3

Protected Object

CT 800/1Star Connected IL1

IL2

IL3AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

IR

IED 670

en06000644.vsd

6

1

3

4

2

5

#3Ph I Star#IL1#IL2#IL3#IR#2

Figure 28: Star connected three-phase CT set with star point from the protectedobject

Please note that in this case everything is done in a similar way as in the abovedescribed example, except that for all used current inputs on the TRM the followingsetting parameters shall be entered:

• CTprim=800A• CTsec=1A• CTStarPoint=FromObject

Inside IED 670 only the ratio of the first two parameters is used. The third parameteras set in this example will invert the measured currents (i.e. turn the currents by 180°)in order to insure that the within IED 670 the currents are measured towards theprotected object.

Example how to connect delta connected three-phase CT set to IED670Figure 29 gives an example how to connect the delta connected three-phase CT setto IED 670. It as well gives overview of required actions by the user in order to makethis measurement available to the built-in protection and control functions within IED670.



REG 670

7

8

910

1112

1

2

34

5

6

L1

IL1

IL2

IL3

L2 L3

Protected Object

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

IED 670

CT

600/

5 in

Del

taD

AB C

onne

cted

IL1-IL2

IL2-IL3

IL3-IL1

1

2 3

4

5

en06000645.vsd

#3Ph I Delta

#IL1-IL2

#IL2-IL3

#IL3-IL1

#Not used

#2

Figure 29: Delta DAB connected three-phase CT set

Where:

1) shows how to connect three individual phase currents from delta connected three-phase CTset to three CT inputs in IED 670.

2) is TRM module where these current inputs are located. It shall be noted that for all thesecurrent inputs the following setting values shall be entered.

• CTprim=600/1.732=346A• CTsec=5A• CTStarPoint=ToObject

Inside IED 670 only the ratio of the first two parameters is used. The third parameter as setin this example will have no influence on the measured currents (i.e. currents are alreadymeasured towards the protected object).




63

3) are three connections made in Signal Matrix Tool (i.e. SMT) which connect these three currentinputs to first three input channels of the preprocessing function block 6). Depending on typeof functions which need this current information, more then one preprocessing block mightbe connected in parallel to these three CT inputs.

4) shows that the fourth input channel of the preprocessing function block shall not be connectedin SMT.





Another alternative is ti have the delta connected CT set as shown in figure 30:

78

9

10

1112

1

23

4

56

L1

IL1

IL2

IL3

L2 L3

Protected Object

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

IED 670

CT

800/

1 in

Del

taD

CA

Con

nect

ed

IL3-IL2

IL2-IL1

IL1-IL3

2 3

4

5

en06000646.vsd

#3Ph I Delta

#IL1-IL2

#IL2-IL3

#IL3-IL1

#Not used

#2

Figure 30: Delta DAC connected three-phase CT set

Please note that in this case everything is done in a similar way as in the abovedescribed example, except that for all used current inputs on the TRM the followingsetting parameters shall be entered:



REG 670

• CTprim=800/1.732=462A• CTsec=1A• CTStarPoint=ToObject

Inside IED 670 only the ratio of the first two parameters is used. The third parameteras set in this example will have no influence on the measured currents (i.e. currentsare already measured towards the protected object).

Example how to connect single-phase CT to IED 670Figure 31 gives an example how to connect the single-phase CT to IED 670. It aswell gives overview of required actions by the user in order to make this measurementavailable to the built-in protection and control functions within IED 670.

Protected Object

7

8

9

10

11

12

1

2

3

4

5

6

L1 L2 L3AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

IED 670

CT

1000

/1IN

P

INP

INP

2

1

3 #NP Current

#Not used

#Not used

#Not used

#INP

#2

4

5

en06000647.vsd

Figure 31: Connections for single-phase CT input



65

Where:

1) shows how to connect single-phase CT input in IED 670.

2) is TRM module where these current inputs are located. It shall be noted that for all thesecurrent inputs the following setting values shall be entered.For connection a) shown in figure 31:


Inside IED 670 only the ratio of the first two parameters is used. The third parameter as setin this example will have no influence on the measured currents (i.e. currents are alreadymeasured towards the protected object).For connection b) shown in figure 31:


Inside IED 670 only the ratio of the first two parameters is used. The third parameter as setin this example will invert the measured currents (i.e. turn the currents by 180o) in order toinsure that the within IED 670 the currents are measured towards the protected object.

3) shows that in this example the first three input channel of the preprocessing block is notconnected in SMT tool.

4) shows the connection made in Signal Matrix Tool (i.e. SMT) which connect this CT input tothe fourth input channel of the preprocessing function block 5).





Setting of voltage channelsAs the IED uses primary system quantities the main VT ratios must be known. Thisis done by setting the two parameters VTsec and VTprim for each voltage channel.The phase-to-phase value can be used even if each channel is connected to a phase-to-earth voltage from the VT.

ExampleConsider a VT with the following data:

132 1103 3kV V

(Equation 9)



REG 670

The following setting should be used: VTprim=132 (value in kV) VTsec=110 (valuein V)

Examples how to connect, configure and set VT inputs for mostcommonly used VT connectionsFigure 32 defines the marking of voltage transformers terminals commonly usedaround the world.

A(H1)

B(H2)

b(X2)

a(X1)

A(H1)

N(H2)

n(X2)

a(X1)

b) c)

A(H1)

N(H2)

dn(X2)

da(X1)

d)

UPri

+ +USec

a)

en06000591.vsd

Figure 32: Commonly used markings of VT terminals

Where:

a) is symbol and terminal marking used in this document. Terminals marked with a dot indicatesthe primary and secondary winding terminals with the same (i.e. positive) polarity

b) is equivalent symbol and terminal marking used by IEC (ANSI) standard for phase-to-earthconnected VT

c) is equivalent symbol and terminal marking used by IEC (ANSI) standard for open deltaconnected VT

d) is equivalent symbol and terminal marking used by IEC (ANSI) standard for phase-to-phaseconnected VT

It shall be noted that depending on national standard and utility practices ratedsecondary voltage of a VT has typically one of the following values:

• 100 V• 110 V• 115 V• 120 V

IED 670 fully supports all of these values and most of them will be shown in thefollowing examples.

Examples how to connect three phase-to-earthground connected VTsto IED 670Figure 33 gives an example how to connect the three phase-to ground connected VTsto IED 670. It as well gives overview of required actions by the user in order to makethis measurement available to the built-in protection and control functions within IED670.



67

192021222324

131415

1617

18

L1

AI07 (I)

AI08 (U)

AI09 (U)

AI10 (U)

AI11 (U)

AI12 (U)

IED 670L2

L3

663

1103

kV

V

5

4

1

3

2

663

1103

kV

V

663

1103

kV

V

en06000599.vsd

#3Ph-E VTs

#UL1

#UL2

#UL3

#Not used

#1

Figure 33: Three phase-to-ground connected VTs

Where:

1) shows how to connect three secondary phase-to-earth voltages to three VT inputs in IED 670

2) is TRM module where these three voltage inputs are located. It shall be noted that for thesethree voltage inputs the following setting values shall be entered:VTprim=66 kVVTsec= 110 VInside IED 670 only the ratio of these two parameters is used. It shall be noted that the ratioof the entered values exactly corresponds to ratio of one individual VT.

6666 3

1101103

=




REG 670

3) are three connections made in Signal Matrix Tool (i.e. SMT) which connect these three voltageinputs to first three input channels of the preprocessing function block 5). Depending on typeof functions which need this voltage information, more then one preprocessing block might beconnected in parallel to these three VT inputs

4) shows that in this example the fourth (i.e. residual) input channel of the preprocessing blockis not connected in SMT tool. Thus the preprocessing block will automatically calculate 3Uoinside by vectorial sum from the three phase to ground voltages connected to the first threeinput channels of the same preprocessing block. Alternatively the fourth input channel can beconnected to open delta VT input, as shown in figure 35.




These calculated values are then available for all built-in protection and control functions withinIED 670, which are connected to this preprocessing function block in the configuration tool.For this application most of the preprocessing settings can be left to the default values.However the following settings shall be set as shown here:VBase=66 kV (i.e. rated Ph-Ph voltage)If frequency tracking and compensation is required (this feature is typically required only forIEDs installed in the generating stations) then the setting parameters DFTReference shall beset accordingly.

Example how to connect two phase-to-phase connected VTs to IED670Figure 34 gives an example how to connect the two phase-to-phase connected VTsto IED 670. It as well gives overview of required actions by the user in order to makethis measurement available to the built-in protection and control functions within IED670. It shall be noted that this VT connection is only used on lower voltage levels(i.e. rated primary voltage below 40 kV).



69

192021222324

13

1415161718

L1

AI07 (I)

AI08 (U)

AI09 (U)

AI10 (U)

AI11 (U)

AI12 (U)

IED 670

L2

L313.8

120kV

V

1

2

3

4

5

#3Ph-Ph VTs#UL1L2

#UL2L3#UL3L1

#Not Used

13.8120

kVV

#1

en06000600.vsd

Figure 34: Two phase-to-phase connected VTs

Where:

1) shows how to connect secondary side of two phase-to-phase VTs to three VT inputs in IED670

2) is TRM module where these three voltage inputs are located. It shall be noted that for thesethree voltage inputs the following setting values shall be entered:VTprim=13.8 kVVTsec=120 VPlease note that inside IED 670 only ratio of these two parameters is used.




REG 670

3) are three connections made in Signal Matrix Tool (i.e. SMT) which connect these threevoltage inputs to first three input channels of the preprocessing function block 5). Dependingon type of functions which need this voltage information, more then one preprocessing blockmight be connected in parallel to these three VT inputs

4) shows that in this example the fourth (i.e. residual) input channel of the preprocessing blockis not connected in SMT tool




These calculated values are then available for all built-in protection and control functionswithin IED 670, which are connected to this preprocessing function block in the configurationtool. For this application most of the preprocessing settings can be left to the default values.However the following settings shall be set as shown here:ConnectionType=Ph-PhVBase=13.8 kVIf frequency tracking and compensation is required (this feature is typically required only forIEDs installed in the generating stations) then the setting parameters DFTReference shall beset accordingly.

Example how to connect the open delta VT to IED 670 for highimpedance earthedgrounded or unearthedungroundedFigure 35 gives an example how to connect the open delta VT to IED 670 for highimpedance grounded or ungrounded power systems. It shall be noted that this typeof VT connection presents secondary voltage proportional to 3Uo3Vo to the IED.

In case of a solid ground fault close to the VT location the primary value of3Uo3Vo will be equal to:

3 3 3Ph Ph Ph EUo U U- -= × = ×(Equation 11)

The primary rated voltage of such VT is always equal to UPh-E. Therefore, three seriesconnected VT secondary windings will give the secondary voltage equal to threetimes the individual VT secondary winding rating. Thus the secondary windings ofsuch open delta VTs quite often has a secondary rated voltage equal to one third ofthe rated phase-to-phase VT secondary voltage (i.e. 110/3V in this particularexample). Figure 35 as well gives overview of required actions by the user in orderto make this measurement available to the built-in protection and control functionswithin IED 670.



71

192021222324

13141516

1718

L1

AI07 (I)

AI08 (U)

AI09 (U)

AI10 (U)

AI11 (U)

AI12 (U)

IED 670L2

L3

6.63

1103

kV

V

+3Uo

6.63

1103

kV

V

6.63

1103

kV

V

1

2

5

4

3 #3Uo Voltage

#Not Used

#Not Used

#Not Used

#3Uo

#1

en06000601.vsd

Figure 35: Open delta connected VT in high impedance earthed power system

Where:

1) shows how to connect the secondary side of open delta VT to one VT input in IED 670.Please note that +3Uo shall be connected to the IED!

2) is TRM module where this voltage input is located. It shall be noted that for this voltage inputthe following setting values shall be entered:

3 6.6 11.43VTprim kV= × =

110sec 3 110

3VT V= × =

Inside IED 670 only the ratio of these two parameters is used. It shall be noted that the ratioof the entered values exactly corresponds to ratio of one individual open delta VT.

6.63 6.6 3

1101103

×=




REG 670


4) shows the connection made in Signal Matrix Tool (i.e. SMT) which connect this voltage inputto the fourth input channel of the preprocessing function block 5).




These calculated values are then available for all built-in protection and control functionswithin IED 670, which are connected to this preprocessing function block in the configurationtool. For this application most of the preprocessing settings can be left to the default values.If frequency tracking and compensation is required (this feature is typically required only forIEDs installed in the generating stations) then the setting parameters DFTReference shallbe set accordingly.

Example how to connect the open delta VT to IED 670 for lowimpedance earthedgrounded or solidly earthedgrounded powersystemsFigure 36 gives an example how to connect the open delta VT to IED 670 for lowimpedance grounded or solidly grounded power systems. It shall be noted that thistype of VT connection presents secondary voltage proportional to 3Uo to the IED.

In case of a solid ground fault close to the VT location the primary value of 3Uo willbe equal to:

33

Ph PhPh E

UUo U-

-= =(Equation 15)

The primary rated voltage of such VT is always equal to UPh-E Therefore, three seriesconnected VT secondary windings will give the secondary voltage equal only to oneindividual VT secondary winding rating. Thus the secondary windings of such opendelta VTs quite often has a secondary rated voltage close to rated phase-to-phase VTsecondary voltage (i.e. 115V or (115/1.732)V as in this particular example). Figure36 as well gives overview of required actions by the user in order to make thismeasurement available to the built-in protection and control functions within IED670.



73

192021222324

131415161718

L1

AI07 (I)

AI08 (U)

AI09 (U)

AI10 (U)

AI11 (U)

AI12 (U)

IED 670L2

L3

1383

1153

kV

V

+3Uo

1383

1153

kV

V

1383

1153

kV

V

1

2

4

3 #3Uo Voltage

#Not used

#Not used

#Not used

#3Uo

#1

5

en06000602.vsd

Figure 36: Open delta connected VT in low impedance earthed power system

Where:

1) shows how to connect the secondary side of open delta VT to one VT input in IED 670.Please note that +3Uo shall be connected to the IED!

2) is TRM module where this voltage input is located. It shall be noted that for this voltageinput the following setting values shall be entered:

1383 138

3VTprim kV= × =

115sec 3 115

3VT V= × =

Inside IED 670 only the ratio of these two parameters is used. It shall be noted that theratio of the entered values exactly corresponds to ratio of one individual open delta VT.

138138 3

1151153

=




REG 670


4) shows the connection made in Signal Matrix Tool (i.e. SMT) which connect this voltageinput to the fourth input channel of the preprocessing function block 5).

5) preprocessing block has a task to digitally filter the connected analog inputs andcalculate:

• fundamental frequency phasors for all four input channels• harmonic content for all four input channels• positive, negative and zero sequence quantities by using the fundamental

frequency phasors for the first three input channels (channel one taken asreference for sequence quantities)

These calculated values are then available for all built-in protection and control functionswithin IED 670, which are connected to this preprocessing function block in theconfiguration tool. For this application most of the preprocessing settings can be left tothe default values.If frequency tracking and compensation is required (this feature is typically required onlyfor IEDs installed in the generating stations) then the setting parametersDFTReference shall be set accordingly.

Example how to connect the neutral point VT to IED 670Figure 37 gives an example how to connect the neutral point VT to IED 670. It shallbe noted that this type of VT connection presents secondary voltage proportionaltoUo to the IED.

In case of a solid ground fault in high impedance grounded or ungrounded systemsthe primary value of Uo voltage will be equal to:

3Ph Ph

Ph E

UUo U-

-= =

3Ph Ph

Ph Gnd

VVo V-

-= =(Equation 19)

Figure 37 as well gives overview of required actions by the user in order to make thismeasurement available to the built-in protection and control functions within IED670.



75

Protected Object

19

20

21

22

23

24

13

14

15

16

17

18

L1 L2 L3AI07 (I)

AI08 (I)

AI09 (I)

AI10 (U)

AI11 (U)

AI12 (U)

IED 670

6.63

100

kV

V

RUo

1

2

3

4

5

#NP Voltage

#Not used

#Not used

#Not used

#UNP

#1

en06000603.vsd

Figure 37: Neutral point connected VT

Where:

1) shows how to connect the secondary side of neutral point VT to one VT input in IED 670.Please note that +Uo shall be connected to the IED!

2) is TRM module where this voltage input is located. It shall be noted that for this voltage inputthe following setting values shall be entered:

6.63.81

3VTprim kV= =

sec 100VT V=

Inside IED 670 only the ratio of these two parameters is used. It shall be noted that the ratioof the entered values exactly corresponds to ratio of the neutral point VT.




REG 670


4) shows the connection made in Signal Matrix Tool (i.e. SMT) which connect this voltage inputto the fourth input channel of the preprocessing function block 5).

5) preprocessing block has a task to digitally filter the connected analog inputs and calculate:



These calculated values are then available for all built-in protection and control functions withinIED 670, which are connected to this preprocessing function block in the configuration tool.For this application most of the preprocessing settings can be left to the default values.If frequency tracking and compensation is required (this feature is typically required only forIEDs installed in the generating stations) then the setting parameters DFTReference shall beset accordingly.

4.2.3 Setting parameters

The available setting parameters related to analog inputs aredepending on the actual hardware (TRM) and the logic configurationmade in PCM 600.

Table 1: General settings for the AISERVAL (AISV-) function

Parameter Range Step Default Unit DescriptionPhaseAngleRef 1 - 24 1 1 Ch Reference channel

for phase anglepresentation

Table 2: Basic general settings for the ANALOGIN12I (TA40-) function

Parameter Range Step Default Unit DescriptionCTStarPoint1 FromObject

ToObject- ToObject - ToObject= towards

protected object,FromObject= theopposite

CTsec1 1 - 10 1 1 A Rated CT secondarycurrent

CTprim1 1 - 99999 1 3000 A Rated CT primarycurrent

CTStarPoint2 FromObjectToObject

- ToObject - ToObject= towardsprotected object,FromObject= theopposite





77

Parameter Range Step Default Unit DescriptionCTprim2 1 - 99999 1 3000 A Rated CT primary

current




























REG 670


















Table 3: Basic general settings for the ANALOGIN9I3U (TC40-) function












79

Parameter Range Step Default Unit DescriptionCTprim2 1 - 99999 1 3000 A Rated CT primary

current




























REG 670






VTsec10 0.001 - 999.999 0.001 110.000 V Rated VT secondaryvoltage

VTprim10 0.05 - 2000.00 0.05 400.00 kV Rated VT primaryvoltage





Table 4: Basic general settings for the ANALOGIN6I6U (TD40-) function

















81




























REG 670

Table 5: Basic general settings for the ANALOGIN6I (TB40-) function




























83

4.3 Local human-machine interface

4.3.1 Human machine interfaceThe local human machine interface is available in a small, and a medium sizedmodel. The principle difference between the two is the size of the LCD. The smallsize LCD can display seven line of text and the medium size LCD can display thesingle line diagram with up to 15 objects on each page.

Up to 12 SLD pages can be defined, depending on the product capability.

The local human machine interface is equipped with an LCD that can display thesingle line diagram with up to 15 objects.

The local human-machine interface is simple and easy to understand – the whole frontplate is divided into zones, each of them with a well-defined functionality:

• Status indication LEDs• Alarm indication LEDs which consists of 15 LEDs (6 red and 9 yellow) with

user printable label. All LEDs are configurable from the PCM 600 tool• Liquid crystal display (LCD)• Keypad with push buttons for control and navigation purposes, switch for

selection between local and remote control and reset• An isolated RJ45 communication port

Figure 38: Example of medium graphic HMI



REG 670

4.3.2 LHMI related functions

4.3.2.1 Introduction

The adaptation of the LHMI to the application and user preferences is made with:

• function block LHMI (LocalHMI)• function block HLED (LEDMonitor)• setting parameters

4.3.2.2 General setting parameters

Table 6: Basic general settings for the localHMI (LHM1-) function

Parameter Range Step Default Unit DescriptionLanguage English

OptionalLanguage- English - Local HMI language

DisplayTimeout 10 - 120 10 60 Min Local HMI displaytimeout

AutoRepeat OffOn

- On - Activation of auto-repeat (On) or not(Off)

ContrastLevel -10 - 20 1 0 % Contrast level fordisplay

DefaultScreen 0 - 0 1 0 - Default screen

EvListSrtOrder Latest on topOldest on top

- Latest on top - Sort order of event list

SymbolFont IECANSI

- IEC - Symbol font for SingleLine Diagram

4.3.3 Indication LEDs

4.3.3.1 Introduction

The function block HLED (LEDMonitor) controls and supplies information aboutthe status of the indication LEDs. The input and output signals of HLED areconfigured with the PCM 600 tool. The input signal for each LED is selectedindividually with the PCM 600 Signal Matrix Tool (SMT). LEDs (number 1–6) fortrip indications are red and LEDs (number 7–15) for start indications are yellow.

Each indication LED on the LHMI can be set individually to operate in six differentsequences; two as follow type and four as latch type. Two of the latching sequencetypes are intended to be used as a protection indication system, either in collecting orrestarting mode, with reset functionality. The other two are intended to be used assignalling system in collecting (coll) mode with an acknowledgment functionality.



85

The light from the LEDs can be steady (-S) or flickering (-F). For details, refer toTechnical reference manual.

4.3.3.2 Setting parameters

Table 7: Basic general settings for the LEDMonitor (HLED-) function

Parameter Range Step Default Unit DescriptionOperation Off

On- Off - Operation mode for

the LED function

tRestart 0.0 - 100.0 0.1 0.0 s Defines thedisturbance length

tMax 0.0 - 100.0 0.1 0.0 s Maximum time for thedefinition of adisturbance

SeqTypeLED1 Follow-SFollow-FLatchedAck-F-SLatchedAck-S-FLatchedColl-SLatchedReset-S

- Follow-S - Sequence type forLED 1
















REG 670

Parameter Range Step Default Unit DescriptionSeqTypeLED8 Follow-S

Follow-FLatchedAck-F-SLatchedAck-S-FLatchedColl-SLatchedReset-S

- Follow-S - sequence type forLED 8

















87

4.4 Basic IED functions

4.4.1 Self supervision with internal event list

4.4.1.1 Application

The protection and control IEDs have a complex design with many includedfunctions. The included self-supervision function and the INTernal signals functionblock provide good supervision of the IED. The fault signals make it easier to analyzeand locate a fault.

Both hardware and software supervision is included and it is also possible to indicatepossible faults through a hardware contact on the power supply module and/orthrough the software communication.

Internal events are generated by the built-in supervisory functions. The supervisoryfunctions supervise the status of the various modules in the IED and, in case of failure,a corresponding event is generated. Similarly, when the failure is corrected, acorresponding event is generated.

Apart from the built-in supervision of the various modules, events are also generatedwhen the status changes for the:

• built-in real time clock (in operation/out of order).• external time synchronization (in operation/out of order).

Events are also generated:

• whenever any setting in the IED is changed.

The internal events are time tagged with a resolution of 1 ms and stored in a list. Thelist can store up to 40 events. The list is based on the FIFO principle, that is, when itis full, the oldest event is overwritten. The list cannot be cleared and its content cannotbe modified.

The list of internal events provides valuable information, which can be used duringcommissioning and fault tracing.

The information can only be retrieved with the aid of a Station Monitoring System(SMS). The PC can be connected either to the port at the front or at the rear of theIED.


The function does not have any parameters available in Local HMI or Protection andControl IED Manager (PCM 600)



REG 670

4.4.2 Time synchronization

4.4.2.1 Application

Use time synchronization to achieve a common time base for the IEDs in a protectionand control system. This makes comparison of events and disturbance data betweenall IEDs in the system possible.

Time-tagging of internal events and disturbances are an excellent help whenevaluating faults. Without time synchronization, only the events within the IED canbe compared to one another. With time synchronization, events and disturbanceswithin the entire station, and even between line ends, can be compared at evaluation.

In the IED 670 IED, the internal time can be synchronized from a number of sources:

• BIN (Binary Minute Pulse)• GPS• SNTP

Out of these, LON and SPA contains two types of synchronization messages:

• Coarse time messages are sent every minute and contain complete date and time,i.e. year, month, day, hour, minute, second and millisecond.

• Fine time messages are sent every second and comprises only seconds andmilliseconds.

The setting tells the IED which of these that shall be used to synchronize the IED.

It is possible to set several time-sources, i.e. for instance both SNTP and GPS, andin that case the IED will automatically choose the time-source that will provide thebest accuracy. At a given point in time, only one time-source will be used.

4.4.2.2 Setting guidelines

System timeThe time is set with years, month, day, hour, minute, second and millisecond.

SynchronizationThe setting parameters for the real-time clock with external time synchronization(TIME) are set via the local HMI or the PCM 600 tool.

TimeSynchWhen the source of time synchronization is selected on the local HMI, the parameteris called TimeSynch. The time synchronization source can also be set from the PCM600 tool. The setting alternatives are:

FineSyncSource which can have the following values:



89

• Off• SPA• LON• BIN (Binary Minute Pulse)• GPS• GPS+SPA• GPS+LON• GPS+BIN• SNTP• GPS+SNTP

CoarseSyncSrc which can have the following values:

• Off• SPA• LON• SNTP• DNP

The function input to be used for minute-pulse synchronization is called TIME-MINSYNC.

The system time can be set manually, either via the local HMI or via any of thecommunication ports. The time synchronization fine tunes the clock (seconds andmilliseconds).


Path in local HMI: Setting/Time

Path in PCM 600: Settings/Time/Synchronization



REG 670

Table 8: Basic general settings for the TimeSynch (TSYN-) function

Parameter Range Step Default Unit DescriptionCoarseSyncSrc Off

SPALONSNTP

- Off - Coarse timesynchronizationsource

FineSyncSource OffSPALONBINGPSGPS+SPAGPS+LONGPS+BINSNTPGPS+SNTP

- Off - Fine timesynchronizationsource

SyncMaster OffSNTP-Server

- Off - Activate IEDassynchronizationmaster

TimeAdjustRate SlowFast

- Fast - Adjust rate for timesynchronization

Table 9: General settings for the TimeSynchBIN (TBIN-) function

Parameter Range Step Default Unit DescriptionModulePosition 3 - 16 1 3 - Hardware position of

IO module for timesynchronization

BinaryInput 1 - 16 1 1 - Binary input numberfor timesynchronization

BinDetection PositiveEdgeNegativeEdge

- PositiveEdge - Positive or negativeedge detection

Table 10: General settings for the TimeSynchSNTP (TSNT-) function

Parameter Range Step Default Unit DescriptionServerIP-Add 0 - 18 1 0.0.0.0 - Server IP-address

RedServIP-Add 0 - 18 1 0.0.0.0 - Redundant server IP-address



91

Table 11: General settings for the DaySumDSTBegin (TSTB-) function

Parameter Range Step Default Unit DescriptionMonthInYear January

FebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember

- March - Month in year whendaylight time starts

DayInWeek SundayMondayTuesdayWednesdayThursdayFridaySaturday

- Sunday - Day in week whendaylight time starts

WeekInMonth LastFirstSecondThirdFourth

- Last - Week in month whendaylight time starts

UTCTimeOfDay 0 - 86400 1 3600 s UTC Time of day inseconds whendaylight time starts



REG 670

Table 12: General settings for the DaySumTimeEnd (TSTE-) function

Parameter Range Step Default Unit DescriptionMonthInYear January

FebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember

- October - Month in year whendaylight time ends

DayInWeek SundayMondayTuesdayWednesdayThursdayFridaySaturday

- Sunday - Day in week whendaylight time ends

WeekInMonth LastFirstSecondThirdFourth

- Last - Week in month whendaylight time ends

UTCTimeOfDay 0 - 86400 1 3600 s UTC Time of day inseconds whendaylight time ends

Table 13: General settings for the TimeZone (TZON-) function

Parameter Range Step Default Unit DescriptionNoHalfHourUTC -24 - 24 1 0 - Number of half-hours

from UTC

Table 14: Basic general settings for the TimeSynchIRIGB (TIRI-) function

Parameter Range Step Default Unit DescriptionSynchType BNC

Opto- Opto - Type of

synchronization

TimeDomain LocalTimeUTC

- LocalTime - Time domain

Encoding IRIG-B13441344TZ

- IRIG-B - Type of encoding

TimeZoneAs1344 MinusTZPlusTZ

- PlusTZ - Time zone as in 1344standard



93

4.4.3 Parameter setting groups

4.4.3.1 Application

Six sets of settings are available to optimize IED operation for different systemconditions. By creating and switching between fine tuned setting sets, either from thehuman-machine interface or configurable binary inputs, results in a highly adaptableIED that can cope with a variety of system scenarios.

Different conditions in networks with different voltage levels require highly adaptableprotection and control units to best provide for dependability, security and selectivityrequirements. Protection units operate with a higher degree of availability, especially,if the setting values of their parameters are continuously optimized according to theconditions in the power system.

Operational departments can plan for different operating conditions in the primaryequipment. The protection engineer can prepare the necessary optimized and pre-tested settings in advance for different protection functions. Six different groups ofsetting parameters are available in the IED. Any of them can be activated through thedifferent programmable binary inputs by means of external or internal control signals.

A function block, SGC, (available in CAP 531) defines how many setting groups areused. Setting is done with parameter MAXSETGR and shall be set to the requiredvalue for each application. Only the number of setting groups set will be available inPST for activation with the ACGR function block.


The setting ActiveSetGrp, which is set via from the local HMI or from the PCM600tool, is used to select which parameter group to be active. The active group can alsobe selected with configured input to the function block SGC.

The length of the pulse, sent out by the output signal SETCHGD when an active grouphas changed, is set with the parameter t.

The parameter MAXSETGR defines the maximum number of setting groups in useto switch between.


Table 15: General settings for the ActiveGroup (ACGR-) function

Parameter Range Step Default Unit Descriptiont 0.0 - 10.0 0.1 1.0 s Pulse length of pulse

when setting changed



REG 670

Table 16: General settings for the NoOfSetGrp (SGC--) function

Parameter Range Step Default Unit DescriptionActiveSetGrp SettingGroup1

SettingGroup2SettingGroup3SettingGroup4SettingGroup5SettingGroup6

- SettingGroup1 - ActiveSettingGroup

NoOfSetGrp 1 - 6 1 1 No Number of possiblesetting groups toswitch between

4.4.4 Test mode functionality

4.4.4.1 Application

The protection and control IEDs have a complex configuration with many includedfunctions. To make the testing procedure easier, the IEDs include the feature toindividually block a single, several or all functions.

This means that it is possible to see when a function is activated or trips. It also enablesthe user to follow the operation of several related functions to check correctfunctionality and to check parts of the configuration etc.


Remember always that there are two possible ways to place the IED in the “Testmode: On” state. If, at the end of one test, you took off the IED from the Test mode,but the functions are still shown being in the test mode, check your configuration —you might have the input on the TEST function block activated.


Table 17: Basic general settings for the Test (TEST-) function

Parameter Range Step Default Unit DescriptionTestMode Off

On- Off - Test mode in

operation (On) or not(Off)

EventDisable OffOn

- Off - Event disable duringtestmode

CmdTestBit OffOn

- Off - Command bit for testrequired or not duringtestmode



95

4.4.5 IED identifiers

4.4.5.1 Application

The IED identifier function is divided into two parts. One part handles factory definedsettings and the other part handles customer specific settings.

Factory defined settingsThe factory defined settings are very useful for identifying a specific version and veryhelpful in the case of maintenance, repair, interchanging IEDs between differentSubstation Automation Systems and upgrading. The factory made settings can not bechanged by the customer. They can only be viewed. The settings are found in thelocal HMI under:

Diagnostics/IED status/Product Identifiers

The following identifiers are available:

• IEDType• Describes the type of the IED (like REL, REC or RET). Example: REL670

• ProductDef• Describes the release number, from the production. Example: 1.1.r01

• FirmwareVer• Describes the firmware version. Example: 1.4.51• Firmware versions numbers are “running” independently from the release

production numbers. For every release numbers (like 1.1.r01) there can beone or more firmware versions, depending on the small issues corrected inbetween releases.

• IEDMainFunType• Main function type code according to IEC 60870-5-103. Example: 128

(meaning line protection).• SerialNo• OrderingNo• ProductionDate

Customer specific settingsThe customer specific settings are used to give the IED an unique name and address.The settings are used by a central control system, for instance micro scada, tocommunicate with the IED. The customer specific identifiers are found in the localHMI under:

Settings/General settings/Power system/Identifiers

The settings can also be made from the PCM600 tool. For more information aboutthe available identifiers, refer to section "Setting parameters".



REG 670


Table 18: General settings for the TerminalID (TEID-) function

Parameter Range Step Default Unit DescriptionStationName 0 - 18 1 Station name - Station name

StationNumber 0 - 99999 1 0 - Station number

ObjectName 0 - 18 1 Object name - Object name

ObjectNumber 0 - 99999 1 0 - Object number

UnitName 0 - 18 1 Unit name - Unit name

UnitNumber 0 - 99999 1 0 - Unit number

4.4.6 Rated system frequency (RFR)

4.4.6.1 Application

The rated system frequency is set under General settings/Power system/PrimaryValues in PCM 600 parameter setting tree.


The parameters for the instantaneous non-directional phase overcurrent protectionfunctions are set via the local HMI or Protection and Control IED Manager (PCM600).

Set the system rated frequency. Refer to section "Signal matrix for analog inputs(SMAI)" for description on frequency tracking.


Table 19: General settings for the RatedFreq (RFR--) function

Parameter Range Step Default Unit DescriptionFrequency 50.0 - 60.0 10.0 60.0 Hz Rated system

frequency

4.4.7 Signal matrix for binary inputs (SMBI)

4.4.7.1 Application

The SMBI function block is used within the CAP tool in direct relation with the SignalMatrix Tool (see the overview of the engineering process in chapter "Engineering ofthe IED"). It represents the way binary inputs are brought in for one IED 670configuration.



97


There are no setting parameters for the SMBI available to the user in PST. However,the user must give a name to the SMBI instance and the SMBI inputs, directly in theCAP tool. These names will define the function block in the Signal Matrix Tool.



4.4.8 Signal matrix for binary outputs (SMBO)

4.4.8.1 Application

The SMBO function block is used within the CAP tool in direct relation with theSignal Matrix Tool (see the overview of the engineering process in chapter "Engineering of the IED"). It represents the way binary outputs are sent from one IED670 configuration.


There are no setting parameters for the SMBO available to the user in PST. However,the user must give a name to the SMBO instance and the SMBO outputs, directly inthe CAP tool. These names will define the function block in the Signal Matrix Tool.



4.4.9 Signal matrix for mA inputs (SMMI)

4.4.9.1 Application

The SMMI function block is used within the CAP tool in direct relation with theSignal Matrix Tool (please see the overview of the engineering process in chapter "Engineering of the IED"). It represents the way milliamp (mA) inputs are broughtin for one IED 670 configuration.


There are no setting parameters for the SMMI available to the user in PST. However,the user must give a name to the SMMI instance and the SMMI inputs, directly in theCAP tool.



REG 670



4.4.10 Signal matrix for analog inputs (SMAI)

4.4.10.1 Application

The SMAI function block (or the pre-processing function block PreProc, as it is alsonamed) is used within the CAP tool in direct relation with the Signal Matrix Tool (seethe overview of the engineering process in chapter "Engineering of the IED"). Itrepresents the way analog inputs are brought in for one IED 670 configuration.


The parameters for the signal matrix for analog inputs (SMAI) functions are set viathe local HMI or Protection and Control Manager (PCM 600).

Every SMAI function block can receive four analog signals (three phases and oneneutral value), either voltage or current. The outputs of the SMAI are givinginformation about every aspect of the 3ph analog signals acquired (phase angle, RMSvalue, frequency and frequency derivates, etc. – 244 values in total). Besides the block“group name”, the analog inputs type (voltage or current) and the analog input namesthat can be set directly in CAP, the user has several settings available in PST:

DFTRefExtOut: Parameter valid for function block PR01, PR13, PR25 only.Reference DFT block for external output (SPFCOUT function output).

DFTReference: Reference DFT block for that specific instance of the SMAI.

These DFT reference block settings decide which DFT block will be used as referencein the calculation of frequency and other values (Internal DFTRef will use set systemfrequency. GrpnAdDFTRef will use calculated frequency from the selected groupblock, ExternalDFTRef will use input DFTSPFC as frequency reference.)

ConnectionType: Connection type for that specific instance (n) of the SMAI (if it isPh-N or Ph-Ph). Depending on connection type setting the not connected Ph-N orPh-Ph outputs will be calculated.

Negation: If the user wants to negate the 3ph signal, it is possible to choose to negateonly the phase signals Negate3Ph, only the neutral signal NegateN or both Negate3Ph+N; negation means rotation with 180° of the vectors.

UBase: Base voltage setting (for each instance n).

MinValFreqMeas: The minimum value of the voltage for which the frequency iscalculated, expressed as percent of UBase (for each instance n).



99

Settings DFTRefExtOut and DFTReference shall be set to defaultvalue InternalDFTRef if no VT inputs are available.

Examples of adaptive frequency tracking

en07000197.vsd

SMAI instance 3 phase groupPR01 1PR02 2PR03 3PR04 4PR05 5PR06 6PR07 7PR08 8PR09 9PR10 10PR11 11PR12 12

Task time group 1


Task time group 2


Task time group 3

AdDFTRefCh7

AdDFTRefCh4

Figure 39: SMAI instances as organized in different task time groups and thecorresponding parameter numbers

The examples shows a situation with adaptive frequency tracking with one referenceselected for all instances. In practice each instance can be adapted to the needs of theactual application.

Example 1



REG 670

07000198.vsd

SMAIPR01-

BLOCKDFTSPFCGRPNAMEAI1NAMEAI2NAMEAI3NAMEAI4NAMETYPE

SYNCOUTSPFCOUT

AI3PAI1AI2AI3AI4AIN

NOSMPLCY

SMAIPR13-


SYNCOUTSPFCOUT

AI3PAI1AI2AI3AI4AIN

NOSMPLCY

SMAIPR25-


SYNCOUTSPFCOUT

AI3PAI1AI2AI3AI4AIN

NOSMPLCY

Figure 40: Configuration for using an instance in task time group 1 as DFTreference

Assume instance PR07 in task time group 1 has been selected in the configuration tocontrol the frequency tracking. Observe that the selected reference instance must bea voltage type.

For task time group 1 this gives the following settings (see Figure 39 for numbering):

PR01: DFTRefExtOut = AdDFTRefCh7 to route PR07 reference to the SPFCOUToutput, DFTReference = AdDFTRefCh7 for PR01 to use PR07 as reference (seeFigure 40) PR02 – PR12: DFTReference = AdDFTRefCh7 for PR02 – PR12 to usePR07 as reference.

For task time group 2 this gives the following settings:

PR13 – PR24: DFTReference = ExternalDFTRef to use DFTSPFC input as reference(PR07)



Example 2



101

07000199.vsd

SMAIPR13-


SYNCOUTSPFCOUT

AI3PAI1AI2AI3AI4AIN

NOSMPLCY

SMAIPR01-


SYNCOUTSPFCOUT

AI3PAI1AI2AI3AI4AIN

NOSMPLCY

SMAIPR25-


SYNCOUTSPFCOUT

AI3PAI1AI2AI3AI4AIN

NOSMPLCY

Figure 41: Configuration for using an instance in task time group 2 as DFTreference.

Assume instance PR16 in task time group 2 has been selected in the configuration tocontrol the frequency tracking for all instances. Observe that the selected referenceinstance must be a voltage type

For task time group 1 this gives the following settings (see Figure 39 for numbering):



PR13: DFTRefExtOut = AdDFTRefCh4 to route PR16 reference to the SPFCOUToutput, DFTReference = AdDFTRefCh4 for PR13 to use PR16 as reference (seeFigure 41) PR14 – PR24: DFTReference = AdDFTRefCh4 to use DFTSPFC input asreference (PR16)






REG 670

Table 20: Basic general settings for the SMAI (PR01-) function

Parameter Range Step Default Unit DescriptionDFTRefExtOut InternalDFTRef

AdDFTRefCh1AdDFTRefCh2AdDFTRefCh3AdDFTRefCh4AdDFTRefCh5AdDFTRefCh6AdDFTRefCh7AdDFTRefCh8AdDFTRefCh9AdDFTRefCh10AdDFTRefCh11AdDFTRefCh12External DFT ref

- InternalDFTRef - DFT reference forexternal output

DFTReference InternalDFTRefAdDFTRefCh1AdDFTRefCh2AdDFTRefCh3AdDFTRefCh4AdDFTRefCh5AdDFTRefCh6AdDFTRefCh7AdDFTRefCh8AdDFTRefCh9AdDFTRefCh10AdDFTRefCh11AdDFTRefCh12External DFT ref

- InternalDFTRef - DFT reference

ConnectionType Ph-NPh-Ph

- Ph-N - Input connection type

TYPE 1 - 2 1 1 Ch 1=Voltage,2=Current

Table 21: Advanced general settings for the SMAI (PR01-) function

Parameter Range Step Default Unit DescriptionNegation Off

NegateNNegate3PhNegate3Ph+N

- Off - Negation

MinValFreqMeas 5 - 200 1 10 % Limit for frequencycalculation in % ofUBase

UBase 0.05 - 2000.00 0.05 400.00 kV Base Voltage



103

Table 22: Basic general settings for the SMAI (PR02-) function

Parameter Range Step Default Unit DescriptionDFTReference InternalDFTRef

AdDFTRefCh1AdDFTRefCh2AdDFTRefCh3AdDFTRefCh4AdDFTRefCh5AdDFTRefCh6AdDFTRefCh7AdDFTRefCh8AdDFTRefCh9AdDFTRefCh10AdDFTRefCh11AdDFTRefCh12External DFT ref


ConnectionType Ph-NPh-Ph

- Ph-N - Input connection type

TYPE 1 - 2 1 1 Ch 1=Voltage,2=Current

Table 23: Advanced general settings for the SMAI (PR02-) function

Parameter Range Step Default Unit DescriptionNegation Off

NegateNNegate3PhNegate3Ph+N

- Off - Negation

MinValFreqMeas 5 - 200 1 10 % Limit for frequencycalculation in % ofUBase


4.4.11 Summation block 3 phase (SUM3Ph)


The analog summation block SUM3Ph function block is used in order to get the sumof two sets of 3 ph analog signals (of the same type) for those IED functions thatmight need it.


The summation block receives the 3ph signals from the SMAI blocks. The summationblock has several settings.

SummationType: Summation type (Group 1+ Group2, Group 1 – Group 2, Group 2-Group 1 or –(Group1 + Group 2)).

DFTReference: The reference DFT block (InternalDFT Ref, Grp1AdDFTRef orExternal DFT ref) as above.



REG 670

FreqMeasMinVal: The minimum value of the voltage for which the frequency iscalculated, expressed as percent of UBase (for each instance n).

UBase: Base voltage setting (for each instance n).


Table 24: Basic general settings for the Sum3Ph (SU01-) function

Parameter Range Step Default Unit DescriptionSummationType Group1+Group2

Group1-Group2Group2-Group1-(Group1+Group2)

- Group1+Group2 - Summation type

DFTReference InternalDFTRefAdDFTRefCh1External DFT ref


Table 25: Advanced general settings for the Sum3Ph (SU01-) function

Parameter Range Step Default Unit DescriptionFreqMeasMinVal 5 - 200 1 10 % Amplitude limit for

frequency calculationin % of Ubase

UBase 0.05 - 2000.00 0.05 400.00 kV Base voltage

4.4.12 Authority status (AUTS)


The AUTS function block (or the authority status function block) is an indicationfunction block, which informs about two events related to the IED and the userauthorization:

• the fact that at least one user has tried to log on wrongly into the IED and it wasblocked (the output USRBLKED)

• the fact that at least one user is logged on (the output LOGGEDON)

The two outputs of the AUTS function block can be used in the configuration fordifferent indication and alarming reasons, or can be sent to the station control for thesame purpose.



105



4.4.13 Goose binary receive


Table 26: Basic general settings for the GooseBinRcv (GB01-) function


On- Off - Operation Off/On

4.5 Differential protection

4.5.1 Generator differential protection (PDIF, 87G)

Function block name: GDPx IEC 60617 graphical symbol:

Id>ANSI number: 87G

IEC 61850 logical node name:GENPDIF

4.5.1.1 Application

Short circuit between the phases of the stator windings causes normally very largefault currents. The short circuit gives risk of damages on insulation, windings andstator core. The large short circuit currents cause large current forces, which candamage other components in the power plant, such as turbine and generator-turbineshaft. The short circuit can also initiate explosion and fire. When a short circuit occursin a generator there is a damage that has to be repaired. The severity and thus therepair time are dependent on the degree of damage, which is highly dependent on thefault time. Fast fault clearance of this fault type is therefore of greatest importance tolimit the damages and thus the economic loss.

To limit the damages in connection to stator winging short circuits, the fault clearancetime must be as fast as possible (instantaneous). Both the fault current contributionsfrom the external power system (via the generator and/or the block circuit breaker)and from the generator itself must be disconnected as fast as possible. A fast reductionof the mechanical power from the turbine is of great importance. If the generator block



REG 670

is connected to the power system close to other generating blocks, the fast faultclearance is essential to maintain the transient stability of the non-faulted generators.

Normally the short circuit fault current is very large, i.e. significantly larger than thegenerator rated current. There is a risk that a short circuit can occur between phasesclose to the neutral point of the generator, thus causing a relatively small fault current.The fault current fed from the generator itself can also be limited due to low excitationof the generator. This is normally the case at running up of the generator, beforesynchronisation to the network. Therefore it is desired that the detection of generatorphase-to-phase short circuits shall be relatively sensitive, thus detecting small faultcurrents.

It is also of great importance that the generator short circuit protection does not tripfor external faults, when large fault current is fed from the generator. In order tocombine fast fault clearance, sensitivity and selectivity the generator currentdifferential protection is normally the best alternative for phase-to-phase generatorshort circuits.

The risk of unwanted operation of the differential protection, caused by currenttransformer saturation, is a universal differential protection problem. If the generatoris tripped in connection to an external short circuit this will first give an increasedrisk of power system collapse. Besides that there will be a production loss for everyunwanted trip of the generator. There is therefore a great economic value to preventunwanted disconnection of power generation.

The generator application gives a special situation, where the short circuit fault currentwith a large DC component, can have the first zero crossing of the current, afterseveral periods. This is due to the long DC time constant of the generator (up to 150ms), see figure 42.

The generator differential protection is also well suited to give fast, sensitive andselective fault clearance if used for shunt reactors and small busbars.



107

t

I(t)

en06000312.vsd

Figure 42: Zero crossing of the current


The generator differential protection in REG 670 makes evaluation in different sub-functions in the differential function.

1. Percentage restrained differential analysis2. DC, 2nd and 5th harmonic analysis3. Internal/external fault discriminator

Adaptive frequency tracking must be properly configure and set forthe analog preprocessing blocks (SMAI) in order to insure properoperation of the generator differential protection function.

General settingsCurrRated: CurrRated is the rated current of the generator, set in primary A.

InvertCT2Curr: It is normally assumed that the secondary winding of the CT:s of thegenerator are earthed towards the generator, as shown in figure 43. In this case theparameter InvertCT2Curr is set to false(0).



REG 670

xx06000430.vsd

Figure 43: Position of current transformers

If the generator differential protection is used in a transformer protection IED thedirection of CT is refereed to the transformer differential protection. This might givewrong reference direction of the generator terminal side CT. This can be adjusted bysetting the parameter InvertCT2curr to 1

Operation: The generator differential protection function is set on or off with thissetting.

Percentage restrained differential operationThe characteristic of the restrain differential protection is shown in figure 44. Thecharacteristic is defined by the settings:

1. IdMin2. EndSection13. EndSection24. SlopeSection25. SlopeSection3



109

Section 1

Operateconditionally

UnrestrainedLimit

Section 2 Section 3

Restrain

Operateunconditionally

5

4

3

2

1

00 1 2 3 4 5

IdMin

EndSection1

EndSection2restrain current

[ times I1r ]

operate current[ times I1r ]

SlopeSection2

SlopeSection3

en05000187.vsd

Figure 44: Operate - restrain characteristic

100%Ioperateslope IrestrainD= D ×

(Equation 22)

IdMin: IdMin is the constant sensitivity of section 1. This setting can normally bechosen to 0.10 times the generator rated current.

In section 1 the risk of false differential current is very low. This is the case, at leastup to 1.25 times the generator rated current. EndSection1 is proposed to be set to 1.25times the generator rated current.

In section 2, a certain minor slope is introduced which is supposed to cope with falsedifferential currents proportional to higher than normal currents through the currenttransformers. EndSection2 is proposed to be set to about 3 times the generator ratedcurrent. The SlopeSection2, defined as the percentage value of DIdiff/DIBias, isproposed to be set to 40%, if no deeper analysis is done.

In section 3, a more pronounced slope is introduced which is supposed to cope withfalse differential currents related to current transformer saturation. TheSlopeSection3, defined as the percentage value of DIdiff/DIBias, is proposed to be setto 80 %, if no deeper analysis is done.



REG 670

IdUnre: IdUnre is the sensitivity of the unrestrained differential protection function.The choise of setting value can be based on calculation of the largest short circuitcurrent from the generator at fault in the external power system (normally three phaseshort circuit at the busbar to which the generator block is connected). IdUnre is setas a multiple of the generator rated current.

OpCrossBlock: OpCrossBlock is set on, activation of the harmonic blocking in onephase. If the function is set on, activation of the harmonic blocking in one phase willblock the other phases too.

Negative sequence subfunctionsOpNegSeqDiff: OpNegSeqDiff is set on or off for activation of the negative sequencedifferential functions, both the internal/external fault discrimination and the sensitivenegative sequence differential current function. It is recommended to have thisfunction enabled.

IMinNegSeq: IMinNegSeq is the setting of the smallest negative sequence currentwhen the negative sequence based functions shall be active. This sensitivity cannormally be set down to 0.04 times the generator rated current, to enable very sensitiveprotection function. As the sensitive negative sequence differential protectionfunction is blocked at high currents the high sensitivity does not give risk of unwantedfunction.

NegSeqROA: NegSeqROA is the “Relay Operate Angle” as described in figure 45.



111

30

60

90

120

150

180

210

240

270

300

330

CT1 I- : Reference

Internal Fault ZoneExternal Fault ZoneROA

en06000433.vsd

Figure 45: NegSeqROA: NegSeqROA determines the boundary between theinternal- and external fault regions

The default value 60° is recommended for high degree of dependability and security.

Other additional optionsHarmDistLimit: HarmDistLimit is the total harmonic distortion (2nd and 5th harmonic)for the harmonic restrain pick-up. The default limit 10% can be used in normal cases.In special application, for example close to power electronic converters, a highersetting might be used to prevent unwanted blocking.

TempIdMin: If the binary input raise pick-up (DESENSIT) is activated the operationlevel of IdMin is increased to the TempIdMin.



REG 670

Section 1


UnrestrainedLimit

Section 2 Section 3

Restrain


5

4

3

2

1

00 1 2 3 4 5

IdMin

EndSection1


[ times I1r ]


SlopeSection2

SlopeSection3

en06000637.vsd

TempIdMin

Figure 46: The value of TempIdMin


(Equation 23)

AddTripDelay: If the input DESENSIT is activated also the operation time of theprotection function can be increase be the setting AddTripDelay.

OperDCBiasing: OperDCBiasing is set on or off for activation of the option wherealso the DC component of the differential function influence the sensitivity of thebiased differential protection. If enabled the DC component of the differential currentwill be included in the bias current with a slow decay. The option can be used toincrease security if the DC time constant is very long, thus giving risk of currenttransformer saturation, even if the fault current is small. It is recommended to setOperDCBiasing on if the current transformers on the two sides of the generator is ofdifferent make with have different operating characteristics. It is also recommendedto set the parameter on for all shunt reactor applications.




113

Table 27: Basic general settings for the GENPDIF_87G (GDP1-) function

Parameter Range Step Default Unit DescriptionIBase 100.0 - 100000.0 0.1 5000.0 A Rated current of

protected generator,Amperes

InvertCT2Curr NoYes

- No - Invert CT 2 curr., yes(1) or no (0). Default isno (0).

Table 28: Basic parameter group settings for the GENPDIF_87G (GDP1-) function


On- Off - Operation Off / On

IdMin 0.05 - 1.00 0.01 0.25 IB Section 1 sensitivity,multiple of generatorrated current

IdUnre 1.00 - 50.00 0.01 10.00 IB Unrestr. prot. limit,multiple of generatorrated current

OpNegSeqDiff NoYes

- Yes - Negative SequenceDifferential EnableOff/On

IMinNegSeq 0.02 - 0.20 0.01 0.04 IB Neg. sequence curr.limit, as multiple ofgen. rated curr.

Table 29: Advanced parameter group settings for the GENPDIF_87G (GDP1-) function

Parameter Range Step Default Unit DescriptionEndSection1 0.20 - 1.50 0.01 1.25 IB End of section 1,

multiple of generatorrated current

EndSection2 1.00 - 10.00 0.01 3.00 IB End of section 2,multiple of generatorrated current

SlopeSection2 10.0 - 50.0 0.1 40.0 % Slope in section 2 ofoperate-restraincharacteristic, in %


OpCrossBlock NoYes

- Yes - Operation On / Off forcross-block logicbetween phases

NegSeqROA 30.0 - 120.0 0.1 60.0 Deg Operate Angle of int/ext neg. seq. faultdiscriminator, deg

HarmDistLimit 5.0 - 100.0 0.1 10.0 % (Total) relativeharmonic distorsionlimit, percent




REG 670

Parameter Range Step Default Unit DescriptionTempIdMin 1.0 - 5.0 0.1 2.0 IdMin Temp. Id pickup when

input raisePickUp=1,multiple of IdMin

AddTripDelay 0.000 - 60.000 0.001 0.100 s Additional trip delay,when inputraisePickUp=1

OperDCBiasing OffOn

- Off - Operation DC biasingOn / Off

4.5.2 Transformer differential protection (PDIF, 87T)

Table 30: Transformer differential protection, two winding

Function block name: T2Dx- IEC 60617 graphical symbol:

3Id/I

ANSI number: 87T

IEC 61850 logical node name:T2WPDIF

Table 31: Transformer differential protection, three winding

Function block name: T3Dx- IEC 60617 graphical symbol:

3Id/I

ANSI number: 87T

IEC 61850 logical node name:T3WPDIF

4.5.2.1 Application

The transformer differential protection is a unit protection. It serves as the mainprotection of transformers in case of winding failure. The protective zone of adifferential protection includes the transformer itself, the bus-work or cables betweenthe current transformer and the power transformer. When bushing currenttransformers are used for the differential relay, the protective zone does not includethe bus-work or cables between the circuit breaker and the power transformer.

In some substations there is a current differential protection for the busbar. Such abusbar protection will include the bus-work or cables between the circuit breaker andthe power transformer. Internal electrical faults are very serious and will causeimmediate damage. Short-circuits and earth-faults in windings and terminals willnormally be detected by the differential protection. Interturn faults, which areflashovers between conductors within the same physical winding, is also possible to



115

detect if a large enough number of turns are short-circuited. Interturn faults are themost difficult transformer winding faults to detect with electrical protections. A smallinterturn fault including just a few turns will result in an undetectable amount ofcurrent until it develops into an earth-fault. For this reason it is important that thedifferential protection has a high level of sensitivity and that it is possible to use asensitive setting without causing unwanted operations for external faults.

It is important that the faulty transformer be disconnected as fast as possible. As thedifferential protection is a unit protection it can be designed for fast tripping, thusproviding selective disconnection of the faulty transformer. The differentialprotection should never operate on faults outside the protective zone.

A transformer differential protection compares the current flowing into thetransformer with the current leaving the transformer. A correct analysis of faultconditions by the differential protection must take into consideration changes tovoltages, currents and phase angles. Traditional transformer differential protectionfunctions required auxiliary transformers for correction of the phase shift and ratio.The numerical microprocessor based differential algorithm as implemented in theIED compensate for both the turns-ratio and the phase shift internally in the software.No auxiliary current transformers are necessary.

The differential current should theoretically be zero during normal load or externalfaults if the turn-ratio and the phase shift are correctly compensated. However, thereare several different phenomena other than internal faults that will cause unwantedand false differential currents. The main reasons for unwanted differential currentsare:

• mismatch due to varying tap changer positions• different characteristics, loads and operating conditions of the current

transformers• zero sequence currents that only flow on one side of the power transformer• normal magnetizing currents• magnetizing inrush currents• overexcitation magnetizing currents


The parameters for the Transformer differential protection function are set via thelocal HMI or Protection and Control IED Manager (PCM 600). Refer to the Settingparameters tables, in section "Setting parameters"

Inrush restraint methodsWith a combination of the second harmonic restraint and the waveform restraintmethods it is possibly to get a protection with high security and stability against inrusheffects and at the same time maintain high performance in case of heavy internal faultseven if the current transformers are saturated. Both these restraint methods are usedby RET 670. The second harmonic restraint function has a settable level. If the ratioof the second harmonic to fundamental harmonic in the differential current is above



REG 670

the settable limit, the operation of the differential protection is restrained. It isrecommended to set parameter I2/I1Ratio = 15% as default value in case no specialreasons exist to choose other value.

Overexcitation restraint methodOverexcitation current contains odd harmonics, because the waveform is symmetricalabout the time axis. As the third harmonic currents cannot flow into a delta winding,the fifth harmonic is the lowest harmonic which can serve as a criterion foroverexcitation. The overexcitation on the delta side will produce exciting currentsthat contain a large fundamental frequency component with little odd harmonics. Inthis application the fifth harmonic limit must be set to a relatively low value. IED 670differential protection function is provided with a fifth harmonic restraint to preventthe protection from operation during an overexcitation condition of a powertransformer. If the ratio of the fifth harmonic to fundamental harmonic in thedifferential current is above a settable limit the operation is restrained. It isrecommended to use I5/I1Ratio = 25% as default value in case no special reasonsexist to choose another setting. Transformers likely to be exposed to overvoltage orunderfrequency conditions (i.e. generator step-up transformers in power stations)should be provided with an overexcitation protection based on V/Hz to achieve tripbefore the core thermal limit is reached.

Cross-blocking between phasesBasic definition of the cross-blocking is that one of the three phases can blockoperation (i.e. tripping) of the other two phases due to the properties of the differentialcurrent in that phase (i.e. waveform, 2nd or 5th harmonic content). In the algorithmthe user can control the cross-blocking between the phases via the setting parameterOpCrossBlock. When parameter OpCrossBlock is set to On, cross blocking betweenphases will be introduced. There is not any time settings involved, but the phase withthe operating point above the set bias characteristic will be able to cross-block othertwo phases if it is self-blocked by any of the previously explained restrained criteria.As soon as the operating point for this phase is below the set bias characteristic crossblocking from that phase will be inhibited. In this way cross-blocking of the temporarynature is achieved. In should be noted that this is the default (i.e. recommended)setting value for this parameter. When parameter OpCrossBlock is set to Off, anycross blocking between phases will be disabled.

Restrained and unrestrained differential protectionTo make a differential relay as sensitive and stable as possible, restrained differentialprotections have been developed and are now adopted as the general practice in theprotection of power transformers. The protection should be provided with aproportional bias, which makes the protection operate for a certain percentagedifferential current related to the current through the transformer. This stabilizes theprotection under through fault conditions while still permitting the system to havegood basic sensitivity. The bias current can be defined in many different ways. Oneclassical way of defining the bias current has been Ibias = (I1 + I2) / 2, where I1 isthe magnitude of the power transformer primary current, and I2 the magnitude of thepower transformer secondary current. However, it has been found that if the biascurrent is defined as the highest power transformer current this will reflect the



117

difficulties met by the current transformers much better. The differential protectionfunction uses the highest current of all restrain inputs as bias current. For applicationswhere the power transformer rated current and the CT primary rated current can differconsiderably, (applications with T-connections), measured currents in the Tconnections are converted to pu value using the rated primary current of the CT, butone additional "measuring" point is introduced as sum of this two T currents. Thissummed current is converted to pu value using the power transformer winding ratedcurrents. After that the highest pu value is taken as bias current in pu. In this way bestpossible combination between sensitivity and security for differential protectionfunction with T connection is obtained. The main philosophy behind the principlewith the operate bias characteristic is to decrease the operate sensitivity when thecurrent transformers have difficult operating conditions. This bias quantity gives thebest stability against an unwanted operation of the overall differential protection.

The usual practice for transformer protection is to set the bias characteristic to a valueof at least twice the value of the expected spill current under through faults conditions.These criteria can vary considerably from application to application and are often amatter of judgment. The second slope is increased to ensure stability under heavythrough fault conditions which could lead to increased differential current due tosaturation of current transformers. Default settings for the operating characteristicwith IdMin = 0.3pu of the power transformer rated current can be recommended asa default setting in normal applications. If the conditions are known more in detail,higher or lower sensitivity can be chosen. The selection of suitable characteristicshould in such cases be based on the knowledge of the class of the currenttransformers, availability of information on the on load tap changer (OLTC) position,short circuit power of the systems, etc.

Transformers can be connected to buses in such ways that the current transformersused for the differential protection will be either in series with the power transformerwindings or the current transformers will be in breakers that are part of the bus, suchas a breaker-and-a-half or a ring bus scheme. For current transformers with primariesin series with the power transformer winding, the current transformer primary currentfor external faults will be limited by the transformer impedance. When the currenttransformers are part of the bus scheme, as in the breaker-and-a-half or the ring busscheme, the current transformer primary current is not limited by the powertransformer impedance. High primary currents may be expected. In either case, anydeficiency of current output caused by saturation of one current transformer that isnot matched by a similar deficiency of another current transformer will cause a falsedifferential current to appear. Differential protection can overcome this problem ifthe bias is obtained separately from each set of current transformer circuits. It istherefore important to avoid paralleling of two or more current transformers forconnection to a single restraint input. Each current connected to RET 670 is availablefor biasing the differential protection function.

Unrestrained operation level has default value of IdUnre = 10pu, which is typicallyacceptable for most of the standard power transformer applications. However in thefollowing cases these setting need to be changed accordingly:

• When CT from "T-connection" are connected to IED, as in the breaker-and-a-half or the ring bus scheme, special care shall be taken in order to prevent



REG 670

unwanted operation of transformer differential relay for through-faults due todifferent CT saturation of "T-connected" CTs. Thus if such uneven saturation isa possibility it is typically required to increase unrestrained operational level toIdUnre = 20-25pu

• For differential applications on HV shunt reactors, due to a fact that there is noheavy through-fault conditions, the unrestrained differential operation level canbe set to IdUnre = 1.75pu

Overall operating characteristic of transformer differential protection is shown infigure 47 below:

Section 1


UnrestrainedLimit

Section 2 Section 3

Restrain


5

4

3

2

1

00 1 2 3 4 5

IdMin

EndSection1


[ times I1r ]


SlopeSection2

SlopeSection3

en05000187.vsd

Figure 47: Description of the restrained-, and the unrestrained operatecharacteristics


and where the restrained characteristic is defined by the settings:

1. IdMin

2. EndSection1




119

3. EndSection2

4. SlopeSection2

5. SlopeSection3

Elimination of zero sequence currentsA differential protection may operate unwanted due to external earth faults in caseswhere the zero sequence current can flow only on one side of the power transformerbut not on the other side. This is the situation when the zero sequence current cannotbe properly transformed to the other side of the power transformer. Power transformerconnection groups of Wye/Delta(Yd) or Delta/Wye(Dy) type cannot transform thezero sequence current. If a delta winding of a power transformer is earthed via anearthing transformer inside the zone protected by the differential protection there willbe an unwanted differential current in case of an external earth fault. To make theoverall differential protection insensitive to external earth faults in these situationsthe zero sequence currents must be eliminated from the power transformer terminalcurrents, so that they do not appear as the differential currents. This had once beenachieved by means of interposing auxiliary current transformers. The elimination ofzero sequence current is done numerically and no auxiliary transformers or zerosequence traps are necessary. Instead it is necessary to eliminate the zero sequencecurrent from every individual winding by proper setting of setting parametersZSCurrSubtrWx=Off/On.

External/Internal fault discriminatorThe internal/external fault discriminator operation is based on the relative position ofthe two phasors (in case of two-winding transformer) representing W1 and W2negative-sequence current contributions, defined by matrix expression see“Technical reference manual”. It practically performs directional comparisonbetween these two phasors.

In order to perform directional comparison of the two phasors their magnitudes mustbe high enough so that one can be sure that they are due to a fault. On the other hand,in order to guarantee a good sensitivity of the internal/external fault discriminator,the value of this minimum limit must not be too high. Therefore this limit value, calledIMinNegSeq, is settable in the range from 1% to 20% of the differential protectionsbase current, which is in our case the power transformer HV side rated current. Thedefault value is 4%. Only if magnitudes of both negative sequence currentcontributions are above the set limit, the relative position between these two phasorsis checked. If either of the negative sequence current contributions, which should becompared, is too small (less than the set value for IMinNegSeq), no directionalcomparison is made in order to avoid the possibility to produce a wrong decision.This magnitude check, as well guarantee stability of the algorithm, when powertransformer is energized.

The setting NegSeqROA represents the so-called Relay Operate Angle, whichdetermines the boundary between the internal and external fault regions. It can beselected in the range from 30 degrees to 90 degrees, with a step of 1 degree. The



REG 670

default value is 60 degrees. The default setting somewhat favors security incomparison to dependability.

If the above condition concerning magnitudes is fulfilled, the internal/external faultdiscriminator compares the relative phase angle between the negative sequencecurrent contributions from the HV side and LV side of the power transformer usingthe following two rules:

• If the negative sequence currents contributions from HV and LV sides are inphase, the fault is internal (i.e. both phasors are within internal fault region)

• If the negative sequence currents contributions from HV and LV sides are 180degrees out of phase, the fault is external (i.e. HV phasors is outside internal faultregion)

Therefore, under all external fault condition, the relative angle is theoretically equalto 180 degrees. During internal fault, the angle shall ideally be 0 degrees, but due topossible different negative sequence source impedance angles on HV and LV side ofpower transformer, it may differ somewhat from the ideal zero value.

As the internal/external fault discriminator has proved to be very reliable, it has beengiven a great power. If, for example, a fault has been detected, i.e. PICKUP signalsset by ordinary differential protection, and at the same time the internal/external faultdiscriminator characterized this fault as internal, then any eventual block signalsproduced by either the harmonic or the waveform restraints, are ignored. This assuresthe response times of the new and advanced differential protection below one powersystem cycle (i.e. below 20 ms for 50 Hz system) for all internal faults. Even for heavyinternal faults with severely saturated current transformers new differential protectionoperates well below one cycle because the harmonic distortions in the differentialcurrents do not slow down the differential protection operation. Practically, anunrestrained operation is achieved for all internal faults.

External faults happen ten to hundred times more often than internal ones. If adisturbance has been detected and the internal/external fault discriminatorcharacterized this fault as external fault, the additional criteria are posed on thedifferential algorithm before its trip is allowed. This assures high algorithm stabilityduring external faults. However, in the same time the differential relay is still capableto trip for evolving faults.

The principle of the internal/external fault discriminator can be extended to powertransformers and autotransformers with three windings. If all three windings areconnected to their respective networks, then three directional comparisons can bedone, but only two comparisons are necessary in order to positively determine theposition of the fault with respect to the protected zone. The directional comparisons,which are possible, are: W1 - W2, W1 - W3, and W2 - W3. The rule applied by theinternal / external fault discriminator in case of three-winding power transformers is:



121

• If all comparisons indicate an internal fault, then it is an internal fault.• If any comparison indicates an external fault, then it is an external fault

If one of the windings is not connected, the algorithm automatically reduces to thetwo-winding version. Nevertheless, the whole power transformer is protected,inclusive the non-connected winding.

On-line compensation for on-load tap-changer movementTransformer differential function in IED 670 has a built-in facility to on-linecompensate for on-load tap-changer operation. The following parameters which areset under general settings are related to this compensation feature:

• Parameter LocationOLTC1 defines the winding where first OLTC (i.e. OLTC1)is physically located. The following options are available: Not Used / Winding1 / Winding 2 / Winding 3. When value “Not Used” is selected the differentialfunction will assume that OLTC1 doesn’t exist and it will disregard all otherparameters related to first OLTC

• Parameter LowTapPosOLTC1 defines the minimum end tap position for OLTC1(typically position 1)

• Parameter RatedTapOLTC1 defines the rated (e.g. mid) position for OLTC1 (e.g.11 for OLTC with 21 positions) This tap position shall correspond to the valuesfor rated current and voltage set for that winding

• Parameter HighTapPsOLTC1 defines the maximum end tap position for OLTC1(e.g. 21 for OLTC with 21 positions)

• Parameter TapHighVoltTC1 defines the end position for OLTC1 where highestno-load voltage for that winding is obtained (e.g. position with maximum numberof turns)

• Parameter StepSizeOLTC1 defines the voltage change per OLTC1 step (e.g.1.5%)

The above parameters are defined for OLTC1. Similar parameters shall be set forsecond OLTC designeated with OLTC2 in the parameter names, for 3–windingdifferential protection.

Differential current alarmDifferential protection continuously monitors the level of the fundamental frequencydifferential currents and gives an alarm if the pre-set value is simultaneously exceededin all three phases. This feature can be used to monitor the integrity of OLTCcompensation within the differential function. The threshold for the alarm pickuplevel is defined by setting parameter IdiffAlarm. This threshold should be typicallyset in such way to obtain operation when OLTC measured value within differentialfunction differs for more than two steps from the actual OLTC position. To obtainedsuch operation set parameter IdiffAlarm equal to two times the OLTC step size (e.g.typical setting value 2% to 4%). Set the time delayed defined by parametertAlarmDelay two times longer than the OLTC mechanical operating time (e.g. typicalsetting value 10s).



REG 670

Open CT detectionTransformer differential function in RET 670 has a built-in, advanced open CTdetection feature. This feature can block the unexpected operation created by thetransformer differential protection function in case of open CT secondary circuitunder normal load condition. An alarm signal can also be issued to substationoperational personal to make remedy action once the open CT condition is detected.

The following settings parameters are related to this feature:

• Setting parameter OpenCTEnable enables/disables this feature• Setting parameter tOCTAlarmDelay defines the time delay after which the alarm

signal will be given• Setting parameter tOCTReset defines the time delay after which the open CT

condition will reset once the defective CT circuits have been rectified• Once the open CT condition has been detected, then all the differential protection

functions are blocked except the unrestraint (instantaneous) differentialprotection

The outputs of open CT condition related parameters are listed below:

• OpenCT: Open CT detected• OpenCTAlarm: Alarm issued after the setting delay• OpenCTInput: Open CT in CT group inputs (1 for input 1 and 2 for input 2)• OpenCTPhase: Open CT with phase information (1 for phase L1, 2 for phase

L2, 3 for phase L3)

Switch on to fault featureTransformer differential function in IED 670 has a built-in, advanced switch on tofault feature. This feature can be enabled or disabled by a setting parameterSOTFMode. When “SOTFMode=On” this feature is enabled. However it shall benoted that when this feature is enabled it is not possible to test 2nd harmonic blockingfeature by simply injecting one current with superimposed second harmonic. In thatcase the switch on to fault feature will operate and differential protection will trip.However for real inrush case the differential protection function will properly restrainfrom operation. For more information about operating principles of the switch on tofault feature please read the “Technical Reference Manual”.

4.5.2.3 Setting example

IntroductionDifferential protection for power transformers has been used for decades. In order tocorrectly apply transformer differential protection proper compensation for:



123

• power transformer phase shift (i.e. vector group compensation)

• CT secondary currents magnitude difference on different sides of the protectedtransformer (i.e. ratio compensation)

• zero sequence current elimination (i.e. zero sequence current reduction) shall bedone. In the past this was performed with help of interposing CTs or specialconnection of main CTs (i.e. delta connected CTs). With numerical technologyall these compensations are done in relay software.

This document will demonstrate how this compensation shall be done for RET 670.

The differential transformer in RET 670 is capable to provide differential protectionfor all standard three-phase power transformers without any interposing CTs. It hasbeen designed with assumption that all main CTs will be star connected. For suchapplications it is then only necessary to enter directly CT rated data and powertransformer data as they are given on the power transformer nameplate anddifferential protection will automatically balance itself. However RET 670 can aswell be used in applications where some of main CTs are connected in delta. In suchcases the ratio for main CT connected in delta shall be intentionally set forsqrt(3)=1.732 times smaller than actual ratio of individual phase CTs (e.g. instead of800/5 set 462/5) In case the ratio is 800/2.88A, often designed for such typical deltaconnections, set the ratio as 800/5 in the relay. At the same time the power transformervector group shall be set as Yy0 because the RET 670 shall not internally provideany phase angle shift compensation. The necessary phase angle shift compensationwill be provided externally by delta connected main CT. All other settings shouldhave the same values irrespective of main CT connections. It shall be noted thatirrespective of the main CT connections (i.e. star or delta) on-line reading andautomatic compensation for actual on-load tap-changer position can be used in RET670.

These are internal compensation within the differential function. Theprotected power transformer data are always entered as they are givenon the nameplate. Differential function will by itself correlatenameplate data and select proper reference windings.

Typical main CT connections for transformer differential protectionThree most typical main CT connections used for transformer differential protectionare shown in figure 48. It is assumed that the primary phase sequence isL1-L2-L3.



REG 670

L1IL1

IL1-

IL2

IL2-

IL3

IL3-

IL1

IL1-

IL3

IL2-

IL1

IL3-

IL2

IL1

IL2

IL3

ProtectedTransformer

Winding

CT StarConnected

CT in DeltaDAC Connected

CT in DeltaDAB Connected

IL2

IL3

L2

L3

en06000549.vsd

Figure 48: Commonly used main CT connections for Transformer differential protection.

For star connected main CTs, secondary currents fed to the differential relay:

• are directly proportional to the measured primary currents• are in phase with the measured primary currents• contain all sequence components including zero sequence current component

For star connected main CTs, the main CT ratio shall be set in RET 670 as it is inactual application. The “StarPoint” parameter, for the particular star connectionshown in figure 48, shall be set “ToObject”. If star connected main CTs have theirstar point away from the protected transformer this parameter should be set“FromObject”.

For delta DAC connected main CTs, secondary currents fed to the differential relay:

• are increased sqrt(3) times (i.e. 1.732 times) in comparison with star connectedCTs

• lag by 30° the primary winding currents (i.e. this CT connection rotates currentsby 30° in clockwise direction)

• do not contain zero sequence current component

For DAC delta connected main CT ratio shall be set for sqrt(3) times smaller in RET670 than the actual ratio of individual phase CTs. The “StarPoint” parameter, for thisparticular connection shall be set “ToObject”. It shall be noted that delta DACconnected main CTs must be connected exactly as shown in figure 48.

For delta DAB connected main CTs, secondary currents fed to the differential relay:



125

• are increased sqrt(3) times (i.e. 1.732 times) in comparison with star connectedCTs

• lead by 30° the primary winding currents (i.e. this CT connection rotates currentsby 30° in anti-clockwise direction)

• do not contain zero sequence current component

For DAB delta connected main CT ratio shall be set for sqrt(3) times smaller in RET670 then the actual ratio of individual phase CTs. The “StarPoint” parameter, for thisparticular connection shall be set “ToObject”. It shall be noted that delta DABconnected main CTs must be connected exactly as shown in figure 48.

For more detailed info regarding CT data settings please refer to the three applicationexamples presented in section "Application Examples with RET 670".

Application Examples with RET 670Three application examples will be given here. For each example two differentialprotection solutions will be presented:

• First solution will be with all main CTs star connected.• Second solution will be with delta connected main CT on Y (i.e. star) connected

sides of the protected power transformer.

For each differential protection solution the following settings will be given:

1. Input CT channels on the RET 670 TRM modules.2. General settings for the transformer differential protection where specific data

about protected power transformer shall be entered.

Finally the setting for the differential protection characteristic will be given for allpresented applications.

Example 1: StarWye-delta connected power transformer without tap chargerSingle line diagrams for two possible solutions for such type of power transformerwith all relevant application data are given in figure 49.



REG 670

CT 300/5in Delta(DAC)

CT 800/5Star

20.9 MVA69/12.5 kV

YNd1(YDAC)

CT 300/5Star

CT 800/5Star

20.9 MVA69/12.5 kV

YNd1

(YDAC)

en06000554.vsd

Figure 49: Two differential protection solutions for star-delta connected powertransformer

For this particular power transformer the 69 kV side phase-to-earth no-load voltageslead by 30 degrees the 12.5 kV side phase-to- earth no-load voltages. Thus whenexternal phase angle shift compensation is done by connecting main HV CTs in delta,as shown in the right-hand side in figure 49, it must be ensured that the HV currentsare rotated by 30° in clockwise direction. Thus the DAC delta CT connection mustbe used for 69 kv CTs in order to put 69 kV & 12.5 kV currents in phase.

To ensure proper application of RET 670 for this power transformer it is necessaryto do the following:

1. Check that HV & LV CTs are connected to 5 A CT inputs in RET 670.

2. For second solution make sure that HV delta connected CTs are DAC connected.

3. For star connected CTs make sure how they are stared (i.e. earthed) to/fromprotected transformer.

4. Enter the following settings for all three CT input channels used for the LV sideCTs see table 32.



127

Table 32: CT input channels used for the LV side CTs

Setting parameter Selected value for both solutionsCTprim 800

CTsec 5

CTStarPoint ToObject

5. Enter the following settings for all three CT input channels used for the HV sideCTs, see table 33.

Table 33: CT input channels used for the HV side CTs

Setting parameter Selected value for both solution 1(star connected CT)

Selected value for both solution2 (delta connected CT)

CTprim 300300

1733

=

CTsec 5 5

CTStarPoint From Object ToObject

To compensate for delta connected CTs, see equation 25.

6. Enter the following values for the general settings of the differential protectionfunction, see table 34.

Table 34: General settings of the differential protection function

Setting parameter Select value for both solution 1(starwye connected CT)

Selected value for both solution2 (delta connected CT)

RatedVoltageW1 69 kV 69 kV

RatedVoltageW2 12.5 kV 12.5 kV

RatedCurrentW1 175 A 175 A


ConnectTypeW1 STAR (Y) STAR (Y)

ConnectTypeW2 delta=d star=y 1)

ClockNumberW2 1 [30 deg lag] 0 [0 deg] 1)

ZSCurrSubtrW1 On Off 2)

ZSCurrSubtrW2 Off Off

TconfigForW1 No No

TconfigForW2 No No

LocationOLTC1 Not used Not used

Other Parameters Not relevant for this application.Use default value.

Not relevant for thisapplication. Use default value.

1) To compensate for delta connected CTs2) Zero-sequence current is already removed by connecting main CTs in delta



REG 670

Delta-starwye connected power transformer without tap chargerSingle line diagrams for two possible solutions for such type of power transformerwith all relevant application data are given in figure 50.

CT 1500/5in Delta(DAB)

CT 400/5Star

60 MVA115/24.9 kV

Dyn1(DABY)

CT 1500/5Star

CT 400/5Star

60 MVA115/24.9 kV

Dyn1(DABY)

en06000555.vsd

Figure 50: Two differential protection solutions for delta-star connected powertransformer

For this particular power transformer the 115 kV side phase-to-earth no-load voltageslead for 30° the 24.9 kV side phase-to-earth no-load voltages. Thus when externalphase angle shift compensation is done by connecting main 24.9 kV CTs in delta, asshown in the right-hand side in figure 50, it must be ensured that the 24.9 kV currentsare rotated by 30° in anti-clockwise direction. Thus, the DAB CT delta connection(see Figure 1) must be used for 24.9 kV CTs in order to put 115 kV & 24.9 kV currentsin phase.


1. Check that HV & LV CTs are connected to 5 A CT inputs in RET 670.

2. For second solution make sure that LV delta connected CTs are DAB connected.

3. For star connected CTs make sure how they are 'star'red (i.e. earthed) to/fromprotected transformer.




129


Setting parameter Selected value for both solutionsCTprim 400

CTsec 5

CTStarPoint ToObject

5. Enter the following settings for all three CT input channels used for the LV sideCTs, see table "CT input channels used for the LV side CTs".

CT input channels used for the LV side CTsSetting parameter Selected value for both Solution 1

(star connected CT)Selected value for both Solution2 (delta connected CT)

CTprim 15001500

8663

=

CTsec 5 5

CTStarPoint ToObject ToObject


6. Enter the following values for the general settings of the differential protectionfunction, see table36.

Table 36: General settings of the differential protection

Setting parameter selected value for both Solution 1(star conected CT)

Selected value for both Solution2 (delta connected CT)


Rated VoltageW2 24.9 kV 24.9 kV



ConnectTypeW1 Delta (D) STAR (Y) 1)

ConnectTypeW2 star=y star=y

ClockNumberW2 1 [30 deg lag] 0 [0 deg] 1)

ZSCurrSubtrW1 Off Off

ZSCurrSubtrW2 On On 2)

TconfigForW1 No No

TconfigForW2 No No

LocationOLTC1 Not Used Not Used

Other parameters Not relevant for this application.Use default value.

Not relevant for thisapplication. Use default value.

1) To compensate for delta connected CTs.2) Zero-sequence current is already removed by connecting main CTs in delta.



REG 670

Star-starWye-wye connected power transformer with on-load tap-changerand tertiary not loaded delta windingSingle line diagrams for two possible solutions for such type of power transformerwith all relevant application data are given in figure 51. It shall be noted that thisexample is applicable for protection of autotransformer with not loaded tertiary deltawinding as well.

CT 500/5Star

31.5/31.5/(10.5) MVA110±11×1.5% /36.75/(10.5) kV

YNyn0(d5)

CT 200/1Star


31.5/31.5/(10.5) MVA110±11×1.5% /36.75/(10.5) kV

YNyn0(d5)


en06000558.vsd

Figure 51: Two differential protection solutions for star-star connectedtransformer.

For this particular power transformer the 110 kV side phase-to-earth no-load voltagesare exactly in phase with the 36.75 kV side phase-to-earth no-load voltages. Thus,when external phase angle shift compensation is done by connecting main CTs indelta, both set of CTs must be identically connected (i.e. either both DAC or bothDAB as shown in the right-hand side in figure 51) in order to put 110 kV & 36.75kV currents in phase.


1. Check that HV CTs are connected to 1 A CT inputs in RET 670.

2. Check that LV CTs are connected to 5 A CT inputs in RET 670.

3. When delta connected CTs are used make sure that both CT sets are identicallyconnected (i.e. either both DAC or both DAB).



131

4. For star connected CTs make sure how they are 'star'red (i.e. earthed) towards oraway from the protected transformer.



Setting parameter Selected value for both solution 1(star connected CTs)

Selected value for both Solution 2(delta connected CTs)

CTprim 200200

1153

=

CTsec 1 1

CTStarPoint FromObject ToObject


6. Enter the following settings for all three CT input channels used for the LV sideCTs

Table 38: CT input channels used for the LV side CTs

Setting parameter Selected value for both Solution 1(star connected)

Selected value for both Solution 2(delta connected)

CTprim 500500

2893

=

CTsec 5 5

CTStarPoint ToObject ToObject


7. Enter the following values for the general settings of the differential protectionfunction, see table 39

Table 39: General settings of the differential protection function




RatedVoltageW2 36.75 kV 36.75 kV



ConnectTypeW1 STAR (Y) STAR (Y)




REG 670



ConnectTypeW2 star=y star=y

ClockNumberW2 0 [0 deg] 0 [0 deg]



TconfigForW1 No No

TconfigForW2 No No

LocationOLT1 Winding 1 (W1) Winding 1 (W1)

LowTapPosOLTC1 1 1

RatedTapOLTC1 12 12

HighTapPsOLTC1 23 23

TapHighVoltTC1 23 23

StepSizeOLTC1 1.5% 1.5%

Other parameters Not relevant for this application.Use default value.

Not relevant for this application.Use default value.

1) Zero-sequence current is already removed by connecting main CTs in delta.

Summary and conclusionsRET 670 can be used for differential protection of three-phase power transformerswith main CTs either star or delta connected. However the relay has been designedwith assumption that all main CTS are star connected. RET 670 can be used inapplications where main CTs are delta connected. For such applications the followingshall be kept in mind:

1. Ratio for delta connected CTs shall be set sqrt(3)=1.732 times smaller then actualindividual phase CT ratio.

2. Power transformer vector group shall be typically set as Yy0 because thecompensation for power transformer actual phase shift is provided by externaldelta CT connection.

3. Zero sequence current is eliminated by main CT delta connection. Thus on sideswhere CTs are connected in delta the zero sequence current elimination shall beset to Off in RET 670.

The following table summarizes the most commonly used star-delta vector grouparound the world and provides information about required type of main CT deltaconnection on the star sides of the protected transformer.



133

IEC vector group ANSI designation Positive sequence no-loadvoltage phasor diagram

Required delta CTconnection type on starside of the protectedpower transformer andinternal vector groupsetting in RET 670

YNd1 YDAC

YDAC/Yy0

Dyn1 DABY

Y

DAB/Yy0

YNd11 YDAB

YDAB/Yy0

Dyn11 DACY

Y

DAC/Yy0

YNd5 YD150Y

DAB/Yy6

Dyn5 DY150

Y

DAC/Yy6



REG 670


Table 40: Basic general settings for the T2WPDIF_87T (T2D1-) function

Parameter Range Step Default Unit DescriptionRatedVoltageW1 0.05 - 2000.00 0.05 400.00 kV Rated voltage of

transformer winding 1(HV winding) in kV

RatedVoltageW2 0.05 - 2000.00 0.05 231.00 kV Rated voltage oftransformer winding 2in kV

RatedCurrentW1 1 - 99999 1 577 A Rated current oftransformer winding 1(HV winding) in A

RatedCurrentW2 1 - 99999 1 1000 A Rated current oftransformer winding 2in A

ConnectTypeW1 WYE (Y)Delta (D)

- WYE (Y) - Connection type ofwinding 1: Y-wye orD-delta



ClockNumberW2 0 [0 deg]1 [30 deg lag]2 [60 deg lag]3 [90 deg lag]4 [120 deg lag]5 [150 deg lag]6 [180 deg]7 [150 deg lead]8 [120 deg lead]9 [90 deg lead]10 [60 deg lead]11 [30 deg lead]

- 0 [0 deg] - Phase displacementbetween W2 &W1=HV winding, hournotation

ZSCurrSubtrW1 OffOn

- On - Enable zer. seq.current subtraction forW1 side, On / Off

ZSCurrSubtrW2 OffOn


TconfigForW1 NoYes

- No - Two CT inputs (T-config.) for winding 1,YES / NO

CT1RatingW1 1 - 99999 1 3000 A CT primary rating inA, T-branch 1, ontransf. W1 side

CT2RatingW1 1 - 99999 1 3000 A CT primary in A, T-branch 2, on transf.W1 side

TconfigForW2 NoYes





135

Parameter Range Step Default Unit DescriptionCT1RatingW2 1 - 99999 1 3000 A CT primary rating in

A, T-branch 1, ontransf. W2 side


LocationOLTC1 Not UsedWinding 1 (W1)Winding 2 (W2)

- Not Used - Transformer windingwhere OLTC1 islocated

LowTapPosOLTC1

1 1 0 - 10 - OLTC1 lowest tapposition designation(e.g. 1)

RatedTapOLTC1 6 1 1 - 100 - OLTC1 rated tap/mid-tap positiondesignation (e.g. 6)

HighTapPsOLTC1 11 1 1 - 100 - OLTC1 highest tapposition designation(e.g. 11)

TapHighVoltTC1 1 1 1 - 100 - OLTC1 end-tapposition with windinghighest no-loadvoltage

StepSizeOLTC1 0.01 - 30.00 0.01 1.00 % Voltage change perOLTC1 step inpercent of ratedvoltage

Table 41: Basic parameter group settings for the T2WPDIF_87T (T2D1-) function



SOTFMode OffOn

- On - Operation mode forswitch onto fault

tAlarmDelay 0.000 - 60.000 0.001 10.000 s Time delay for diffcurrents alarm level

IDiffAlarm 0.05 - 1.00 0.01 0.20 %IB Dif. cur. alarm,multiple of base curr,usually W1 curr.

IdMin 0.10 - 0.60 0.01 0.30 IB Section1 sensitivity,multi. of base curr,usually W1 curr.

EndSection1 0.20 - 1.50 0.01 1.25 IB End of section 1,multiple of Winding 1rated current

EndSection2 1.00 - 10.00 0.01 3.00 IB End of section 2,multiple of Winding 1rated current





REG 670

Parameter Range Step Default Unit DescriptionSlopeSection3 30.0 - 100.0 0.1 80.0 % Slope in section 3 of

operate-restraincharacteristic, in %

IdUnre 1.00 - 50.00 0.01 10.00 IB Unrestr. prot. limit,multiple of Winding 1rated current

I2/I1Ratio 5.0 - 100.0 1.0 15.0 % Max. ratio of 2ndharm. to fundamentalharm dif. curr. in %

I5/I1Ratio 5.0 - 100.0 1.0 25.0 % Max. ratio of 5thharm. to fundamentalharm dif. curr. in %

CrossBlockEn OffOn

- On - Operation Off/On forcross-block logicbetween phases

NegSeqDiffEn OffOn

- On - Operation Off/On forneg. seq. differentialprotections

IMinNegSeq 0.02 - 0.20 0.01 0.04 IB Neg. seq. curr. mustbe higher than thislevel to be used

NegSeqROA 30.0 - 120.0 0.1 60.0 Deg Operate Angle forint. / ext. neg. seq.fault discriminator

OpenCTEnable OffOn

- On - Open CT detectionfeature. OpenCTEnable Off/On

tOCTAlarmDelay 0.100 - 10.000 0.001 3.000 s Open CT: time in s toalarm after an openCT is detected

tOCTResetDelay 0.100 - 10.000 0.001 0.250 s Reset delay in s. Afterdelay, diff. function isactivated

tOCTUnrstDelay 0.10 - 6000.00 0.01 10.00 s Unrestrained diff.protection blockedafter this delay, in s

Table 42: Basic general settings for the T3WPDIF_87T (T3D1-) function

Parameter Range Step Default Unit DescriptionRatedVoltageW1 0.05 - 2000.00 0.05 400.00 kV Rated voltage of

transformer winding 1(HV winding) in kV



RatedCurrentW1 1 - 99999 1 577 A Rated current oftransformer winding 1(HV winding) in A




137

Parameter Range Step Default Unit DescriptionRatedCurrentW2 1 - 99999 1 1000 A Rated current of

transformer winding 2in A

RatedCurrentW3 1 - 99999 1 7173 A Rated current oftransformer winding 3in A






- Delta (D) - Connection type ofwinding 3: Y-wye orD-delta


- 0 [0 deg] - Phase displacementbetween W2 &W1=HV winding, hournotation


- 5 [150 deg lag] - Phase displacementbetween W3 &W1=HV winding, hournotation

ZSCurrSubtrW1 OffOn


ZSCurrSubtrW2 OffOn


ZSCurrSubtrW3 OffOn


TconfigForW1 NoYes



CT2RatingW1 1 - 99999 1 3000 A CT primary in A, T-branch 2, on transf.W1 side




REG 670

Parameter Range Step Default Unit DescriptionTconfigForW2 No

Yes- No - Two CT inputs (T-

config.) for winding 2,YES / NO



TconfigForW3 NoYes




LocationOLTC1 Not UsedWinding 1 (W1)Winding 2 (W2)Winding 3 (W3)


LowTapPosOLTC1



HighTapPsOLTC1 11 1 1 - 100 - OLTC1 highest tapposition designation(e.g. 11)



LocationOLTC2 Not UsedWinding 1 (W1)Winding 2 (W2)Winding 3 (W3)


LowTapPosOLTC2






139

Parameter Range Step Default Unit DescriptionHighTapPsOLTC2 11 1 1 - 100 - OLTC2 highest tap

position designation(e.g. 11)



Table 43: Basic parameter group settings for the T3WPDIF_87T (T3D1-) function



SOTFMode OffOn

- On - Operation mode forswitch onto faultfeature

tAlarmDelay 0.000 - 60.000 0.001 10.000 s Time delay for diffcurrents alarm level

IDiffAlarm 0.05 - 1.00 0.01 0.20 %IB Dif. cur. alarm,multiple of base curr,usually W1 curr.

IdMin 0.10 - 0.60 0.01 0.30 IB Section1 sensitivity,multi. of base curr,usually W1 curr.

IdUnre 1.00 - 50.00 0.01 10.00 IB Unrestr. prot. limit,multi. of base curr.usually W1 curr.

CrossBlockEn OffOn

- On - Operation Off/On forcross-block logicbetween phases

NegSeqDiffEn OffOn

- On - Operation Off/On forneg. seq. differentialprotections

IMinNegSeq 0.02 - 0.20 0.01 0.04 IB Neg. seq. curr. limit,mult. of base curr,usually W1 curr.

NegSeqROA 30.0 - 120.0 0.1 60.0 Deg Operate Angle forint. / ext. neg. seq.fault discriminator



REG 670

Table 44: Advanced parameter group settings for the T3WPDIF_87T (T3D1-) function

Parameter Range Step Default Unit DescriptionEndSection1 0.20 - 1.50 0.01 1.25 IB End of section 1,

multi. of base current,usually W1 curr.

EndSection2 1.00 - 10.00 0.01 3.00 IB End of section 2,multi. of base current,usually W1 curr.



I2/I1Ratio 5.0 - 100.0 1.0 15.0 % Max. ratio of 2ndharm. to fundamentalharm dif. curr. in %

I5/I1Ratio 5.0 - 100.0 1.0 25.0 % Max. ratio of 5thharm. to fundamentalharm dif. curr. in %

OpenCTEnable OffOn

- On - Open CT detectionfeature. OpenCTEnable Off/On

tOCTAlarmDelay 0.100 - 10.000 0.001 3.000 s Open CT: time in s toalarm after an openCT is detected

tOCTResetDelay 0.100 - 10.000 0.001 0.250 s Reset delay in s. Afterdelay, diff. function isactivated

tOCTUnrstDelay 0.10 - 6000.00 0.01 10.00 s Unrestrained diff.protection blockedafter this delay, in s

4.5.3 Restricted earth fault protection (PDIF, 87N)

Function block name: REFx- IEC 60617 graphical symbol:

IdN/I

ANSI number: 87N

IEC 61850 logical node name:REFPDIF

4.5.3.1 Application

Break-down of the insulation between a phase conductor and earth in an effectivelyor low impedance earthed power system results in a large fault current. A breakdownof the insulation between a transformer winding and the core or the tank may result



141

in a large fault current which causes severe damage to the windings and thetransformer core. A high gas pressure may develop, damaging the transformer tank.

Fast and sensitive detection of earth faults in a power transformer winding can beobtained in solidly earthed or low impedance earth networks by the restricted earthfault protection. The only requirement is that the power transformer winding isconnected to earth in the neutral (star) point (in case of Wye(Star)-connectedwindings) or via separate earthinging transformer (in case of delta-connectedwindings).

The restricted earth fault function is used as a unit protection function. It protects thepower transformer winding against the faults involving earth. However, it should benoted that the earth faults are the most likely and common type of fault.

Restricted earth fault protection is the fastest and the most sensitive protection a powertransformer winding can have and will detect faults such as:

• earth faults in the transformer winding when the network is earthed through animpedance

• earth faults in the transformer winding in solidly eartheded network when thepoint of the fault is close to the winding neutral(star) point.

• interturn faults

The restricted earth fault protection is not affected, as differential protection, with thefollowing power transformer related phenomena:

• magnetizing inrush currents• overexcitation magnetizing currents• on load tap changer• external and internal phase faults which do not involve earth• symmetrical overload conditions

Because of its properties the restricted earth fault protection is often used as a mainprotection of the transformer winding for all faults involving earth.

Application examples

Transformer winding, solidly earthedThe most common application is on a solidly eartheded transformer winding. Theconnection is shown in figure 52.



REG 670

en05000210.vsd

INd>

REFx

I3P

I3PW1CT1

Figure 52: Connection of restricted earth fault function for a fully insulated,directly (solidly) eartheded transformer

Transformer winding, earthedgrounded through Z-0 earthingZig-Zaggrounding transformerA common application is for low reactance earthed transformer where the earthingis through separate Z-0earthinging transformers. The fault current is then limited totypical 800 to 2000 A for each transformer. The connection of a REF for thisapplication is shown in figure 53.



143

en05000211.vsd

INd>

REFx

INd>

REFx

I3P

I3PW1CT1

I3P

I3PW1CT1

Figure 53: Connection of restricted earth fault function for a fully insulatedtransformer, earthed with a Z-0 earthing transformer

Autotransformer winding, solidly earthedgroundedAutotransformers can be protected with a REF protection. The complete transformerwill then be connected including HV side, neutral connection and the LV side. Theconnection of a REF for this application is shown in figure 54.



REG 670

en05000212.vsd

INd>

REFx

I3P

I3PW1CT1

I3PW2CT1

Figure 54: Connection of restricted earth fault function for an autotransformer,solidly earthed

Reactor winding, solidly earthedgroundedReactors can be protected with a REF protection. The connection of a REF for thisapplication is shown in figure 55.



145

en05000213.vsd

INd>

REFx

I3P

I3PW1CT1

Figure 55: Connection of restricted earth fault function for a reactor, solidlyearthed

Multi-breaker applicationsMulti-breaker arrangements including ring-, one and a half breakerbreaker-and-a-half, double breaker and mesh corner arrangements will have multiple currenttransformers on the phase side. The REF function block has inputs to allow twocurrent inputs from each side of the transformer the second winding set is thenbasically only applicable for Autotransformers.

A typical connection for an autotransformer, which is the maximum case, is shownin figure 56.



REG 670

INd>

REFx

I3P

I3PW1CT1I3PW1CT2

en05000214.vsd

Figure 56: Connection of restricted earth fault function in multi-breakerarrangements

CT earthinggrounding directionTo make Restricted Earth Fault protection to work, the main CT's are always supposedto be Wye(star) connected. The main CT's neutral(star) formation can be done in anyway (i.e. either "ToObject" or "FromObject"). However internally the restrictedearth fault function will always use reference directions towards the protectedtransformer. Thus the IED will always measure the primary currents on all sides andin the neutral of the power transformer with the same reference direction towards thepower transformer windings.

The earthing can therefore be freely selected for each of the involved currenttransformers.


Setting and configurationThe signals are configured by use of the CAP configuration tool and the SignalMatrixtool forming part of the PCM 600 tool.

The setting parameters for the overexcitation function are set at the local HMI (HumanMachine Interface) or by use of the PST (Parameter Setting Tool) forming part ofPCM 600 tool installed on a PC connected to the control or protection unit.



147

Recommendation for analog inputs

• I3P (should be NI or SI)• Connect the neutral current here

I3PW1CT1: Phase currents for winding 1 first current transformer set.

I3PW1CT2: Phase currents for winding1 second current transformer set for multi-breaker arrangements. When not required configure input to "REAL ZERO"

I3PW2CT1: Phase currents for winding 2 first current transformer set. Used atAutotransformers. When not required configure input to "REAL ZERO"

I3PW2CT2: Phase currents for winding 2 second current transformer set for multi-breaker arrangements. Used in Autotransformers. When not required configure inputto "REAL ZERO"

Recommendation for input signalsRefer to the default factory configuration for examples of configuration.

BLOCK: The input will block the operation of the function. Can be used e.g. to fora limited time block the operation during special service conditions.

Recommendation for output signalsRefer to the default factory configuration for examples of configuration.

START: The start output indicates that the level IdMin has been reached. It can beused to initiate time measurement.

TRIP: The trip output is activated after the operate time for the IdMin level has beenreached. The output signal is used to trip the circuit breaker.

DIROK: The output is activated when the directional criteria has been fulfilled.Output can be used for information purpose normally during testing. It can e.g. bechecked from the debug tool or wired as an event to an event log.

BLK2H: The output is activated when the function is blocked due to too high levelof second harmonic. Output can be used for information purpose normally duringtesting. It can e.g. be checked from the debug tool or wired as an event to an eventlog.

Setting parametersOperation: The operation of the restricted earth fault function can be switched On-Off.

IBase: The Ibase setting is the setting of the base (per unit) current on which allpercentage settings are based. Normally the protected power transformer windingrated current is used but alternatively the current transformer rated current can be set.

IdMin: The setting gives the minimum operation value. The setting is in percent ofthe Ibase value. The neutral current must always be bigger than or equal to half of



REG 670

this value. A normal setting is 10% of power transformer rated current for the windingit has been connected to.

CTFactorPri1: A factor to allow a sensitive function also at multi-breakerarrangement where the rating in the bay is much higher than the rated current of thetransformer winding. The stabilizing can then be high so an unnecessary high faultlevel can be required. The setting is normally 1.0 and but in multi-breaker arrangementthe setting shall be ICRated/Ibase (Ibase is normally transformer rated current).



CTFactorPri4: A factor to allow a sensitive function also at multi-breakerarrangement where the rating in the bay is much higher than the rated current of thetransformer winding. The stabilizing can then be high so an unnecessary high faultlevel can be required. The setting is normally 1.0 and but in multi-breaker arrangementthe setting shall be ICRated/Ibase (Ibase is normally transformer rated current)


Table 45: Basic parameter group settings for the REFPDIF_87N (REF1-) function


ON- Off - Operation Off / On

IBase 1 - 99999 1 3000 A Base current

IdMin 4.0 - 100.0 0.1 10.0 %IB Maximum sensitivityin % of Ibase

CTFactorPri1 1.0 - 10.0 0.1 1.0 - CT factor for HV sideCT1 (CT1rated/HVrated current)

CTFactorPri2 1.0 - 10.0 0.1 1.0 - CT factor for HV sideCT2 (CT2rated/HVrated current)

CTFactorSec1 1.0 - 10.0 0.1 1.0 - CT factor for MV sideCT1 (CT1rated/MVrated current)

CTFactorSec2 1.0 - 10.0 0.1 1.0 - CT factor for MV sideCT2 (CT2rated/MVrated current)



149

Table 46: Advanced parameter group settings for the REFPDIF_87N (REF1-) function

Parameter Range Step Default Unit DescriptionROA 60 - 90 1 60 Deg Relay operate angle

for zero sequencedirectional feature

4.5.4 High impedance differential protection (PDIF, 87)

Function block name: HZDx- IEC 60617 graphical symbol:

IdN

ANSI number: 87

IEC 61850 logical node name:HZPDIF

4.5.4.1 Application

The high impedance differential protection can be used as:

• Autotransformer differential protection• Restricted earth fault protection• T-feeder protection• Tertiary (or secondary busbar) protection• Tertiary connected reactor protection• Generator differential protection at block connected generators.

The application will be dependent on the primary system arrangements and locationof breakers, available independent cores on CTs etc.



REG 670

en05000163.vsd

3Id

3Id

3Id/I>

IdN

3Id

3Id

3Id/I>

G

3Id

3Id

3Z<

3Id

3Z<

xx05000738.vsd



151

Figure 57: Different applications of a high impedance differential protectionfunction

The basics of the high impedance principleThe high impedance principle has been used through many years for differentialprotection due to the capability to manage through faults also with heavy CTsaturation. The principle is based on the CT secondary current circulating betweeninvolved current transformers and not through the relay due to its high impedance,normally in the range of hundreds of ohms and sometimes above a kOhm.. When afault occurs the current cannot circulate and is forced through the differential circuitcausing operation.

IdN

en05000164.vsd

Figure 58: The high impedance principle for one phase with three currenttransformer inputs

For a through fault one current transformer might saturate when the other CTs stillwill feed current. For such a case a voltage will be developed across the relay. Thecalculations are made with the worst situations in mind and a minimum operatingvoltage UR is calculated according to equation 29

( )maxUR IF Rct Rl> × +(Equation 29)

where:

IFmax is the maximum through fault current at the secondary side,

Rct is the current transformer secondary resistance and

RI is the maximum loop resistance of the circuit at any CT.



REG 670

The maximum operating voltage has to be calculated (all loops) and the relay is sethigher than the highest achieved value (setting U>Trip). As the loop resistance is thevalue to the connection point from each CT it is advisable to do all the CT coresummations in the switchgear to have shortest possible loops. This will give lowersetting values and also a better balanced scheme. The connection in to the controlroom can then be from the most central bay.

For an internal fault circulation is not possible and due to the high impedance thecurrent transformers will immediately saturate and a rms voltage depending on thesize of current transformer saturation voltage will be developed across the relay. Dueto the fast saturation very high peak voltages can be achieved. To prevent the risk offlashover in the circuit, a voltage limiter must be included. The voltage limiter is avoltage dependent resistor (Metrosil).

Based on the above calculated operating voltage the relay stabilizing resistor must beselected. The external unit with stabilizing resistor has a value of either 6800Ohmsor 2200Ohms (depending on ordered alternative) with a shorting link to allowadjustment to the required value. Select a suitable value of the resistor based on theUR voltage calculated. A higher resistance value will give a higher sensitivity and alower value a lower sensitivity.

The function has an operating current range 20 mA to 1.0A for 1 A inputs and 100mA to 5A for 5A inputs. This, together with the selected and set value, is used tocalculate the required value of current at the set U>Trip and SeriesResitor values.

The CT inputs used for high impedance differential protection, shallbe set to have ratio 1:1

The table below shows the operating voltages for different resistances and the relatedoperating current. Adjust as required based on this table or to values in between asrequired for the application.

Minimum ohms can be difficult to adjust due to the small valuecompared to the total value.

Normally the voltage can be increased to higher values than the calculated minimumU>Trip with a minor change of total operating values as long as this is done byadjusting the resistor to a higher value. Check the sensitivity calculation below forreference.

Table 47: Operating voltages for 1A

Operatingvoltage

Stabilizingresistor R

Operatingcurrent level 1A





20 V 1000 0.020 A -- -- -- --

40 V 2000 0.020 A 1000 0.040 A -- --

60 V 3000 0.020 A 1500 0.040 A 600 0.100 A




153

Operatingvoltage







80 V 4000 0.020 A 2000 0.040 A 800 0.100 A

100 V 5000 0.020 A 2500 0.040 A 1000 0.100 A

150 V 6000 0.020 A 3750 0.040 A 1500 0.100 A

200 V 6800 0.029 A 5000 0.040 A 2000 0.100 A

Table 48: 5 A input with minimum operating down to 100 mA

Operatingvoltage

Stabilizingresistor R1






20 V 200 0.100 A 100 0.200 A -- --

40 V 400 0.100 A 200 0.200 A 100 0.400

60 V 600 0.100 A 300 0.200 A 150 0.400 A

80 V 800 0.100 A 400 0.200 A 800 0.100 A

100 V 1000 0.100 A 500 0.200 A 1000 0.100 A

150 V 1500 0.100 A 750 0.200 A 1500 0.100 A

200 V 2000 0.100 A 1000 0.200 A 2000 0.100 A

The current transformer saturating voltage must be at least 2*U>Trip to havesufficient operating margin. This must be checked after calculation of U>Trip.

When you have selected the R value and set the U>Tripvalue the sensitivity of thescheme IP can be calculated. The relay sensitivity is decided by the total current inthe circuit according to equation 30.

( )IP n IR Ires lmag= × + + å (Equation 30)

where:

n is the CT ratio

IP is the current through the relay,

Ires is the current through the voltage limiter and

ΣImag is the sum of the magnetizing currents from all CTs in the circuit (e.g. 4 for Restricted earthfault protection, 2 for reactor differential protection, 3-4 for Autotransformer differentialprotection etc.).

It should be remembered that the vectorial sum of the currents must be used (relays,Metrosil and resistor currents are resistive). The current measurement shall beinsensitive to DC component in fault current to allow a use of only the AC componentsof the fault current in the above calculations.

The voltage dependent resistor (Metrosil) characteristic is shown in figure 65



REG 670

Series resistor thermal capacityThe series resistor is dimensioned for 200 W. Preferable theU>Trip2/SeriesResistorshould always be lower than 200 W to allow continuos activation onduring testing. If this value is exceeded, testing should be done with transient faults.



155

I>

R

Rres

Rl

Rct Rct

Rl

UR

a) Through load situation

b) Through fault situation

UR

UR

c) Internal faults

UR

Protected Object

en05000427.vsd



REG 670

Figure 59: The high impedance principle for one phase with two currenttransformer inputs

4.5.4.2 Connection examples

WARNING! USE EXTREME CAUTION! Dangerously highvoltages might be present on this equipment, especially on the platewith resistors. Do any maintenance ONLY if the primary objectprotected with this equipment is de-energized. If required by nationallow/standard enclose the plate with resistors with a protective coveror in a separate box!

Connections for three-phase high impedance differential protectionGenerator, reactor or busbar differential protection is a typical application for three-phase high impedance differential protection. Typical CT connections for three-phasehigh impedance differential protection scheme with 670 series are shown in figureCT connections for High Impedance Differential Protection

L1(A)

L2(B)

L3(C)

Protected Object

CT 1200/1Star/Wye

Connected

L1(A)

L2(B)

L3(C)

CT 1200/1Star/Wye

Connected

7

8

9

10

11

12

1

2

3

4

5

6

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

78

6

9

IED 670

X1

R4

R5

R6

12

12

12

11 12 13 14

U U U R1

13

4

2

13

R2

2

4

13

R3

2

4

1 2 3 4 5 6 7

L1 (A)

L2 (B)

L3 (C)N

3-Ph Plate with Metrosils and Resistors

2

3

5

4

10

X X

L1 (A)

L2 (B)

L3 (C)N

1

Figure 60: CT connections for High Impedance Differential Protection

• Number 1 shows the scheme earthing point. Note that it is of outmost importanceto insure that only one earthing point exist in such scheme.

• Number 2 shows the three-phase plate with setting resistors and metrosils.• Number 3 shows the necessary connection for three-phase metrosil set. Shown

connections are applicable for both types of three-phase plate.



157

• Number 4 shows the position of optional test switch for secondary injection intothe high impedance differential relay.

• Number 5 shows the necessary connection for setting resistors. Shownconnections are applicable for both types of three-phase plate.

• Number 6 shows that the factory made star point on a three-phase setting resistorset shall be removed for installations with 670 series. This star point is requiredfor RADHA schemes only!

• Number 7 shows how to connect three individual phase currents for highimpedance scheme to three CT inputs in IED 670.

• Number 8 shows a TRM module where these current inputs are located. Notethat the CT ratio for high impedance differential protection application must beset as one! Thus for main CTs with 1A secondary rating the following settingvalues shall be entered: CTprim=1A and CTsec=1A; while for main CTs with5A secondary rating the following setting values shall be entered: CTprim=5Aand CTsec=5A. The parameter CTStarPoint shall be always left to the defaultvalue ToObject.

• Number 9 shows three connections made in Signal Matrix Tool (i.e. SMT) whichconnect these three current inputs to first three input channels of thepreprocessing function block (10). For high impedance differential protectionpreprocessing function block in 3ms task shall be used.

• Number 10 shows the preprocessing block which has a task to digitally filter theconnected analogue inputs. Preprocessing block outputs AI1, AI2 and AI3 shallbe connected to three instances of high impedance differential protectionfunction blocks (e.g. HZD1, HZD2 and HZD3 function blocks in theconfiguration tool).

Connections for three-phase high impedance differential protectionRestricted earth fault (REF) protection is a typical application for one-phase highimpedance differential protection. Typical CT connections for high impedance basedREF protection scheme with 670 series are shown in figure CT connections forRestricted Earth Fault Protection



REG 670

L1(A)

L2(B)

L3(C)

Protected Object

CT 1500/5Star/Wye

Connected

7

8

9

10

11

12

1

2

3

4

5

6

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

6

7

8

IED 670

X1

R1

12

4 5

U R2

13

4

2

1 2 3

N

1-Ph Plate with Metrosil and Resistor

23

5

4

9

N

L1(A)

L2(B)

L3(C)

CT

1500

/51

en07000194.vsd

Figure 61: CT connections for Restricted Earth Fault Protection

• Number 1 shows the scheme earthing point. Note that it is of outmost importanceto insure that only one earthing point exist in such scheme.

• Number 2 shows the one-phase plate with setting resistor and metrosil.• Number 3 shows the necessary connection for the metrosil. Shown connections

are applicable for both types of one-phase plate. • Number 4 shows the positionof optional test switch for secondary injection into the high impedancedifferential relay.

• Number 4 shows the position of optional test switch for secondary injection intothe high impedance differential relay.

• Number 5 shows the necessary connection for setting resistor. Shownconnections are applicable for both types of one-phase plate.

• Number 6 shows how to connect the REF high impedance scheme to one CTinput in IED 670.

• Number 7 shows a TRM module where this current input is located. Note thatthe CT ratio for high impedance differential protection application must be setas one! Thus for main CTs with 1A secondary rating the following setting valuesshall be entered: CTprim=1A and CTsec=1A; while for main CTs with 5Asecondary rating the following setting values shall be entered: CTprim=5A andCTsec=5A. The parameter CTStarPoint shall be always left to the default valueToObject.

• Number 8 shows a connection made in Signal Matrix Tool (i.e. SMT) whichconnects this current input to first input channel of the preprocessing functionblock (10). For high impedance differential protection preprocessing functionblock in 3ms task shall be used.

• Number 9 shows the preprocessing block which has a task to digitally filter theconnected analogue inputs. Preprocessing block output AI1 shall be connected



159

to one instances of high impedance differential protection function block (e.g.HZD1 function block in the configuration tool).


The setting calculations are individual for each application. Refer to the differentapplication descriptions below.

ConfigurationThe configuration is done in CAP531 graphical configuration tool. Signals from e.g.check criterias are connected to the inputs as required for the application.

BLOCK input is used to block the function e.g. from an external check criteria.

BLKTR input is used to block the function tripping e.g. from an external checkcriteria. The alarm level will be operative.

Settings of protection functionOperation: The operation of the high impedance differential function can be switchedOn-Off.

U>AlarmAlarmPickup: Set the alarm level. The sensitivity can roughly be calculatedas a divider from the calculated sensitivity of the differential level. A typical settingis 10% of U>Trip

tAlarm: Set the time for the alarm. Mostly this output is also used to short-circuit thedifferential circuit at the alarm. A typical setting is 2-3 seconds.

U>Trip: Set the trip level according to the calculations in the examples for eachapplication example. The level is selected with margin to the calculated requiredvoltage to achieve stability. Values can be 20-200 V dependent on the application.

Series resistor: Set the value of the stabilizing series resistor. Calculate the valueaccording to the examples for each application. Adjust the resistor as close as possibleto the calculated example. Measure the value achieved and set this value here. Note!The value shall always be a high impedance. This means e.g. for 1A circuits say biggerthan 400 ohms (400 VA) and for 5 A circuits say bigger than 100 ohms (2500 VA).This ensures that the current will circulate and not go through the differential circuitat through faults.

T-feeder protectionIn many busbar arrangements such as one-and a half breaker, ring breaker, meshcorner etc there will be a T-feeder from the current transformer at the breakers up tothe current transformers in the transformer bushings. It is often required to separatethe zones so the zone up to the bushing is covered from one differential function andthe transformer from another. The high impedance differential function in REx670allows this to be done efficiently, see figure 62.



REG 670

3Id

en05000165.vsd

3Id

xx05000739.vsd

Figure 62: The protection scheme utilizing the high impedance function for theT-feeder and the transformer differential protection for thetransformer



161

Normally this scheme is set to achieve a sensitivity of around 20 percent of the ratedcurrent so that a low value can be used on the resistor.

Caution: It is strongly recommended to use the highest tap of the CTwhenever high impedance protection is used. This helps in utilizingmaximum CT capability, minimize the current, thereby reducing thestability voltage limit. Another factor is that during internal faults, thevoltage developed across the selected tap is limited by the non-linearresistor but in the unused taps, owing to auto-transformer action,voltages much higher than design limits might be induced.

Setting exampleBasic data: Current transformer ratio: 2000/1 A

CT Class: 20 VA 5P20

Secondary resistance: 6.2 ohms

Cable loop resistance: <100 m 2.5mm2(one way) gives 2*0,8 ohm at 75° C<200 ft AWG10(one way between the junction point and the farthest CT) to belimited to appx 0.2 Ohms at 75deg C gives loop resistance 2*0.2 =0.4 Ohms.

Max fault current: Equal to switchgear rated fault current 40 kA

Calculation:

( )40006.2 1.6 156

2000UR V> × + =

Select a setting of U>Trip=200 V.

The current transformer knee point voltage can roughly be calculated from the rated values, consideringknee point voltage to be about 70% of the accuracy limit voltage.

( )5 20 6.2 20 524E P V> + × =

i.e. bigger than 2*U>Trip

Check from the table of selected resistances the required series stabilizing resistorvalue to use. As this application does not need to be so sensitive selectSeriesResistor= 2000 ohm which gives a relay current of 100 mA.

Calculate the sensitivity at operating voltage, ignoring the current drawn by the non-linear resistor.



REG 670

( ) 32000100 0 20 0 3 10 60 10 .220

1IP approx A-= ° + ° + × - ° × £

(Equation 33)

where

200mA is the current drawn by the relay circuit and

50mA is the current drawn by each CT just at pickup

The magnetizing current is taken from the magnetizing curve for the currenttransformer cores which should be available. The value at U>Trip is taken. For thevoltage dependent resistor current the top value of voltage 200*√2 is used and thetop current used. Then the rms current is calculated by dividing with√2. Use themaximum value from the curve.

It can clearly be seen that the sensitivity is not so much influenced by the selectedvoltage level so a sufficient margin should be used. The selection of the stabilizingresistor and the level of the magnetizing current (mostly dependent of the number ofturns) are the most important factors.

Tertiary reactor protectionFor many transformers there can be a secondary system for local distribution and/orshunt compensation. The high impedance differential function can be used to protectthe tertiary reactor for phase as well as earth faults if the earthing is direct or lowimpedance.



163

3Id

en05000176.vsd

Figure 63: Application of the high impedance differential function on an autotransformer.

Setting example

It is strongly recommended to use the highest tap of the CT wheneverhigh impedance protection is used. This helps in utilizing maximumCT capability, minimize the current, thereby reducing the stabilityvoltage limit. Another factor is that during internal faults, the voltagedeveloped across the selected tap is limited by the non-linear resistorbut in the unused taps, owing to auto-transformer action, voltagesmuch higher than design limits might be induced.



REG 670

Basic data: Current transformer ratio: 100/5 A (Note: Must be the same at all locations)


Secondary resistance: 0.26 ohms

Cable loop resistance: <50 m 2.5mm2 (one way) gives 1*0.4 ohm at 75° CNote! Only one way as the system earthing is limiting the earth fault current.If high earth fault currents exists use two way cable.

Max fault current: The maximum through fault current is limited by the reactor reactance andthe inrush will be the worst for a reactor e.g. 800 A.

Calculation:

( )8000.26 0.4 5.28

1000UR V> × + =


The current transformer saturation voltage at 5% error can roughly be calculated from the rated values.

105 0.26 20 5 66

25E P V> + × × =æ ö

ç ÷è ø

i.e. bigger than 2* U>Trip.

Check from the table of selected resistances the required series stabilizing resistorvalue to use. As this application it is required to be so sensitive so selectSeriesResistor= 200 ohm which gives a relay current of 100 mA.

To calculate the sensitivity at operating voltage, refer to equation 36 which gives anacceptable value. A little lower sensitivity could be selected by using a lowerresistance value.

( )100100 0 5 0 2 100 60 .5

5IP approx A= × ° + ° + × - ° £

(Equation 36)

The magnetizing current is taken from the magnetizing curve for the currenttransformer cores which should be available. The value at U>Trip is taken. For thevoltage dependent resistor current the top value of voltage 20*√2 is used and the topcurrent used. Then the rms current is calculated by dividing with √2. Use themaximum value from the curve.

Restricted earth fault protectionFor solidly earthed systems a Restricted earth fault protection (REF) is often providedas a complement to the normal transformer differential relay. The advantage with the



165

restrictedearth fault relays is their high sensitivity. Sensitivities of 2-8% can beachieved whereas the normal differential relay will have sensitivities of 20-40%. Thelevel for high impedance restricted earth fault function is dependent of the currenttransformers magnetizing currents.

Restricted earth fault relays are also very quick due to the simple measuring principleand the measurement of one winding only.

The connection of a restricted earth fault relay is shown in figure 64. It is connectedacross each directly or low ohmic earthed transformer winding in the figure.

It is quite common to connect the Restricted earth fault relay in the same currentcircuit as the transformer differential relay. This will due to the differences inmeasuring principle limit the differential relays possibility to detect earth faults. Suchfaults are then only detected by the REF function. The mixed connection using thehigh impedance differential function should be avoided and the low impedancescheme should be used instead.

IdN

en05000177.vsd

Figure 64: Application of the high impedance differential function as a restrictedearth fault relay for an YNd transformer.

Setting example

It is strongly recommended to use the highest tap of the CT wheneverhigh impedance protection is used. This helps in utilizing maximumCT capability, minimize the current, thereby reducing the stabilityvoltage limit. Another factor is that during internal faults, the voltagedeveloped across the selected tap is limited by the non-linear resistorbut in the unused taps, owing to auto-transformer action, voltagesmuch higher than design limits might be induced.



REG 670

Basic data: Transformer rated current on HV winding: 250 A

Current transformer ratio: 300/1 A (Note: Must be the same at all locations)


Cable loop resistance: <50 m 2.5mm2 (one way) gives 2*0.4 ohm at 75° C

Max fault current: The maximum through fault current is limited by thetransformer reactance, use 15*rated current of thetransformer

Calculation:

( )25015 0.66 0.8 18.25

300UR V> × × + =


The current transformer saturation voltage at 5% error can roughly be calculated from the rated values.

( )5 10 0.66 20 213.2E P V> + × =

i.e. bigger than 2* U>Trip

Check from the table of selected resistances the required series stabilizing resistorvalue to use. As this application it is required to be so sensitive so selectSeriesResistor= 1000 ohm which gives a relay current of 20 mA.

To calculate the sensitivity at operating voltage, refer to equation 39 which isacceptable as it gives around 10% minimum operating current.

( )30020 0 5 0 4 20 60 .25.5

1IP approx A= × ° + ° + × - ° £

(Equation 39)

The magnetizing current is taken from the magnetizing curve for the currenttransformer cores which should be available. The value at U>Trip is taken. For thevoltage dependent resistor current the top value of voltage 20*√2 is used and the topcurrent used. Then the rms current is calculated by dividing with √2. Use themaximum value from the curve.

Alarm level operationThe high impedance differential protection function has a separate alarm level whichcan be used to give alarm for problems with an involved current transformer circuit.The setting level is normally selected to be around 10% of the operating voltageU>Trip.



167

As seen in the setting examples above the sensitivity of the function is normally highwhich means that the function will in many cases operate also for short circuits oropen current transformer secondary circuits. However the stabilizing resistor can beselected to achieve a sensitivity higher than normal load current and/or a separatecriteria can be added to the operation, a check zone. This can be another IED withthe same high impedance differential function, it could be a check that the fault isthere with a earth overcurrent function or neutral point voltage function etc.

For such cases where operation is not expected during normal service the alarm outputshould be used to activate an external shorting of the differential circuit avoidingcontinuous high voltage in the circuit. A time delay of a few seconds is used beforethe shorting and alarm is activated.

Figure 65: Current voltage characteristics for the non-linear resistors, in the range 10-200 V, the averagerange of current is: 0.01–10 mA.


Table 49: Basic parameter group settings for the HZPDIF_87 (HZD1-) function



U>Alarm 2 - 500 1 10 V Alarm voltage level involts on CTsecondary side

tAlarm 0.000 - 60.000 0.001 5.000 s Time delay to activatealarm

U>Trip 5 - 900 1 100 V Operate voltage levelin volts on CTsecondary side

SeriesResistor 10 - 20000 1 250 ohm Value of seriesresistor in Ohms



REG 670

4.6 Impedance protection

4.6.1 Full-scheme distance measuring, Mho characteristic, PDIS21

Function block name: ZMHx-- IEC 60617 graphical symbol:

ANSI number: 21

IEC 61850 logical node name:ZMHPDIS

4.6.1.1 Application

IntroductionTo maintain proper operation in electric power systems, the main transmission systemmust hold together at various areas. Practical all produced electric energy istransmitted over transmission and sub transmission lines and this is a reason why theoperational reliability of the transmission network is of vital importance to theindividual consumer.

The transmission lines are the most widely spread part of the power system andoverhead lines are the least protected parts from environmental influences. Thenumber of line faults is consequently very high compared to the number of faults onthe other elements in the power system.

Additionally to this is the fact that faults on transmission lines are faults most likelyto cause damages also to the equipment and structures not belonging to the powersystem. Therefore the clearing of line fault is subjected to stringent authorityregulations.

Sub transmission networks are being extended and often become more and morecomplex, consisting of a high number of multi-circuit and/or multi terminal lines ofvery different lengths. These changes in the network will normally impose morestringent demands on the fault clearing equipment in order to maintain an unchangedor increased security level of the power system.

The distance protection function in IED 670 is designed to meet basic requirementsfor application on transmission and sub transmission lines (solid earthed systems)although it also can be used on distribution levels.

System earthinggroundingThe type of system earthing plays an important roll when designing the protectionsystem. In the following some hints with respect to distance protection arehighlighted.



169

Solid earthedgrounded networksIn solid earthed systems the transformer neutrals are connected solidly to earthwithout any impedance between the transformer neutral and earth.

xx05000215.vsd

Figure 66: Solidly earthed network.

The earth fault current is as high or even higher than the short-circuit current. Theseries impedances determine the magnitude of the earth fault current. The shuntadmittance has very limited influence on the earth fault current. The shunt admittancemay, however, have some marginal influence on the earth fault current in networkswith long transmission lines.

The earth fault current at single line to earth in phase L1 can be calculated asequation 40:

1 10

1 2 0 1

333

L L

f N f

U UIZ Z Z Z Z Z Z

×= =

+ + + + + (Equation 40)

Where:

UL1 is the phase to earth voltage (kV) in the faulty phase before fault

Z1 is the positive sequence impedance (Ω/phase)

Z2 is the negative sequence impedance (Ω/phase)

Z0 is the zero sequence impedance (Ω/phase)

Zf is the fault impedance (Ω), often resistive

ZN is the earth return impedance defined as (Z0-Z1)/3

The voltage on the healthy phases is generally lower than 140% of the nominal phase-to-earth voltage. This corresponds to about 80% of the nominal phase-to-phasevoltage.

The high zero sequence current in solid earthed networks makes it possible to useimpedance measuring technique to detect earth fault. However, distance protectionhas limited possibilities to detect high resistance faults and should therefore alwaysbe complemented with other protection function(s) that can carry out the faultclearance in those cases.



REG 670

Effectively earthedgrounded networksA network is defined as effectively earthed if the earth fault factor "fe" is less than1.4. The earth fault factor is defined according to equation 41.

maxe

pn

Vf

V=

(Equation 41)

Where:

Vmax is the highest fundamental frequency voltage on one of the healthy phases at single line toearth fault.

Vpn is the phase to earth fault fundamental frequency voltage before fault.

Another definition for effectively earthed network is when the following relationshipsbetween the symmetrical components of the network impedances are valid, seeequation 42 and equation 43.

0 13X X< × (Equation 42)

0 1R R£(Equation 43)

The magnitude of the earth fault current in effectively earthed networks is high enoughfor impedance measuring element to detect earth fault. However, in the same way asfor solid earthed networks, distance protection has limited possibilities to detect highresistance faults and should therefore always be complemented with other protectionfunction(s) that can carry out the fault clearance in this case.

High impedance earthedgrounded networksIn high impedance networks the neutral of the system transformers are connected tothe earth through high impedance, mostly a reactance in parallel with a high resistor.

This type of network is many times operated in radial, but can also be found operatingmeshed.

What is typical for this type of network is that the magnitude of the earth fault currentis very low compared to the short circuit current. The voltage on the healthy phaseswill get a magnitude of √3 times the phase voltage during the fault. The zero sequencevoltage (3U0) will have the same magnitude in different places in the network due tolow voltage drop distribution.

The magnitude of the total fault current can be calculated according to the formulabelow:

2 203 ( )R L CI I I I= + -

(Equation 44)



171

Where:

3I0 is the earth fault current (A)

IR is the current through the neutral point resistor (A)

IL is the current through the neutral point reactor (A)

IC is the total capacitive earth fault current (A)

The neutral point reactor is normally designed so that it can be tuned to a positionwhere the reactive current balances the capacitive current from the network that is:

13

LC

ww

=× × (Equation 45)

IcIcIc

ILIR

en05000216.vsd

Figure 67: High impedance earthing network.

The operation of high impedance earthed networks is different compare to solidearthed networks where all major faults have to be cleared very fast. In highimpedance earthed networks, some system operators do not clear single line toearth faults immediately; they clear the line later when it is more convenient. In caseof cross country faults, many network operators want to selectively clear one of thetwo earth faults. To handle this type phenomena a separate function called “phasepreference logic” is needed, which is not common to be used in transmissionapplications.

In this type of network, it is mostly not possible to use distance protection for detectionand clearance of earth faults. The low magnitude of the earth fault current might notgive start of the zero sequence measurement element or the sensitivity will be too lowfor acceptance. For this reason a separate high sensitive earth fault protection isnecessary to carry out the fault clearance for single line to earth fault.

Fault infeed from remote endAll transmission and most all sub transmission networks are operated meshed.Typical for this type of network is that we will have fault infeed from remote endwhen fault occurs on the protected line. The fault infeed will enlarge the faultimpedance seen by the distance protection. This effect is very important to keep inmind when both planning the protection system and making the settings.



REG 670

With reference to figure 68, we can draw the equation for the bus voltage Va at leftside as:

( )A A L A B fV I p Z I I R= × × + + ×(Equation 46)

If we divide Va by IA we get Z present to the relay at A side

a A BA L A

A A

V I IZ p Z ZI I

+= = × + ×

(Equation 47)

The infeed factor (IA+IB)/IA can be very high, 10-20 depending on the differencesin source impedances at local and remote end.

Z <

ZL

Z <

EsAVA VAA B EsB

IA IB

Rf

p*ZL (1-p)*ZLZSA ZSB

en05000217.vsd

Figure 68: Influence of fault infeed from remote end.

The effect of fault current infeed from remote end is one of the most driving factorsfor justify complementary protection to distance protection.

Load encroachmentIn some cases the load impedance might enter the zone characteristic without anyfault on the protected line. The phenomenon is called load encroachment and it mightoccur when an external fault is cleared and high emergency load is transferred on theprotected line. The effect of load encroachment for the Mho circle is illustrated to theleft in figure 69. The entrance of the load impedance inside the characteristic is ofcause not allowed and the way to handle this with conventional distance protectionis to consider this with the settings i.e. to have a security margin between the distancezone and the minimum load impedance. This has the drawback that it will reduce thesensitivity of the protection i.e. the ability to detect resistive faults.



173

jX

RLoad

Load

Load

Load

jX

RLoad

Load

Load

Load

Nooperation

en06000403.vsd

Figure 69: Load encroachment phenomena and shaped load encroachmentcharacteristic

The mho function in REL 670 has a built in function which shapes the characteristicaccording to the right in figure 69. The load encroachment algorithm will increasethe possibility to detect high fault resistances, especially for line to earth faults atremote end. For example for a given setting of the load angle ArgLd(see figure 70)for the load encroachment function, the zone reach can be expanded according to theright in figure 70 given higher fault resistance coverage without risk for unwantedoperation due to load encroachment. The part of the load encroachment sector thatcomes inside the mho circle will not cause a trip if the load encroachment functionis activated for the zone measurement. This is valid in both directions.



REG 670

R

X

RLd

RLdArgLd

ArgLdArgLd

ArgLd

en06000404.vsd

Figure 70: Load encroachment characteristic

The use of the load encroachment feature is essential for long heavy loaded lines,where there might be a conflict between the necessary emergency load transfer andnecessary sensitivity of the distance protection. The function can also preferably beused on heavy loaded medium long lines. For short lines the major concern is to getsufficient fault resistance coverage and load encroachment is not a major problem.So, for short lines, the load encroachment function could preferably be switched off.

The main settings of the parameters for load encroachment are done in the mho phaseselector function PHSM. The operation of load encroachment function is alwaysactivated. To deactivate the function , the setting of RLdFw and RLdRv must be setto a value much higher than the maximal load impedance.

Short line applicationThe definition of short, medium and long lines is found in IEEE Std C37.113-1999. ).The length classification is defined by the ratio of the source impedance at theprotected line’s terminal to the protected line’s impedance (SIR). SIR’s of about 4 orgreater generally define a short line. Medium lines are those with SIR’s greater than0.5 and less than 4.

In short line applications, the major concern is to get sufficient fault resistancecoverage. Load encroachment is not so common. The line length that can berecognized as a short line is not a fixed length; it depends on system parameters suchas voltage and source impedance, see table 50.



175

Table 50: Definition of short and very short line

Line category

Un Un

110 kV 500 kV

Very short lineShort line

1.1-5.5 km 5-25 km

5.5-11 km 25-50 km

The use of load encroachment algorithm in REL 670 mho function improves thepossibility to detect high resistive faults without conflict with the load impedance(see previous right figure 4).

For very short line applications the underreaching zone 1 can not be used due to thatthe voltage drop distribution through out the line will be too low causing risk foroverreaching.

Load encroachment is normally no problems for short line applications so the loadencroachment function could be switched off (LoadEncMode = Off). This willincrease the possibility to detect resistive close-in faults.

Long transmission line applicationFor long transmission lines the margin to the load impedance i.e. to avoid loadencroachment, will normally be a major concern. It is well known that it is difficultto achieve high sensitivity for line to earth fault at remote end of a long lines whenthe line is heavy loaded.

What can be recognized as long lines with respect to the performance of distanceprotection is noted in table 51.

Table 51: Definition of long lines

Line category

Un Un110 kV 500 kV

Long lines 77 km - 99 km 350 km - 450 km

Very long lines > 99 km > 450 km

As mentioned in the previous chapter, the possibility to use the binary informationfrom the load encroachment algorithm improves the possibility to detect high resistivefaults at the same time as the security is improved (risk for unwanted trip due to loadencroachment is eliminated). The possibility to also use blinder together with loadencroachment algorithm will considerable increase the security but might also lowerthe dependability since the blinder might cut off a larger part of the operating area ofthe circle (see right figure 5 in previous chapter).

It is recommended to use at least one of the load discrimination function for longheavy loaded transmission lines.

Parallel line application with mutual coupling



REG 670

GeneralIntroduction of parallel lines in the network is increasing due to difficulties to getnecessary area for new lines.

Parallel lines introduce an error in the measurement due to the mutual couplingbetween the parallel lines. The lines need not to be of the same voltage in order toexperience mutual coupling, and some coupling exists even for lines that are separatedby 100 meters or more. The reason to the introduced error in measuring due to mutualcoupling is the zero sequence voltage inversion that occurs.

It can be shown from analytical calculations of line impedances that the mutualimpedances for positive and negative sequence are very small (< 1-2%) of the selfimpedance and it is practice to neglect them.

From an application point of view there exists three types of network configurations(classes) that must be considered when making the settings for the protection function.Those are:

1. Parallel line with common positive and zero sequence network2. Parallel circuits with common positive but isolated zero-sequence network3. Parallel circuits with positive and zero sequence sources isolated.

One example of class3 networks could be the mutual coupling between a 400 kV lineand rail road overhead lines. This type of mutual coupling is not so common althoughit exists and is not treated any further in this manual.

For each type of network class we can have three different topologies; the parallelline can be in service, out of service, out of service and earthed in both ends.

The reach of the distance protection zone1 will be different depending on theoperation condition of the parallel line. It is therefore recommended to use thedifferent setting groups to handle the cases when the parallel line is in operation andout of service and earthed at both ends.

The mho distance protection within the REL 670 IED can compensate for theinfluence of a zero-sequence mutual coupling on the measurement at single-phase-to-earth faults in the following ways, by using:

• The possibility of different setting values that influence the earth-returncompensation for different distance zones within the same group of settingparameters.

• Different groups of setting parameters for different operating conditions of aprotected multi circuit line.

Most multi circuit lines have two parallel operating circuits. The application guidementioned below recommends in more detail the setting practice for this particulartype of line. The basic principles also apply to other multi circuit lines.



177

Parallel line applicationsThis type of networks are defined as those networks where the parallel transmissionlines terminate at common nodes at both ends. We consider the three most commonoperation modes:

1. parallel line in service.2. parallel line out of service and earthed.3. parallel line out of service and not earthed.

Parallel line in serviceThis type of application is very common and applies to all normal sub-transmissionand transmission networks.

Let us analyze what happens when a fault occurs on the parallel line see figure 71.

Z0m

A B

Z< Z< en05000221.vsd

Figure 71: Class 1, parallel line in service.

The equivalent circuit of the lines can be simplified, see figure 72.

A

B

CZ0m

Z0Z0 m-

Z0Z0 m-

99000038.vsd

Figure 72: Equivalent zero sequence impedance circuit of the double-circuit,parallel, operating line with a single phase-to-earth fault at the remotebusbar.

If the current on the parallel line have negative sign compare to the current on theprotected line i.e. the current on the parallel line has an opposite direction compareto the current on the protected line, the distance function will overreach. If the currentshave the same direction, the distance protection will underreach.

Calculation for a 400 kV line, where we for simplicity have excluded the resistance,gives with X1L=0.303 Ω/km, X0L=0.88 Ω/km, zone 1 reach is set to 90% of the linereactance p=71% i.e. the protection is underreaching with approximately 20%.



REG 670

The zero-sequence mutual coupling can reduce the reach of distance protection onthe protected circuit when the parallel line is in normal operation. The reduction ofthe reach is most pronounced with no infeed in the line terminal closest to the fault.This reach reduction is normally less than 15%. But when the reach is reduced at oneline end, it is proportionally increased at the opposite line end. So this 15% reachreduction does not significantly affect the operation of a permissive under-reachscheme.

Parallel line out of service and earthedgrounded

Z0m

A B

Z< Z<en05000222.vsd

Figure 73: The parallel line is out of service and earthed.

When the parallel line is out of service and earthed at both ends on the bus bar sideof the line CT so that zero sequence current can flow on the parallel line, the equivalentzero sequence circuit of the parallel lines will be according to figure 73.

Z Z00 m

Z Z00 m

Z0m

A

B

C

99000039.vsd

I0

I0

Figure 74: Equivalent zero-sequence impedance circuit for the double-circuitline that operates with one circuit disconnected and earthed at bothends.

Here the equivalent zero sequence impedance is equal to Z0-Z0m in parallel with(Z0-Z0m)/Z0-Z0m+Z0m which is equal to equation 48.

2 20 m

0E

0

Z Z0Z

Z-

=(Equation 48)

The influence on the distance measurement will be a considerable overreach, whichmust be considered when calculating the settings. It is a recommendation to use aseparate setting group for this operation condition since it will reduce the reachconsiderable when the line is in operation.



179

Parallel line out of service and not earthedgrounded

Z0m

A B

Z< Z<en05000223.vsd

Figure 75: Parallel line is out of service and not earthed.

When the parallel line is out of service and not earthe, the zero sequence on that linecan only flow through the line admittance to the earth. The line admittance is highwhich limits the zero sequence current on the parallel line to very low values. Inpractice, the equivalent zero sequence impedance circuit for faults at the remote busbar can be simplified to the circuit shown in figure 75

The line zero-sequence mutual impedance does not influence the measurement of thedistance protection in a faulty circuit. This means that the reach of the underreachingdistance protection zone is reduced if, due to operating conditions, the equivalent zerosequence impedance is set according to the conditions when the parallel system is outof operation and earthed at both ends.

Z Z00 m

Z Z00 m

Z0m

A

B

C

99000040.vsd

I0

I0

Figure 76: Equivalent zero-sequence impedance circuit for a double-circuit linewith one circuit disconnected and not earthed.

The reduction of the reach is equal to equation 49.

21 0

0 1 01 0

1 (2 03 11 (2 3(2 )3

E fm

U

ff

Z Z R ZKZ Z Z RZ Z R

× × + += = -

× × + +× × + +(Equation 49)

This means that the reach is reduced in reactive and resistive directions.

Ensure that the underreaching zones from both line ends will overlap a sufficientamount (at least 10%) in the middle of the protected circuit.



REG 670

Tapped line application

A B

Z< Z<

Z<C

T

IC

IA IB

-IB

en05000224.vsd

Figure 77: Example of tapped line with Auto transformer.

This application gives rise to similar problem that was highlighted in section "Faultinfeed from remote end" i.e. increased measured impedance due to fault currentinfeed. For example for faults between the T point and B station the measuredimpedance at A and C will be

A CA AT TB

A

I IZ Z ZI+

= + ×(Equation 50)

2)

2( ( )1

A CC Trf CT TB

C

I I UZ Z Z ZI U

×+

= + + ×(Equation 51)

Where:

ZAT and ZCT is the line impedance from the B respective C station to the T point.

IA and IC is fault current from A respective C station for fault between T and B.

U2/U1 Transformation ratio for transformation of impedance at U1 side of the transformer tothe measuring side U2 (it is assumed that current and voltage distance function is takenfrom U2 side of the transformer).

For this example with a fault between T and B, the measured impedance from the Tpoint to the fault will be increased by a factor defined as the sum of the currents fromT point to the fault divided by the relay current. For the relay at C, the impedance on



181

the high voltage side U1 has to be transferred to the measuring voltage level by thetransformer ratio.

Another complication that might occur depending on the topology is that the currentfrom one end can have a reverse direction for fault on the protected line. For examplefor faults at T the current from B might go in reverse direction from B to C dependingon the system parameters (see the dotted line in figure 77), given that the distanceprotection in B to T will measure wrong direction.

In three-end application, depending on the source impedance behind the relays, theimpedances of the protected object and the fault location, it might be necessary toaccept zone2 trip in one end or sequential trip in one end.

Generally for this type of application it is difficult to select settings of zone1 that bothgives overlapping of the zones with enough sensitivity without interference with otherzone1 settings i.e. without selectivity conflicts. Careful fault calculations arenecessary to determine suitable settings and selection of proper schemecommunication.


GeneralThe settings for the distance protection function are done in primary values. Theinstrument transformer ratio that has been set for the analogue input card is used toautomatically convert the measured secondary input signals to primary values usedin the distance protection function.

The following basics should be considered, depending on application, when doingthe setting calculations:

• Errors introduced by current and voltage instrument transformers, particularlyunder transient conditions.

• Inaccuracies in the line zero-sequence impedance data, and their effect on thecalculated value of the earth-return compensation factor.

• The effect of infeed between the relay and the fault location, including theinfluence of different Z0/Z1 ratios of the various sources.

• The phase impedance of non transposed lines is not identical for all fault loops.The difference between the impedances for different phase-to-earth loops can beas large as 5-10% of the total line impedance.

• The effect of a load transfer between the terminals of the protected fault resistanceis considerable, the effect must be recognized.

• Zero-sequence mutual coupling from parallel lines.

The setting values of all parameters that belong to the mho distance protection withinthe REL 670 protection IED, must correspond to the parameters of the protected lineand be coordinated to the selectivity plan for the network.



REG 670

Use different setting groups for the cases when the parallel line is in operation, outof service and not earthed and out of service and earthed in both ends. In this way itis possible to optimize the settings for each system condition

Setting of zone1The different errors mentioned earlier usually require a limitation of theunderreaching zone (normally zone 1) to 75 - 90% of the protected line.

In case of parallel lines, consider the influence of the mutual coupling according tosection "Parallel line application with mutual coupling" and select the case(s) thatare valid in your application. We recommend to compensate the setting for the caseswhen the parallel line is in operation, out of service and not earthed and out of serviceand earthed in both ends. The setting of earth fault reach should be selected to be<95% also when parallel line is out of service and earthed at both ends (worst case).

Setting of overreaching zoneThe first overreaching zone (normally zone2) must detect faults on the wholeprotected line. Considering the different errors that might influence the measurementin the same way as for zone1, it is necessary to increase the reach of the overreachingzone to at least 120% of the protected line. The zone2 reach can be even higher if thefault infeed from adjacent lines at remote end are considerable higher than the faultcurrent at the relay location.

The setting shall generally not exceed 80% of the following impedances:

• The impedance corresponding to the protected line, plus the first zone reach ofthe shortest adjacent line.

• The impedance corresponding to the protected line, plus the impedance of themaximum number of transformers operating in parallel on the bus at the remoteend of the protected line.

If the requirements in the bullet list above gives a zone2 reach that gives non-selectivity between the overreaching zone and the shortest outgoing line at the remoteend, the time delay of zone2 must be increased by approximately 200ms to avoidunwanted operation in cases when the telecommunication for the short adjacent lineat remote end is down during faults. The zone2 must not be reduced below 120% ofthe protected line section. The whole line must be covered under all conditions.

The requirement that the zone 2 shall not reach more than 80% of the shortest adjacentline at remote end is highlighted wit a simple example below.

If a fault occurs at point F (see figure 11, also for the explanation of all abbreviationsused), the relay at point A senses the impedance:

Zm ZACIA IB+

IA---------------- ZCF×+ ZAC 1

IBIA-----+

è øç ÷æ ö

ZCF×+= =

(Equation 52)



183

A B

Z<

CIA

IB

Z AC Z CD

Z CF

I A+ IB

en05000457.vsd

Figure 78:

Setting of reverse zoneThe reverse zone is applicable for purposes of scheme communication logic, currentreversal logic, weak-end-infeed logic, and so on. The same applies to the back-upprotection of the bus bar or power transformers. It is necessary to secure, that it alwayscovers the overreaching zone, used at the remote line terminal for thetelecommunication purposes.

Consider the possible enlarging factor that might exist due to fault infeed fromadjacent lines. Equation 53 can be used to calculate the reach in reverse directionwhen the zone is used for blocking scheme, weak-end infeed etc.

( )Zrev 1.2 ZL Z2rem³ × -(Equation 53)

Where:

ZL is the protected line impedance

Z2rem is zone2 setting at remote end of protected line.

In some applications it might be necessary to consider the enlarging factor due tofault current infeed from adjacent lines in the reverse direction in order to obtaincertain sensitivity.

Setting of zones for parallel line application

Parallel line in service – Setting of zone1With reference to section "Parallel line application with mutual coupling", the zonereach can be set to 85% of protected line.

Parallel line in service – setting of zone2Overreaching zones (in general, zones 2 and 3) must overreach the protected circuitin all cases. The greatest reduction of a reach occurs in cases when both parallelcircuits are in service with a single-phase-to-earth fault located at the end of aprotected line. The equivalent zero-sequence impedance circuit for this case is equalto the one in figure 72 in section "Parallel line application with mutual coupling".



REG 670

The components of the zero-sequence impedance for the overreaching zones must beequal to at least:

0 0 0E mR R R= +(Equation 54)

0 0 0E mX X X= +(Equation 55)

Check the reduction of a reach for the overreaching zones due to the effect of the zerosequence mutual coupling. The reach is reduced for a factor:

00 12 1 0

m

f

ZKZ Z R

= -× + +

(Equation 56)

If needed, enlarge the zone reach due to the reduction by mutual coupling, Consideralso the influence on the zone reach due to fault current infeed from adjacent lines.

Parallel line is out of service and earthedgrounded in both endsApply the same measures as in the case with a single set of setting parameters. Thismeans that an underreaching zone must not overreach the end of a protected circuitfor the single-phase-to-earth faults. The equivalent impedance will be according toequation 48

Load impedance limitation, without load encroachment functionThe following instructions is valid when the load encroachment function or blinderfunction is not activated (BlinderMode=Off). The load encroachment function willnot be activated if RLdFw and RLdRv is set to a value higher than expected minimalload impedance. If the load encroachment or blinder function is to be used for all orsome of the measuring zones, the load limitation for those zones according to thischapter can be omitted. Check the maximum permissible resistive reach for any zoneto ensure that there is a sufficient setting margin between the relay boundary and theminimum load impedance. The minimum load impedance (Ω/phase) is calculated as:

Z loadminU2

S-------=(Equation 57)

Where:

U is the minimum phase-to-phase voltage in kV

S is the maximum apparent power in MVA.

The load impedance [Ω/phase] is a function of the minimum operation voltage andthe maximum load current:



185

Z loadUmin

3 Imax×----------------------=

(Equation 58)

Minimum voltage Umin and maximum current Imax are related to the same operatingconditions. Minimum load impedance occurs normally under emergency conditions.

To avoid load encroachment for the phase-to-earth measuring elements, the setimpedance reach of any distance protection zone must be less than 80% of theminimum load impedance.

For setting of the earth fault loop, the following formula can be used:

LoadZZPE 1.6

2(1 cos( ))b£ ×

-(Equation 59)

where:

Zload = magnitude of minimum load impedance

jPE = 180°-2·g =180°–2(ArgPE-QLoad)

The formula is derived by trigonometric analyze of the figure xx below. The lenghof the vector from the origin O to the point F on the circle is defined by the law ofcosine. The result gives the maximum diameter (RFPE) for which the load impedancetouch the circle with the given load condition. An extra margin of 20% is used to giverespect distance between the calculated

jX

R

ZPE/2

ßArgLd

(Ref)

?

O

rc

F

φ

Load

|Zload||Zload|/2 Ohm/phase

en06000406.vsd

Figure 79: Definition of the setting condition to avoid load encroachment forearth fault loop



REG 670

In similar way we can define the maximum setting for phase-to-phase fault bytrigonometric analyze of the same figure 79.The formula to avoid load encroachmentfor the phase-to-phase measuring elements will thus be according to equation 60.

LoadZZPP 1.6

2 (1 cos( PP))j£ ×

× -(Equation 60)

where:

jPP = 180°–2·(ArgPP-QLoad)

All this is applicable for all measuring zones when no power swing detection elementor blinder is activated for the protection zones. Use an additional safety margin ofapproximately 20% in cases when a power swing detection element is in the protectionscheme, refer to the description of the power swing detection function.

Load impedance limitation, with load encroachment function activatedThe parameters for load encroachment shaping of the characteristic are found in thedescription of the phase selection with load encroachment function, refer to section"".

Setting of minimum operating currentsThe operation of the distance function will be blocked if the magnitude of the currentsis below the set value of the parameter IMinOpPP and IMinOpPE.

The default setting of IMinOpPP and IMinOpPE is 20% of IBase where IBase is thechosen base current for the analogue input channels. The value have been proven inpractice to be suitable in most of the applications. However, there might beapplications where it is necessary to increase the sensitivity by reducing the minimumoperating current down to 10% of terminal base current.

The minimum operating fault current is automatically reduced to 75% of its set value,if the distance protection zone has been set for the operation in reverse direction.

Setting of directional modeSetting of the directional mode is by default set to forward by setting the parameterDirMode to Forward.

The selection of Offset mho can be used for sending block signal in blockingTeleprotection scheme, switch onto fault application etc.

The Reverse mode might be use in comparison schemes where it is necessary toabsolute discriminate between forward and reverse fault.

Setting of direction for offset mhoIf offset mho has been selected, one can select if the offset mho shall be Non-Directional, Forward or Reverse by setting the parameter OfffsetMhoDir.



187

When forward or reverse operation is selected, then the operation characteristic willbe cut off by the directional lines used for the quadrilateral characteristic. The settingis by default set to Non-Directional.

Setting of timers for distance protection zonesThe required time delays for different distance-protection zones are independent ofeach other. Distance protection zone1 can also have a time delay, if so required forselectivity reasons. One can set the time delays for all zones (basic and optional) ina range of 0 to 60 seconds. The tripping function of each particular zone can beinhibited by setting the corresponding Operation parameter to Off. Different timedelays are possible for the ph-E (tPE) and for the ph-ph (tPP) measuring loops ineach distance protection zone separately, to further increase the total flexibility of adistance protection.


Table 52: Basic parameter group settings for the ZMHPDIS_21 (ZMH1-) function


ON- ON - Operation Off/On



DirMode OffOffsetForwardReverse

- Forward - Direction mode

LoadEnchMode OffON

- Off - Load enchroachmentmode Off/On

ReachMode OverReachUnderreach

- OverReach - Reach mode Over/Underreach

OpModePE OffON

- ON - Operation mode Off /On of Phase-Earthloops

ZPE 0.005 - 3000.000 0.001 30.000 ohm/p Positive sequenceimpedance setting forPhase-Earth loop

ZAngPE 10 - 90 1 80 Deg Angle for positivesequence lineimpedance for Phase-Earth loop

KN 0.00 - 3.00 0.01 0.80 - Magnitud of earthreturn compensationfactor KN

KNAng -180 - 180 1 -15 Deg Angle for earth returncompensation factorKN

ZRevPE 0.005 - 3000.000 0.001 30.000 ohm/p Reverse reach of thephase to earthloop(magnitude)




REG 670

Parameter Range Step Default Unit DescriptiontPE 0.000 - 60.000 0.001 0.000 s Delay time for

operation of phase toearth elements

IMinOpPE 10 - 30 1 20 %IB Minimum operationphase to earth current

OpModePP OffON

- ON - Operation mode Off /On of Phase-Phaseloops

ZPP 0.005 - 3000.000 0.001 30.000 ohm/p Impedance settingreach for phase tophase elements

ZAngPP 10 - 90 1 85 Deg Angle for positivesequence lineimpedance for Phase-Phase elements

ZRevPP 0.005 - 3000.000 0.001 30.000 ohm/p Reverse reach of thephase to phaseloop(magnitude)

tPP 0.000 - 60.000 0.001 0.000 s Delay time foroperation of phase tophase

IMinOpPP 10 - 30 1 20 %UB Minimum operationphase to phasecurrent

Table 53: Advanced parameter group settings for the ZMHPDIS_21 (ZMH1-) function

Parameter Range Step Default Unit DescriptionOffsetMhoDir Non-directional

ForwardReverse

- Non-directional - Direction mode foroffset mho

OpModetPE OffON

- ON - Operation mode Off /On of Zone timer, Ph-E

OpModetPP OffON

- ON - Operation mode Off /On of Zone timer, Ph-ph

4.6.2 Pole slip protection (PPAM, 78)

Function block name: IEC 60617 graphical symbol:

<ANSI number: 78

IEC 61850 logical node name:



189

4.6.2.1 Application

Normally the generator operates synchronously with the power system, i.e. all thegenerators in the system have the same angular velocity and approximately the samephase angle difference. If the phase angle between the generators gets too large thestable operation of the system cannot be maintained. In such a case the generator losesthe synchronism (pole slip) to the external power system.

The situation with pole slip of a generator can be caused by different reasons.

A short circuit occurs in the external power grid, close to the generator. If the faulttime is too long, the generator will accelerate so much, so the synchronism cannot bemaintained. The relative generator phase angle at a fault and pole slip, relative to theexternal power system, is shown in figure 80.

en06000313.vsd

Figure 80: Relative generator phase angle at a fault and pole slip relative to theexternal power system

The relative angle of the generator is shown for different fault duration at a three-phase short circuit close to the generator. As the fault duration increases the angleswing amplitude increases. When the critical fault clearance time is reached thestability cannot be maintained.



REG 670

Un-damped oscillations occur in the power system, where generator groups atdifferent locations, oscillate against each other. If the connection between thegenerators is too weak the amplitude of the oscillations will increase until the angularstability is lost. At the moment of pole slip there will be a centre of this pole slip,which is equivalent with distance protection impedance measurement of a three-phase. If this point is situated in the generator itself, the generator should be trippedas fast as possible. If the locus of the out of step centre is located in the power systemoutside the generators the power system should, if possible, be split into two parts,and the generators should be kept in service. This split can be made at predefinedlocations (trip of predefined lines) after function from pole slip protection in the lineprotection IED.

en06000314.vsd

Figure 81: Undamped oscillations causing pole slip

The relative angle of the generator is shown a contingency in the power system,causing un-damped oscillations. After a few periods of the oscillation the swingamplitude gets to large and the stability cannot be maintained.

If the excitation of the generator gets too low there is a risk that the generator cannotmaintain synchronous operation. The generator will slip out of phase and operate asan induction machine. Normally the under-excitation protection will detect this state



191

and trip the generator before the pole slip. For this fault the under-excitation protectionand the pole slip protection will give mutual redundancy.

The operation of a generator having pole slip will give risk of damages to the generatorblock.

• At each pole slip there will be significant torque impact on the generator-turbineshaft.

• In asynchronous operation there will be induction of currents in parts of thegenerator normally not carrying current, thus resulting in increased heating. Theconsequence can be damages on insulation and stator/rotor iron.

• At asynchronous operation the generator will absorb a significant amount ofreactive power, thus risking overload of the windings.

The pole slip protection function shall detect out of step conditions and trip thegenerator as fast as possible if the locus of the pole slip is inside the generator. If thecentre of pole slip is outside the generator, situated out in the power grid, the firstaction should be to split the network into two parts, after line protection action. If thisfails there should be operation of the generator pole slip protection, to prevent furtherdamages to the generator block.


Operation: With the parameter Operation the function can be set On/Off.

IBase: The parameter IBase is set to the generator rated current in A, according toequation 61.

3N

N

SIBase

U=

×(Equation 61)

UBase: The parameter UBase is set to the generator rated Voltage (phase-phase) inkV

measureMode: The voltage and current used for the impedance measurement is setby the parameter measureMode. The setting possibilities are: positive sequencevoltage and current, impedance in the measurement loop L1-L2, impedance in themeasurement loop L2-L3 or impedance in the measurement loop L3-L1. If all phasevoltages and phase currents are fed to the IED the positive sequence alternative isrecommended (default).

Further settings can be illustrated in figure 82.



REG 670

en06000548.vsd

REG 670B A

EB EAX’d XT ZS

Zone 1 Zone 2

jX

R

ZB

ZA

Pole slip impedance movement Zone 2

Zone 1

WarnAngle

TripAngle

f

ZC

Figure 82: Settings for the Pole slip detection function

The impedance ZA is the forward impedance as show in figure 82. ZA should be thesum of the transformer impedance XT and the equivalent impedance of the externalsystem ZS. The impedance is given in % of the base impedance, according toequation 62.

3Base

UBaseZ

IBase=

(Equation 62)

The impedance ZB is the reverse impedance as show in figure 82. ZB should be equalto the generator transient reactance X'd. The impedance is given in % of the baseimpedance, see equation 62.



193

The impedance ZC is the forward impedance giving the borderline between zone 1and zone 2. ZC should be equal to the transformer reactance ZT. The impedance isgiven in % of the base impedance, see equation 62.

The angle of the impedance line ZB – ZA is given as anglePhi in degrees. This angleis normally close to 90°.

startAngle: An alarm is given when movement of the rotor is detected and the rotorangle exceeds the angle set for startAngle. The default value 110° is recommended.It should be checked so that the points in the impedance plane, corresponding to thechosen startAngle does not interfere with apparent impedance at maximum generatorload.

tripAngle: If a pole slip has been detected: change of rotor angle corresponding toslip frequency 0.2 – 8 Hz, the slip line ZA – ZB is crossed and the direction of rotationis the same as at start, a trip is given when the rotor angle gets below the settripAngle. The default value 90° is recommended.

n1Limit: The set parameter n1Limit gives the number of pole slips that should occurbefore trip, if the crossing of the slip line ZA – ZB is within zone 1, i.e. the node ofthe pole slip is within the generator transformer block. The default value 1 isrecommended to minimize the stress on the generator and turbine at out of stepconditions.

n2Limit: The set parameter n2Limit gives the number of pole slips that should occurbefore trip, if the crossing of the slip line ZA – ZB is within zone 2, i.e. the node ofthe pole slip is in the external network. The default value 3 is recommended giveexternal protections possibility to split the network and thus limit the systemconsequencies.

tReset: The parameter tReset gives the time for the function to reset after start whenno pole slip been detected. The default value 5 s is recommended.

Setting example for line applicationIn case of out of step conditions this shall be detected and the line between substation1 and 2 shall be tripped.

IED670

ZBLine impedance = ZC

ZA = forward source impedance

en07000014.vsd

Figure 83: Line application of pole slip protection

If the apparent impedance crosses the impedance line ZB – ZA this is the detectioncriterion of out of step conditions, see figure 84.



REG 670

R

X

Apparent impedance at normal load

ZC

ZA

ZB

anglePhi

en07000015.vsd

Figure 84: Impedances to be set for pole slip protection

The setting parameters of the protection is:

ZA: The source impedance in the forward direction

ZB: The source impedance in the reverse direction

ZC: The line impedance in the forward direction

anglePhi: The impedance phase angle

Use the following data:

UBase: 400 kV

SBase set to 1000 MVA

Short circuit power at station 1 without infeed from the protected line: 5000 MVA (assumed to a purereactance)

Short circuit power at station 2 without infeed from the protected line: 5000 MVA (assumed to a purereactance

Line impedance: 2 + j20 ohm

With all phase voltages and phase currents available and fed to the protection IED,it is recommended to set the MeasureMode to positive sequence.

The impedance settings are set in pu with ZBase as reference:



195

2 2400160

1000= = =

UBaseZBase ohm

SBase (Equation 63)

2400( ) ( 2) 2 20 2 52

5000ZA Z line Zsc station j j j ohm= + = + + = +

(Equation 64)

This corresponds to:

2 520.0125 0.325 0.325 88

160j

ZA j pu pu+

= = + = Ð °(Equation 65)

Set ZA to 0.32.

2400( 1) 32

5000ZB Zsc station j j ohm= = =

(Equation 66)


320.20 0.20 90

160j

ZB j pu pu= = = Ð °(Equation 67)

Set ZB to 0.2


2 200.0125 0.125 0.126 84

160j

ZC j pu pu+

= = + = Ð °(Equation 68)

Set ZC to 0.13 and anglePhi to 88°

The warning angle (startAngle) should be chosen not to cross into normal operatingarea. The maximum line power is assumed to be 2000 MVA. This corresponds toapparent impedance:

2 240080

2000U

Z ohmS

= = =(Equation 69)

Simplified, the example can be shown as a triangle, see figure 85.



REG 670

ZA

ZB

Zload

R

X

en07000016.vsd

Figure 85: Simplified figure to derive startAngle

32 52arctan arctan arctan arctan 21.8 33.0 55

80 80ZB ZA

angleStartZload Zload

³ + = + = ° + ° » °(Equation 70)

In case of minor damped oscillations at normal operation we do not want theprotection to start. Therefore we set the start angle with large margin.

Set startAngle to 110°

For the tripAngle it is recommended to set this parameter to 90° to assure limitedstress for the circuit breaker.

In a power system it is desirable to split the system into predefined parts in case ofpole slip. The protection is therefore situated at lines where this predefined split shalltake place.

Normally the n1Limit is set to 1 so that the line will be tripped at the first pole slip.

If the line shall be tripped at all pole slip situations also the parameter n2Limit is setto 1. In other cases a larger number is recommended.



197

Setting example for generator applicationIn case of out of step conditions this shall be checked if the pole slip centre is insidethe generator (zone 1) or if it is situated in the network (zone 2).

ZC

ZAZB

en07000017.vsd

Figure 86: Generator application of pole slip protection

If the apparent impedance crosses the impedance line ZB – ZA this is the detectedcriterion of out of step conditions, see figure 87.

R

X

Apparent impedance at normal load

ZC

ZA

ZB

anglePhi

en07000015.vsd

Figure 87: Impedances to be set for pole slip protection

The setting parameters of the protection are:

ZA The source impedance in the forward direction

ZB The generator transient reactance

ZC The block transformer reactance



REG 670

anglePhi The impedance phase angle

Use the following generator data:

UBase: 20 kV


Xd": 25%

Use the following block transformer data:

UBase: 20 kV (low voltage side)


ek: 15%

Short circuit power from the external network without infeed from the protected line:5000 MVA (assumed to a pure reactance).

We have all phase voltages and phase currents available and fed to the protectionIED. Therefore it is recommended to set the MeasureMode to positive sequence.

The impedance settings are set in pu with ZBase as reference:

2 2202.0

200UBase

ZBase ohmSBase

= = =(Equation 71)

2 220 20( ) ( ) 0.15 0.38200 5000

ZA Z transf Zsc network j j j ohm= + = × + =(Equation 72)


0.380.19 0.19 90

2.0j

ZA j pu pu= = = Ð °(Equation 73)

Set ZA to 0.19

2200.25 0.5

200dZB jX j j ohm= = × =(Equation 74)




199

0.50.25 0.25 90

2.0j

ZB j pu pu= = = Ð °(Equation 75)

Set ZB to 0.25

220 0.15 0.3200TZC jX j j ohm= = × =

(Equation 76)


2 200.0125 0.125 0.126 84

160j

ZC j pu pu+

= = + = Ð °(Equation 77)

Set ZC to 0.15 and anglePhi to 90°.

The warning angle (startAngle) should be chosen not to cross into normal operatingarea. The maximum line power is assumed to be 200 MVA. This corresponds toapparent impedance:

2 2202

200U

Z ohmS

= = =(Equation 78)

Simplified, the example can be shown as a triangle, see figure 88.



REG 670

ZA

ZB

Zload

R

X

en07000016.vsd

Figure 88: Simplified figure to derive startAngle

0.25 0.19arctan arctan arctan arctan 7.1 5.4 13

2 2ZB ZA

angleStartZload Zload

³ + = + = ° + ° » °(Equation 79)

In case of minor damped oscillations at normal operation we do not want theprotection to start. Therefore we set the start angle with large margin.

Set startAngle to 110°.

For the tripAngle it is recommended to set this parameter to 90° to assure limitedstress for the circuit breaker.

If the centre of pole slip is within the generator block set n1Limit to 1 to get trip atfirst pole slip.

If the centre of pole slip is within the network set n2Limit to 3 to get enable split ofthe system before generator trip.




201

Table 54: Basic general settings for the PSPPPAM_78 (PSP1-) function

Parameter Range Step Default Unit DescriptionIBase 0.1 - 99999.9 0.1 3000.0 A Base Current

(primary phasecurrent in Amperes)

UBase 0.1 - 9999.9 0.1 20.0 kV Base Voltage(primary phase-to-phase voltage in kV)

MeasureMode PosSeqL1L2L2L3L3L1

- PosSeq - Measuring mode(PosSeq, L1L2, L2L3,L3L1)

InvertCTcurr NoYes

- No - Invert currentdirection

Table 55: Basic parameter group settings for the PSPPPAM_78 (PSP1-) function


On- Off - Operation On / Off

OperationZ1 OffOn

- On - Operation Zone1 On /Off

OperationZ2 OffOn

- On - Operation Zone2 On /Off

ImpedanceZA 0.00 - 1000.00 0.01 10.00 % Forward impedancein % of Zbase

ImpedanceZB 0.00 - 1000.00 0.01 10.00 % Reverse impedancein % of Zbase

ImpedanceZC 0.00 - 1000.00 0.01 10.00 % Impedance of zone1limit in % of Zbase

AnglePhi 72.00 - 90.00 0.01 85.00 Deg Angle of the slipimpedance line

StartAngle 0.0 - 180.0 0.1 110.0 Deg Rotor angle for thestart signal

TripAngle 0.0 - 180.0 0.1 90.0 Deg Rotor angle for thetrip1 and trip2 signals

N1Limit 1 - 20 1 1 - Count limit for thetrip1 signal

N2Limit 1 - 20 1 3 - Count limit for thetrip2 signal

Table 56: Advanced parameter group settings for the PSPPPAM_78 (PSP1-) function

Parameter Range Step Default Unit DescriptionResetTime 0.000 - 60.000 0.001 5.000 s Time without slip to

reset all signals

4.6.3 Loss of excitation (PDIS, 40)



REG 670

Function block name: UEXx IEC 60617 graphical symbol:

Z<ANSI number: 40

IEC 61850 logical node name: LEXPDIS

4.6.3.1 Application

There are limits for the under-excitation of a synchronous machine. A reduction ofthe excitation current weakens the coupling between the rotor and the external powersystem. The machine may lose the synchronism and starts to operate like an inductionmachine. Then, the reactive consumption will increase. Even if the machine does notlose synchronism it may not be acceptable to operate in this state for a long time. Theunder-excitation increases the generation of heat in the end region of the synchronousmachine. The local heating may damage the insulation of the stator winding and eventhe iron core.

A generator connected to a power system can be represented by an equivalent singlephase circuit as shown in figure 89. For simplicity the equivalent shows a generatorhaving round rotor, (Xd≈Xq).

+

E

-

I, (P, Q)j Xd j Xnet

+

V

-

+

Enet

-

en06000321.vsd

Figure 89: A generator connected to a power system, represented by anequivalent single phase circuit

where:

E represents the internal voltage in the generator,

Xd is the stationary reactance of the generator,

Xnet is an equivalent reactance representing the external power system and

Enet is an infinite voltage source representing the lumped sum of the generators in the system.

The active power out from the generator can be formulated according toequation 80:



203

sinnet

d net

E EP

X Xd

×= ×

+(Equation 80)

where:

The angle δ is the phase angle difference between the voltages E and Enet.

If the excitation of the generator is decreased (loss of field), the voltage E becomeslow. In order to maintain the active power output the angle δ must be increased. It isobvious that the maximum power is achieved at 90°. If the active power cannot bereached at 90º static stability cannot be maintained.

The complex apparent power from the generator, at different angles δ is shown infigure 90. The line corresponding to 90° is the static stability limit. It must be noticedthat the power limitations shown below is highly dependent on the networkimpedance.

en06000322.vsd

P

Q

70º

80º

90º

Figure 90: The complex apparent power from the generator, at different anglesδ

To prevent damages to the generator block, the generator should be tripped at under-excitation. A suitable area, in the PQ-plane, for protection operation is shown infigure 91. In this example limit is set to a small negative reactive power independentof active power.



REG 670

P

70º

80º

90º

Underexcitation ProtectionOperation area

en06000450.vsd

Figure 91: Suitable area, in the PQ-plane, for protection operation

Often the capability curve of a generator describes also the under-excitation capabilityof the generator, see figure 92.



205

0.2 0.4 0.6

-0.3

0.6

-0.5

0.8

Q [pu]

0.8 1

E

DXs=0

B

A

Rated MVA p.f.

0.8 lagging

Rated MVA p.f. 0.95 leading

S

37o

FXe=0.2

CH

18o

GeneratorMotor

Overexcited

Underexcited

F

P [pu]

en06000451.vsd

Figure 92: Capability curve of a generator

where:

AB = Field current limit

BC = Stator current limit

CD = End region heating limit of stator, due to leakage flux

BH = Possible active power limit due to turbine output power limitation

EF = Steady-state limit without AVR

Xs = Source impedance of connected power system

The under-excitation protection can be based on directional power measurement orimpedance measurement.

The straight line in the P-Q plane can be transferred into the impedance plane by usingthe relation shown in equation 81.

* 2 2 2 2

* * * 2 2 2 2V V V V V S V P V QZ j R jXI I V S S S P Q P Q

× × × ×= = = = = + = +

× × + +(Equation 81)

The straight line in the PQ-diagram will be equivalent with a circle in the impedanceplane, see figure 93. In this example the circle is corresponding to constant Q, i.e.characteristic parallel with P-axis.



REG 670

R

X

UnderexcitationProtection Operation area

en06000452.vsd

Figure 93: The straight line in the PQ-diagram, equivalent with a circle in theimpedance plane

The protection in REG 670 is realised by two impedance circles and a directionalrestrain possibility as shown in figure 94.



207

R

X

Underexcitation ProtectionRestrain area

Z1, Fast zone

Z2, Slow zone

en06000453.vsd

Figure 94: The protection in REG 670, realized by two impedance circles and adirectional restrain possibility


Here is described the setting when there are two zones activated of the protection.Zone Z1 will give a fast trip in case of reaching the dynamic limitation of the stability.Zone 2 will give a trip after a longer delay if the generator reaches the static limitationof stability. There is also a directional criterion used to prevent trip at close in externalfaults in case of zones reaching into the impedance area as shown in figure 94.

Operation: With the parameter Operation the function can be set Enable/Disable.

IBase: The parameter IBase is set to the generator rated Current in A, seeequation 82.

3N

N

SIBase

U=

×(Equation 82)

UBase: The parameter UBase is set to the generator rated Voltage (phase-phase) inkV.

measureMode: The voltage and current used for the impedance measurement is setby the parameter measureMode. The setting possibilities are: positive sequence



REG 670

voltage and current, impedance in the measurement loop L1-L2, impedance in themeasurement loop L2-L3 or impedance in the measurement loop L3-L1. If all phasevoltages and phase currents are fed to the IED the positive sequence alternative isrecommended (default).

OperationZ1, OperationZ2: With the parameters OperationZ1 and OperationZ2 eachzone can be set On/Off.

For the two zones the impedance settings are made as shown in figure 95.

R

X

Z1 or Z2

-XoffsetZ1 or -XoffsetZ2

Z1diameter or Z2diameter

en06000460.vsd

Figure 95: Impedance settings for the fast (Z1) and slow (Z2) zone

The impedances are given in pu of the base impedance according to equation 83.

IBase

UBaseZ Base

3=(Equation 83)

XOffsetZ1 and XOffsetZ2, offset of impedance circle top along the X axis, are givennegative value if X < 0.



209

XOffsetZ1: It is recommended to set XOffsetZ1= -X-Xd½ÂÂÂÂ´d/2 andZ1diameter = 1.1· Xd - X-Xd½ÂÂÂÂ´d/2 .

DelayZ1: DelayZ1 is the setting of trip delay for Z1 and this parameter isrecommended to set 0.0 s.

It is recommended to set XOffsetZ2 equal to Xe (the equivalent impedance of theexternal network) and Z2diamater equal to 1.1 · Xd + Xe.

DelayZ2: DelayZ2 is the setting of trip delay for Z2 and this parameter isrecommended to set 2.0 s not to risk unwanted trip at oscillations with temporaryapparent impedance within the characteristic.

DirSuperv: The directional restrain characteristic allows impedance setting withpositive X value without the risk of unwanted operation of the under-excitationfunction. To enable the directional restrain option the parameter DirSuperv shall beset On.

XoffsetDirLine, DirAngle: The parameters XoffsetDirLine and DirAngle are shownin figure 96. XoffsetDirLine is set in pu of the base impedance according toequation 84.

IBase

UBaseZ Base

3=(Equation 84)

XoffsetDirLine is given a positive value if X > 0. DirAngle is set in degrees withnegative value in the 4th quadrant.



REG 670

R

X

Underexcitation ProtectionRestrain area

DirAngleXoffsetDirLine

en06000461.vsd

Figure 96: The parameters XoffsetDirLine and DirAngle


Table 57: Basic general settings for the LEXPDIS_40 (UEX1-) function

Parameter Range Step Default Unit DescriptionIBase 0.1 - 99999.9 0.1 3000 A Base Current

(primary phasecurrent in Amperes)

UBase 0.1 - 9999.9 0.1 20 kV Base Voltage(primary phase-to-phase voltage in kV)

MeasureMode PosSeqL1L2L2L3L3L1

- PosSeq - Measuring mode(PosSeq, L1L2, L2L3,L3L1)



211

Table 58: Basic parameter group settings for the LEXPDIS_40 (UEX1-) function



OperationZ1 OffOn

- On - Operation Off/Onzone Z1

XoffsetZ1 -1000.00 -1000.00

0.01 -10.00 % Offset of Z1 circle toppoint along X axis in% of Zbase

Z1diameter 0.01 - 3000.00 0.01 100.00 % Diameter of imedancecircle for Z1 in % ofZbase

tZ1 0.00 - 6000.00 0.01 0.01 s Trip time delay for Z1

OperationZ2 OffOn

- On - Operation Off/Onzone Z2

XoffsetZ2 -1000.00 -1000.00

0.01 -10.00 % Offset of Z2 circle toppoint along X axis in% of Zbase

Z2diameter 0.01 - 3000.00 0.01 200.00 % Diameter of imedancecircle for Z2 in % ofZbase

tZ2 0.00 - 6000.00 0.01 1.00 s Trip time delay for Z2

Table 59: Advanced general settings for the LEXPDIS_40 (UEX1-) function

Parameter Range Step Default Unit DescriptioninvertCTcurren No

Yes- No - Invert CT current

Table 60: Advanced parameter group settings for the LEXPDIS_40 (UEX1-) function

Parameter Range Step Default Unit DescriptionDirSuperv Off

On- Off - Operation Off/On for

additional directionalcriterion

XoffsetDirLine -1000.00 -3000.00

0.01 0.00 % Offset of directionalline along X axis in %of Zbase

DirAngle -180.0 - 180.0 0.1 -13.0 Deg Angle betweendirectional line and R-axis in degrees

4.7 Current protection

4.7.1 Instantaneous phase overcurrent protection (PIOC, 50)



REG 670

Function block name: IOCx- IEC 60617 graphical symbol:

3I>>

ANSI number: 50

IEC 61850 logical node name:PHPIOC

4.7.1.1 Application

Long transmission lines often transfer great quantities of electric power fromproduction to consumption areas. The unbalance of the produced and consumedelectric power at each end of the transmission line is very large. This means that afault on the line can easily endanger the stability of a complete system.

The transient stability of a power system depends mostly on three parameters (atconstant amount of transmitted electric power):

• The type of the fault. Three-phase faults are the most dangerous, because nopower can be transmitted through the fault point during fault conditions.

• The magnitude of the fault current. A high fault current indicates that the decreaseof transmitted power is high.

• The total fault clearing time. The phase angles between the EMFs of thegenerators on both sides of the transmission line increase over the permittedstability limits if the total fault clearing time, which consists of the protectionoperating time and the breaker opening time, is too long.

The fault current on long transmission lines depends mostly on the fault position anddecreases with the distance from the generation point. For this reason the protectionmust operate very quickly for faults very close to the generation (and relay) point, forwhich very high fault currents are characteristic.

For this reason instantaneous phase overcurrent protection (IOC), which can operatein 10 ms for faults characterized by very high currents, is included in some of theIED. Refer to the ordering information for more details.


The parameters for the phase overcurrent protection function (IOC) are set via thelocal HMI or Protection and Control Manager (PCM 600).

This protection function must operate only in a selective way. So check all systemand transient conditions that could cause its unwanted operation.

Only detailed network studies can determine the operating conditions under whichthe highest possible fault current is expected on the line. In most cases, this currentappears during three-phase fault conditions. But also examine single-phase-to-earthand two-phase-to-earth conditions.



213

Also study transients that could cause a high increase of the line current for shorttimes. A typical example is a transmission line with a power transformer at the remoteend, which can cause high inrush current when connected to the network and can thusalso cause the operation of the built-in, instantaneous, overcurrent protection.

The setting parameters are described below:

IBase: Base current in primary A. This current is used as reference for current setting.If possible to find a suitable value the rated current of the protected object is chosen.

OpMode: This parameter can be set to “2 out of 3” or “1 out of 3”. The setting controlsthe minimum number of phase currents that must be larger than the set operate currentIP>> for operation. Normally this parameter is set to “1 out of 3” and will thus detectall fault types. If the protection is to be used mainly for multi phase faults, “2 out of3” should be chosen.

IP>>: Set operate current in % of IBase.

StValMult: The operate current can be changed by activation of the binary inputENMULT to the set factor StValMult.

Meshed network without parallel lineThe following fault calculations have to be done for three-phase, single-phase-to-earth and two-phase-to-earth faults. With reference to figure 97, apply a fault in Band then calculate the relay through fault phase current IfB. The calculation shouldbe done using the minimum source impedance values for ZA and the maximum sourceimpedance values for ZB in order to get the maximum through fault current from Ato B.

99000474.vsd

~ ~ZA ZBZ L

A B

Relay

I fB

Fault

Figure 97: Through fault current from A to B: IfB

Then a fault in A has to be applied and the through fault current IfA has to be calculated,figure 98. In order to get the maximum through fault current, the minimum value forZB and the maximum value for ZA have to be considered.



REG 670

99000475.vsd

~ ~ZA ZBZ L

A B

Relay

I fA

Fault

Figure 98: Through fault current from B to A: IfA

The relay must not trip for any of the two trough fault currents. Hence the minimumtheoretical current setting (Imin) will be:

Imin MAX I fA IfB,( )³(Equation 85)

A safety margin of 5% for the maximum protection static inaccuracy and a safetymargin of 5% for the maximum possible transient overreach have to be introduced.An additional 20% is suggested due to the inaccuracy of the instrument transformersunder transient conditions and inaccuracy in the system data.

The minimum primary setting (Is) for the instantaneous phase overcurrent protectionis then:

Is 1 3, Imin×³ (Equation 86)

The protection function can be used for the specific application only if this settingvalue is equal to or less than the maximum fault current that the relay has to clear,IF in figure 99.

99000476.vsd

~ ~ZA ZBZ L

A B

Relay

I F

Fault

Figure 99: Fault current: IF



215

The relay setting value IP>> is given in percentage of the primary base current value,IBase. The value for IP>> is given from this formula:

IsI>>= x100IBase (Equation 87)

Meshed network with parallel lineIn case of parallel lines, the influence of the induced current from the parallel line tothe protected line has to be considered. One example is given in figure 100 where thetwo lines are connected to the same busbars. In this case the influence of the inducedfault current from the faulty line (line 1) to the healthy line (line 2) is consideredtogether with the two through fault currents IfA and IfB mentioned previously. Themaximal influence from the parallel line for the relay in figure 100 will be with a faultat the C point with the C breaker open.

A fault in C has to be applied, and then the maximum current seen from the relay(IM ) on the healthy line (this applies for single-phase-to-earth and two-phase-to-earth faults) is calculated.

99000477.vsd

~ ~ZA ZB

ZL1A B

I M

Fault

Relay

ZL2

M

CLine 1

Line 2

Figure 100: Two parallel lines. Influence from parallel line to the through faultcurrent: IM

The minimum theoretical current setting for the overcurrent protection function(Imin) will be:

Imin MAX I fA IfB IM, ,( )³(Equation 88)

Where IfA and IfB have been described in the previous paragraph. Considering thesafety margins mentioned previously, the minimum setting (Is) for the instantaneousphase overcurrent protection is then:

1.3 ImIs in³ × (Equation 89)



REG 670

The protection function can be used for the specific application only if this settingvalue is equal or less than the maximum phase fault current that the relay has to clear.

The relay setting value IP>> is given in percentage of the primary base current value,IBase. The value for IP>> is given from this formula:

IsI>>= x100IBase (Equation 90)


Table 61: Basic parameter group settings for the PHPIOC_50 (IOC1-) function




OpMode 2 out of 31 out of 3

- 1 out of 3 - Select operationmode 2-out of 3 / 1-out of 3

IP>> 1 - 2500 1 200 %IB Operate phasecurrent level in % ofIBase

Table 62: Advanced parameter group settings for the PHPIOC_50 (IOC1-) function

Parameter Range Step Default Unit DescriptionStValMult 0.5 - 5.0 0.1 1.0 - Multiplier for operate

current level

4.7.2 Four step phase overcurrent protection (PTOC, 51_67)

Function block name: TOCx- IEC 60617 graphical symbol:

44 alt

3I>ANSI number: 51/67

IEC 61850 logical node name:OC4PTOC

4.7.2.1 Application

The phase overcurrent protection function is used in several applications in the powersystem. Some applications are:



217

• Short circuit protection of feeders in distribution and subtransmission systems.Normally these feeders have radial structure.

• Back-up short circuit protection of transmission lines.• Back-up short circuit protection of power transformers• Short circuit protection of different kinds of equipment connected to the power

system such as; shunt capacitor banks, shunt reactors, motors and others.• Back-up short circuit protection of power generators.

If VT inputs are not available or not connected, function parameterDirModex shall be left to default value, Non-directional.

In many applications several steps with different current pick up levels and timedelays are needed. TOC can have up to four different, individual settable, steps. Theflexibility of each step of the TOC function is great. The following options arepossible:

Non-directional / Directional function: In most applications the non-directionalfunctionality is used. This is mostly the case when no fault current can be fed fromthe protected object itself. In order to achieve both selectivity and fast fault clearance,the directional function can be necessary.

Choice of delay time characteristics: There are several types of delay timecharacteristics available such as definite time delay and different types of inverse timedelay characteristics. The selectivity between different overcurrent protections isnormally enabled by co-ordination between the function time delays of the differentprotections. To enable optimal co-ordination all overcurrent relays, to be co-ordinatedagainst each other, should have the same time delay characteristic. Therefore a widerange of standardised inverse time characteristics are available: IEC and ANSI. It isalso possible to tailor make the inverse time characteristic.

Normally it is required that the phase overcurrent function shall reset as fast aspossible when the current level gets lower than the operation level. In some casessome sort of delayed reset is required. Therefore different kinds of reset characteristicscan be used.

For some protection applications there can be a need to change the current pick-uplevel for some time. A typical case is when the protection will measure the current toa large motor. At the start up sequence of a motor the start current can be significantlylarger than the rated current of the motor. Therefore there is a possibility to give asetting of a multiplication factor to the current pick-up level. This multiplication factoris activated from a binary input signal to the function.

Power transformers can have a large inrush current, when being energized. Thisphenomenon is due to saturation of the transformer magnetic core during parts of theperiod. There is a risk that inrush current will reach levels above the pick-up currentof the phase overcurrent protection. The inrush current has a large second harmoniccontent. This can be used to avoid unwanted operation of the protection. Therefore



REG 670

the TOC function have a possibility of second harmonic restrain if the level of thisharmonic current reaches a value above a set percentage of the fundamental current.

The phase overcurrent protection is often used as protection for two and three phaseshort circuits. In some cases it is not wanted to detect single-phase earth faults by thephase overcurrent protection. This fault type is detected and cleared after operationof earth fault protection. Therefore it is possible to make a choice how many phases,at minimum, that have to have current above the pick-up level, to enable operation.If set “1 of 3” it is sufficient to have high current in one phase only. If set “2 of 3” or“3 of 3” single-phase earth faults are not detected.


The parameters for the four step phase overcurrent protection function (TOC) are setvia the local HMI or Protection and Control IED Manager (PCM 600).

The following settings can be done for the four step phase overcurrent protection.

MeasType: Selection of discrete Fourier filtered (DFT) or true RMS filtered (RMS)signals Operation: Off/On

IBase: Base current in primary A. This current is used as reference for current setting.It can be suitable to set this parameter to the rated primary current of the current ofthe protected object.

UBase: Base voltage level in kV. This voltage is give as a phase-to-phase voltage andthis is the reference for voltage related settings of the function. Normally the settingshould be chosen to the rated phase-to-phase voltage of the voltage transformerfeeding the protection IED.

AngleRCA: Protection characteristic angle set in degrees. If the angle of the fault loopcurrent has the angle RCA the direction to fault is forward.

AngleROA: Angle value, given in degrees, to define the angle sector of the directionalfunction, see figure 101.

IminOpPhSel: Minimum current for phase selection set in % of IBase. This settingshould be less than the lowest step setting. Default setting is 7%.

StartPhSel: Number of phases, with high current, required for operation. The settingpossibilities are: 1 of 3, 2 of 3 and 3 of 3. Default setting is 1 of 3.

2ndHarmStab: Operate level of 2nd harmonic current restrain set in % of thefundamental current. The setting range is 5-100% I steps of 1%. Default setting is20%.

HarmRestrain: Off/On, enables blocking from harmonic restrain.



219

Uref

Idir

RCA ROA

Forward

Reverse

ROA

en05000745.vsd

Figure 101: Directional function characteristic

Settings for each step (x = 1-4)DirModex: The directional mode of step x. Possible settings are off/nondirectional/forward/reverse.

Characteristx: Selection of time delay characteristic for step x. Definite time delayand different types of inverse time delay characteristics are available according totable 63.

Table 63: Inverse time delay characteristics

Curve name Curve index No.ANSI Extremely Inverse 1

ANSI Very Inverse 2

ANSI Normal Inverse 3

ANSI Moderately Inverse 4

ANSI/IEEE Definite time 5

ANSI Long Time Extremely Inverse 6

ANSI Long Time Very Inverse 7




REG 670

Curve name Curve index No.ANSI Long Time Inverse 8

IEC Normal Inverse 9

IEC Very Inverse 10

IEC Inverse 11

IEC Extremely Inverse 12

IEC Short Time Inverse 13

IEC Long Time Inverse 14

IEC Definite Time 15

User Programmable 17

ASEA RI 18

RXIDG (logarithmic) 19

The different characteristics are described in the “Technical reference manual”.

Ix>: Operation phase current level for step x given in % of IBase.

tx: Definite time delay for step x. Used if definite time characteristic is chosen. Settingrange: 0.000-60.000 s in step of 0.001 s

kx: Time multiplier for the dependent (inverse) characteristic.

IxMult: Multiplier for scaling of the current setting value. If a binary input signal(enableMultiplier) is activated the current operation level is increase by this settingconstant. Setting range: 1.0-10.0

txMin: Minimum operation time for IEC inverse time characteristics. At high currentsthe inverse time characteristic might give a very short operation time. By setting thisparameter the operation time of the step can never be shorter than the setting. Settingrange: 0.000-60.000 s in step of 0.001 s.

In order to fully comply with IEC curves definition setting parameter tMin shall beset to the value which is equal to the operating time of the selected IEC inverse curvefor measured current of twenty times the set current pickup value. Note that theoperating time value is dependent on the selected setting value for time multiplier k.

ResetTypeCrvx: The reset of the delay timer can be made in different ways. Bychoosing setting the possibilities are according to table 64.

Table 64: Reset possibilities

Curve name Curve index no.Instantaneous 1

IEC Reset (constant time) 2

ANSI Reset (inverse time) 3



221

The delay characteristics are described in the “Technical reference manual”. Thereare some restrictions regarding the choice of reset delay.

For the independent time delay characteristics (type 5 and 15) the possible delay timesettings are instantaneous (1) and IEC (2 = set constant time reset).

For ANSI inverse time delay characteristics (type 1-4 and 6-8) all three types of resettime characteristics are available; instantaneous (1), IEC (2 = set constant time reset)and ANSI (3 = current dependent reset time).

For IEC inverse time delay characteristics (type 9-14) the possible delay time settingsare instantaneous (1) and IEC (2 = set constant time reset).

For the customer tailor made inverse time delay characteristics (type 17) all threetypes of reset time characteristics are available; instantaneous (1), IEC (2 = setconstant time reset) and ANSI (3 = current dependent reset time). If the currentdependent type is used settings pr, tr and cr must be given.

HarmRestrainx: Enable block of step x from the harmonic restrain function (2ndharmonic). This function should be used when there is a risk if power transformerinrush currents might cause unwanted trip. Can be set Off/On.

tPCrvx, tACrvx, tBCrvx, tCCrvx: Parameters for customer creation of inverse timecharacteristic curve (Curve type = 17). See equation 91 for the time characteristicequation.

[ ] = + ×

->

æ öç ÷ç ÷ç ÷æ ö

ç ÷ç ÷è øè ø

p

At s B IxMult

iC

in(Equation 91)

For more information, please refer to the “Technical reference manual”.

tPRCrvx, tTRCrvx, tCRCrvx: Parameters for customer creation of inverse reset timecharacteristic curve (Reset Curve type = 3). Further description can be found in the“Technical reference manual”.

Second harmonic restrainIf a power transformer is energized there is a risk that the transformer core will saturateduring part of the period, resulting in an inrush transformer current. This will give adeclining residual current in the network, as the inrush current is deviating betweenthe phases. There is a risk that the phase overcurrent function will give an unwantedtrip. The inrush current has a relatively large ratio of 2nd harmonic component. Thiscomponent can be used to create a restrain signal to prevent this unwanted function.

The settings for the 2nd harmonic restrain are described below.



REG 670

2ndHarmStab: The rate of second harmonic current content for activation of the2nd harmonic restrain signal, to block chosen steps. The setting is given in % of thefundamental frequency residual current. The setting range is 5-100% in step of 1%.The default setting is 20%.

HarmRestrainx: This parameter can be set Off/On, disable or enable the 2nd harmonicrestrain.

The four-step phase overcurrent protection can be used in different ways, dependingon the application where the protection is used. A general description is given below.

The pick up current setting inverse time protection or the lowest current step constantinverse time protection must be given a current setting so that the highest possibleload current does not cause protection operation. Here consideration also has to betaken to the protection reset current, so that a short peak of overcurrent does not causeoperation of the protection even when the overcurrent has ceased. This phenomenonis described in figure 102.

Line phase current

Pick-up current

Reset current

Current I

Time t

The relay does not reset

en05000203.vsd

Figure 102: Pick up and reset current for an overcurrent protection

The lowest setting value can be written according to equation 92.

max1.2puII

k³ ×

(Equation 92)

where:

1.2 is a safety factor,



223

k is the resetting ratio of the protection, and

Imax is the maximum load current.

The maximum load current on the line has to be estimated. From operation statisticsthe load current up to the present situation can be found. The current setting must bevalid also for some years ahead. It is, in most cases, realistic that the setting valuesare updated not more often than once every five years. In many cases this time intervalis still longer. Investigate the maximum load current that different equipment on theline can withstand. Study components such as line conductors, current transformers,circuit breakers, and disconnectors. The manufacturer of the equipment normallygives the maximum thermal load current of the equipment.

There is also a demand that all faults, within the zone that the protection shall cover,must be detected by the phase overcurrent protection. The minimum fault currentIscmin, to be detected by the protection, must be calculated. Taking this value as abase, the highest pick up current setting can be written according to equation 93.

min0.7pu scI I£ ×(Equation 93)

where:

0.7 is a safety factor and

Iscmin is the smallest fault current to be detected by the overcurrent protection.

As a summary the pick up current shall be chosen within the interval stated inequation 94.

maxmin1.2 0.7pu sc

I I Ik

× £ £ ×(Equation 94)

The high current function of the overcurrent protection, which only has a short delayof the operation, must be given a current setting so that the protection is selective toother protection in the power system. It is desirable to have a rapid tripping of faultswithin as large portion as possible of the part of the power system to be protected bythe protection (primary protected zone). A fault current calculation gives the largestcurrent of faults, Iscmax, at the most remote part of the primary protected zone.Considerations have to be made to the risk of transient overreach, due to a possibleDC component of the short circuit current. The lowest current setting of the mostrapid stage, of the phase overcurrent protection, can be written according to

max1.2 t schighI k I³ × ×(Equation 95)

where:



REG 670

1.2 is a safety factor,

kt is a factor that takes care of the transient overreach due to the DC component of the fault currentand can be considered to be less than 1.1

Iscmax is the largest fault current at a fault at the most remote point of the primary protection zone.

The operate times of the phase overcurrent protection has to be chosen so that thefault time is so short so that equipment will not be destroyed due to thermal overload,at the same time as selectivity is assured. For overcurrent protection, in a radial fednetwork, the time setting can be chosen in a graphical way. This is mostly used in thecase of inverse time overcurrent protection. In the figure below is shown how thetime-versus-current curves are plotted in a diagram. The time setting is chosen to getthe shortest fault time with maintained selectivity. Selectivity is assured if the timedifference between the curves is larger than a critical time difference.

en05000204.wmf

Figure 103: Fault time with maintained selectivity

The operation time can be set individually for each overcurrent protection. To assureselectivity between different protective protections, in the radial network, there haveto be a minimum time difference Dt between the time delays of two protections. Theminimum time difference can be determined for different cases. To determine theshortest possible time difference between we must have knowledge about operationtime of protections, breaker opening time and protection resetting time. These time



225

delays can vary significantly between different pieces of equipment. The followingtime delays can be estimated:

protection operation time: 15-60 ms

protection resetting time: 15-60 ms

Breaker opening time: 20-120 ms

ExampleAssume two substations A and B directly connected to each other via one line, asshown in the figure below. We study a fault located at another line from the stationB. The fault current to the overcurrent protection of IED B1 has a magnitude so thatthe protection will have instantaneous function. The overcurrent protection of IEDA1 must have a delayed function. The sequence of events during the fault can bedescribed using a time axis, see figure 104.

I> I>

A1 B1 Feeder

Time axis

t=0 t=t1 t=t2 t=t3The faultoccurs

ProtectionB1 trips

Breaker atB1 opens

ProtectionA1 resets

en05000205.vsd

Figure 104: Sequence of events during fault

where:

t=0 is the fault occurs,

t=t1 is the trip signal from the overcurrent protection at IED B1 is sent. Operation time of thisprotection is t1,

t=t2 is the circuit breaker at IED B1 opens. The circuit breaker opening time is t2 - t1 and

t=t3 is the overcurrent protection at IED A1 resets. The protection resetting time is t3 - t2.

To ensure that the overcurrent protection at IED A1, is selective to the overcurrentprotection at IED B1, the minimum time difference must be larger that the time t3.There are uncertainties in the values of protection operation time, breaker openingtime and protection resetting time. Therefor a safety margin has to be included. With



REG 670

normal values the needed time difference can be calculated according toequation 96.

40 100 40 40 220t ms ms ms ms msD ³ + + + =(Equation 96)

where it is considered that:

the operation time of overcurrent protection B1 is 40 ms

the breaker open time is 100 ms

the resetting time of protection A1 is 40 ms and

the additional margin is 40 ms


Table 65: Basic general settings for the OC4PTOC_51_67 (TOC1-) function

Parameter Range Step Default Unit DescriptionMeasType DFT

RMS- DFT - Selection between

DFT and RMSmeasurement

Table 66: Basic parameter group settings for the OC4PTOC_51_67 (TOC1-) function





AngleRCA 40 - 65 1 55 Deg Relay characteristicangle (RCA)

AngleROA 40 - 89 1 80 Deg Relay operation angle(ROA)

StartPhSel Not Used1 out of 32 out of 33 out of 3

- 1 out of 3 - Number of phasesrequired for op (1 of 3,2 of 3, 3 of 3)

DirMode1 OffNon-directionalForwardReverse

- Non-directional - Directional mode ofstep 1 (off, nodir,forward, reverse)




227

Parameter Range Step Default Unit DescriptionCharacterist1 ANSI Ext. inv.

ANSI Very inv.ANSI Norm. inv.ANSI Mod. inv.ANSI Def. TimeL.T.E. inv.L.T.V. inv.L.T. inv.IEC Norm. inv.IEC Very inv.IEC inv.IEC Ext. inv.IEC S.T. inv.IEC L.T. inv.IEC Def. TimeReservedProgrammableRI typeRD type

- ANSI Def. Time - Selection of timedelay curve type forstep 1

I1> 1 - 2500 1 1000 %IB Phase currentoperate level for step1in % of IBase

t1 0.000 - 60.000 0.001 0.000 s Definitive time delayof step 1

k1 0.05 - 999.00 0.01 0.05 - Time multiplier for theinverse time delay forstep 1

t1Min 0.000 - 60.000 0.001 0.000 s Minimum operatetime for inversecurves for step 1

I1Mult 1.0 - 10.0 0.1 2.0 - Multiplier for currentoperate level for step1



Characterist2 ANSI Ext. inv.ANSI Very inv.ANSI Norm. inv.ANSI Mod. inv.ANSI Def. TimeL.T.E. inv.L.T.V. inv.L.T. inv.IEC Norm. inv.IEC Very inv.IEC inv.IEC Ext. inv.IEC S.T. inv.IEC L.T. inv.IEC Def. TimeReservedProgrammableRI typeRD type






REG 670

Parameter Range Step Default Unit Descriptiont2 0.000 - 60.000 0.001 0.400 s Definitive time delay

of step 2


















229


ANSI Very inv.ANSI Norm. inv.ANSI Def. TimeL.T.E. inv.L.T.V. inv.L.T. inv.IEC Norm. inv.IEC Very inv.IEC inv.IEC Ext. inv.IEC S.T. inv.IEC L.T. inv.IEC Def. TimeReservedProgrammableRI typeRD type







Table 67: Advanced parameter group settings for the OC4PTOC_51_67 (TOC1-) function

Parameter Range Step Default Unit DescriptionIMinOpPhSel 1 - 100 1 7 %IB Minimum current for

phase selection in %of IBase

2ndHarmStab 5 - 100 1 20 %IB Operate level of 2ndharm restrain op in %of Fundamental

ResetTypeCrv1 InstantaneousIEC ResetANSI reset

- Instantaneous - Selection of resetcurve type for step 1

tReset1 0.000 - 60.000 0.001 0.020 s Reset time delay usedin IEC Definite Timecurve step 1

tPCrv1 0.005 - 3.000 0.001 1.000 - Parameter P forcustomerprogrammable curvefor step 1




REG 670

Parameter Range Step Default Unit DescriptiontACrv1 0.005 - 200.000 0.001 13.500 - Parameter A for

customerprogrammable curvefor step 1

tBCrv1 0.00 - 20.00 0.01 0.00 - Parameter B forcustomerprogrammable curvefor step 1

tCCrv1 0.1 - 10.0 0.1 1.0 - Parameter C forcustomerprogrammable curvefor step 1

tPRCrv1 0.005 - 3.000 0.001 0.500 - Parameter PR forcustomerprogrammable curvefor step 1

tTRCrv1 0.005 - 100.000 0.001 13.500 - Parameter TR forcustomerprogrammable curvefor step 1

tCRCrv1 0.1 - 10.0 0.1 1.0 - Parameter CR forcustomerprogrammable curvefor step 1

HarmRestrain1 OffOn

- Off - Enable block of step 1from harmonicrestrain





tACrv2 0.005 - 200.000 0.001 13.500 - Parameter A forcustomerprogrammable curvefor step 2







231

Parameter Range Step Default Unit DescriptiontTRCrv2 0.005 - 100.000 0.001 13.500 - Parameter TR for



HarmRestrain2 OffOn












HarmRestrain3 OffOn

- Off - Enable block of step3from harmonicrestrain







REG 670

Parameter Range Step Default Unit DescriptiontPCrv4 0.005 - 3.000 0.001 1.000 - Parameter P for








HarmRestrain4 OffOn


4.7.3 Instantaneous residual overcurrent protection (PIOC, 50N)

Function block name: IEFx- IEC 60617 graphical symbol:

IN>>

ANSI number: 50N

IEC 61850 logical node name:EFPIOC

4.7.3.1 Application

In many application, when fault current is limited to a defined value by the objectimpedance, an instantaneous earth fault protection can provide fast and selectivetripping.



233

The instantaneous residual overcurrent (IEF), which can operate in 15 ms (50 Hznominal system frequency) for faults characterized by very high currents, is includedin the IED.


The parameters for the instantaneous residual overcurrent protection function (IEF)are set via the local HMI or Protection and Control Manager (PCM 600).

Some guidelines for the choice of setting parameter for the instantaneous residualovercurrent protection (IEF) function is given.

The setting of the function is limited to the operation residual current to the protection(IN>>).

The basic requirement is to assure selectivity, i.e. the IEF function shall not be allowedto operate for faults at other objects than the protected object (line).

For a normal line in a meshed system single phase to earth faults and phase to phaseto earth faults shall be calculated as shown in figure 105 and figure 106. The residualcurrents (3I0) to the protection are calculated. For the fault at the remote line end thisfault current is IfB. In this calculation the operational state with high source impedanceZA and low source impedance ZB should be used. For the fault at the home busbarthis fault current is IfA. In this calculation the operational state with low sourceimpedance ZA and high source impedance ZB should be used.

99000474.vsd

~ ~ZA ZBZ L

A B

Relay

I fB

Fault

Figure 105: Through fault current from A to B: IfB



REG 670

99000475.vsd

~ ~ZA ZBZ L

A B

Relay

I fA

Fault

Figure 106: Through fault current from B to A: IfA

The function shall not operate for any of the calculated currents to the protection. Theminimum theoretical current setting (Imin) will be:

Imin MAX IfA IfA,( )³(Equation 97)

A safety margin of 5% for the maximum static inaccuracy and a safety margin of 5%for maximum possible transient overreach have to be introduced. An additional 20%is suggested due to inaccuracy of instrument transformers under transient conditionsand inaccuracy in the system data.

The minimum primary current setting (Is) is:

Is 1 3, Imin×³ (Equation 98)

In case of parallel lines with zero sequence mutual coupling a fault on the parallelline, as shown in figure 107, should be calculated.

99000477.vsd

~ ~ZA ZB

ZL1A B

I M

Fault

Relay

ZL2

M

CLine 1

Line 2

Figure 107: Two parallel lines. Influence from parallel line to the through faultcurrent: IM



235

The minimum theoretical current setting (Imin) will in this case be:

I m in M AX IfA I fB IM, ,( )³ (Equation 99)

Where:

IfA and IfB have been described for the single line case.

Considering the safety margins mentioned previously, the minimum setting (Is) is:

Is 1 3, Imin×³(Equation 100)

Transformer inrush current shall be considered.

The setting of the protection is set as a percentage of the base current (IBase).

The setting parameters are described below:

IBase: Base current in primary A. This current is used as reference for current setting.If possible to find a suitable value the rated current of the protected object is chosen.

IN>>: Set operate current in % of IBase.

StValMult: The operate current can be changed by activation of the binary inputENMULT to the set factor StValMult.


Table 68: Basic parameter group settings for the EFPIOC_50N (IEF1-) function




IN>> 1 - 2500 1 200 %IB Operate residualcurrent level in % ofIBase

Table 69: Advanced parameter group settings for the EFPIOC_50N (IEF1-) function

Parameter Range Step Default Unit DescriptionStValMult 0.5 - 5.0 0.1 1.0 - Multiplier for operate

current level

4.7.4 Four step residual overcurrent protection (PTOC, 51N/67N)



REG 670

Function block name: TEFx- IEC 60617 graphical symbol:

44 alt

INANSI number:51N/ 67N

IEC 61850 logical node name:EF4PTOC

4.7.4.1 Application

The residual overcurrent protection function is used in several applications in thepower system. Some applications are:

• Earth fault protection of feeders in effectively earthed distribution andsubtransmission systems. Normally these feeders have radial structure.

• Back-up earth fault protection of transmission lines.• Sensitive earth fault protection of transmission lines. The residual overcurrent

protection can have better sensitivity to detect resistive phase to earth faultscompared to distance protection.

• Back-up earth fault protection of power transformers• Earth fault protection of different kinds of equipment connected to the power

system such as shunt capacitor banks, shunt reactors and others.

In many applications several steps with different current pick up levels and timedelays are needed. TEF can have up to four different, individual settable, steps. Theflexibility of each step of the TEF function is great. The following options arepossible:

Non-directional/Directional function: In some applications the non-directionalfunctionality is used. This is mostly the case when no fault current can be fed fromthe protected object itself. In order to achieve both selectivity and fast fault clearance,the directional function can be necessary. This can be the case for earth fault lineprotection in meshed and effectively earthed transmission systems. The directionalresidual overcurrent protection is also well suited to operate in communicationschemes, which enables fast clearance of earth faults on transmission lines. Thedirectional function uses the polarizing quantity as decided by setting. Voltagepolarizing (-3U0) is most commonly used but alternatively Current polarizing wherecurrent in transformer neutrals providing the neutral (zero sequence) source (ZN) isused to polarize (IN*ZN) the function. Dual polarizing where both voltage and currentcomponents is allowed to polarize can also be selected.

Choice of delay time characteristics: There are several types of delay timecharacteristics available such as definite time delay and different types of inverse timedelay characteristics. The selectivity between different overcurrent protections isnormally enabled by co-ordination between the function time delays of the differentprotections. To enable optimal co-ordination all overcurrent relays, to be co-ordinatedagainst each other, should have the same time delay characteristic. Therefore a wide



237

range of standardized inverse time characteristics are available: IEC and ANSI. It isalso possible to tailor make the inverse time characteristic.

Normally it is required that the residual overcurrent function shall reset as fast aspossible when the current level gets lower than the operation level. In some casessome sort of delayed reset is required. Therefore different kinds of reset characteristicscan be used.

For some protection applications there can be a need to change the current pick-uplevel for some time. Therefore there is a possibility to give a setting of a multiplicationfactor INnMultto the residual current pick-up level. This multiplication factor isactivated from a binary input signal ENMULTn to the function.

Power transformers can have a large inrush current, when being energized. Thisinrush current can have residual current components. The phenomenon is due tosaturation of the transformer magnetic core during parts of the cycle. There is a riskthat inrush current will give a residual current that reaches level above the pick-upcurrent of the residual overcurrent protection. The inrush current has a large secondharmonic content. This can be used to avoid unwanted operation of the protection.Therefore the TEF function has a possibility of second harmonic restrainHarmRestrainn if the level of this harmonic current reaches a value above a setpercentage of the fundamental current.


Table 70: Basic parameter group settings for the EF4PTOC_51N67N (TEF1-) function



IBase 1 - 99999 1 3000 A Base value for currentsettings

UBase 0.05 - 2000.00 0.05 400.00 kV Base value for voltagesettings

AngleRCA -180 - 180 1 65 Deg Relay characteristicangle (RCA)

polMethod VoltageCurrentDual

- Voltage - Type of polarization

UPolMin 1 - 100 1 1 %UB Minimum voltagelevel for polarizationin % of UBase

IPolMin 2 - 100 1 5 %IB Minimum current levelfor polarization in % ofIBase

RNPol 0.50 - 1000.00 0.01 5.00 ohm Real part of source Zto be used for currentpolarisation




REG 670

Parameter Range Step Default Unit DescriptionXNPol 0.50 - 3000.00 0.01 40.00 ohm Imaginary part of

source Z to be usedfor currentpolarisation

IN>Dir 1 - 100 1 10 %IB Residual current levelfor Direction releasein % of IBase

2ndHarmStab 5 - 100 1 20 % Second harmonicrestrain operation in% of IN amplitude

BlkParTransf OffOn

- Off - Enable blocking atparallel transformers

UseStartValue IN1>IN2>IN3>IN4>

- IN4> - Current level blk atparallel transf (step1,2, 3 or 4)

SOTF OffSOTFUnderTimeSOTF+UnderTime

- Off - SOTF operationmode (Off/SOTF/Undertime/SOTF+undertime)

ActivationSOTF OpenClosedCloseCommand

- Open - Select signal thatshall activate SOTF

StepForSOTF Step 2Step 3

- Step 2 - Selection of step usedfor SOTF

HarmResSOTF OffOn

- Off - Enable harmonicrestrain function inSOTF

tSOTF 0.000 - 60.000 0.001 0.200 s Time delay for SOTF

t4U 0.000 - 60.000 0.001 1.000 s Switch-onto-faultactive time




- ANSI Def. Time - Time delay curve typefor step 1




239

Parameter Range Step Default Unit DescriptionIN1> 1 - 2500 1 100 %IB Operate residual

current level for step 1in % of IBase

t1 0.000 - 60.000 0.001 0.000 s Independent(defenite) time delayof step 1

k1 0.05 - 999.00 0.01 0.05 - Time multiplier for thedependent time delayfor step 1

IN1Mult 1.0 - 10.0 0.1 2.0 - Multiplier for scalingthe current settingvalue for step 1


HarmRestrain1 OffOn

- On - Enable block of step 1from harmonicrestrain





IN2> 1 - 2500 1 50 %IB Operate residualcurrent level for step 2in % of IBase

t2 0.000 - 60.000 0.001 0.400 s Independent(definitive) time delayof step 2



t2Min 0.000 - 60.000 0.001 0.000 s Minimum operatetime for inversecurves step 2




REG 670

Parameter Range Step Default Unit DescriptionHarmRestrain2 Off

On- On - Enable block of step 2

from harmonicrestrain



Characterist3 ANSI Ext. inv.ANSI Very inv.ANSI Norm. inv.ANSI Mod. inv.ANSI Def. TimeL.T.V. inv.L.T. inv.IEC Norm. inv.IEC Very inv.IEC inv.IEC Ext. inv.IEC S.T. inv.IEC L.T. inv.IEC Def. TimeReservedProgrammableRI typeRD type



t3 0.000 - 60.000 0.001 0.800 s Independent timedelay of step 3




HarmRestrain3 OffOn







241





t4 0.000 - 60.000 0.001 1.200 s Independent(definitive) time delayof step 4



t4Min 0.000 - 60.000 0.001 0.000 s Minimum operatetime in inverse curvesstep 4

HarmRestrain4 OffOn


Table 71: Advanced parameter group settings for the EF4PTOC_51N67N (TEF1-) function

Parameter Range Step Default Unit DescriptionActUnderTime CB position

CB command- CB position - Select signal to

activate under time(CB Pos/CBCommand)

tUnderTime 0.000 - 60.000 0.001 0.300 s Time delay for undertime


- Instantaneous - Reset curve type forstep 1

tReset1 0.000 - 60.000 0.001 0.020 s Reset curve type forstep 1




REG 670

Parameter Range Step Default Unit DescriptiontPCrv1 0.005 - 3.000 0.001 1.000 - Parameter P for



















243

Parameter Range Step Default Unit DescriptiontTRCrv2 0.005 - 100.000 0.001 13.500 - Parameter TR for









tCCrv3 0.1 - 10.0 0.1 1.0 - Parameter C forcustomerprogrammable curvestep 3

tPRCrv3 0.005 - 3.000 0.001 0.500 - Parameter PR forcustomerprogrammable curvestep 3

tTRCrv3 0.005 - 100.000 0.001 13.500 - Parameter TR forcustomerprogrammable curvestep 3






tACrv4 0.005 - 200.000 0.001 13.500 - Parameter A forcustomerprogrammable curvestep 4




REG 670

Parameter Range Step Default Unit DescriptiontBCrv4 0.00 - 20.00 0.01 0.00 - Parameter B for


tCCrv4 0.1 - 10.0 0.1 1.0 - Parameter C forcustomerprogrammable curvestep 4

tPRCrv4 0.005 - 3.000 0.001 0.500 - Parameter PR forcustomerprogrammable curvestep 4

tTRCrv4 0.005 - 100.000 0.001 13.500 - Parameter TR forcustomerprogrammable curvestep 4

tCRCrv4 0.1 - 10.0 0.1 1.0 - Parameter CR forcustomerprogrammable curvestep 4

4.7.5 Sensitive directional residual overcurrent and powerprotection (PSDE, 67N)

Function block name: SDEx- IEC 60617 graphical symbol:

ANSI number: 67N

IEC 61850 logical node name:SDEPSDE

4.7.5.1 Application

In networks with high impedance earthing, the phase to earth fault current issignificantly smaller than the short circuit currents. Another difficulty for earth faultprotection is that the magnitude of the phase to earth fault current is almostindependent of the fault location in the network.

Directional residual current can be used to detect and give selective trip of phase toearth faults in high impedance earthed networks. The protection uses the residualcurrent component 3I0 cos φ, where φ is the angle between the residual current andthe residual voltage, compensated with a characteristic angle. Alternatively thefunction can be set to strict 3I0 level with an check of angle 3I0 and cos φ.

Directional residual power can be used to detect and give selective trip of phase toearth faults in high impedance earthed networks. The protection uses the residualpower component 3I03U0 cos φ, where φ is the angle between the residual currentand the reference residual voltage, compensated with a characteristic angle.



245

A normal undirectional residual current function can also be used and be with definiteor inverse time delay.

A back-up neutral point voltage function is also available for undirectional sensitiveback-up protection.

In an isolated network, i.e. the network is only coupled to earth via the capacitancesbetween the phase conductors and earth, the residual current always has -90º phaseshift compared to the reference residual voltage. The characteristic angle is chosento -90º in such a network.

In resistance earthed networks or in Petersen coil, with a parallel resistor, the activeresidual current component (in phase with the residual voltage) should be used forthe earth fault detection. In such networks the characteristic angle is chosen to 0º.

As the amplitude of the residual current is independent of the fault location theselectivity of the earth fault protection is achieved by time selectivity.

When should the sensitive directional residual overcurrent protection be used andwhen should the sensitive directional residual power protection be used? We havethe following facts to consider:

• Sensitive directional residual overcurrent protection gives possibility for bettersensitivity

• Sensitive directional residual power protection gives possibility to use inversetime characteristics. This is applicable in large high impedance earthed networks,with large capacitive earth fault current

• In some power systems a medium size neutral point resistor is used. Such aresistor will give a resistive earth fault current component of about 200 - 400 Aat a zero resistive phase to earth fault. In such a system the directional residualpower protection gives better possibilities for selectivity enabled by inverse timepower characteristics.


The sensitive earthground fault protection is intended to be used in high impedanceearthed systems, or in systems with resistive earthing where the neutral point resistorgives an earth fault current larger than what normal high impedance gives but smallerthan the phase to phase short circuit current.

In a high impedance system the fault current is assumed to be limited by the systemzero sequence shunt impedance to earth and the fault resistance only. All the seriesimpedances in the system are assumed to be zero.

In the setting of earth fault protection, in a high impedance grounded system, theneutral point voltage (zero sequence voltage) and the earth fault current will be



REG 670

calculated at the desired sensitivity (fault resistance). The complex neutral pointvoltage (zero sequence) can be calculated as:

phase

0f

0

UU

3 R1

Z

=×

+

(Equation 101)

Where

Uphase is the phase voltage in the fault point before the fault,

Rf is the resistance to earth in the fault point and

Z0 is the system zero sequence impedance to earth

The fault current, in the fault point, can be calculated as:

phase

j 0

0 f

3 UI 3I

Z 3 R

×= =

+ ×(Equation 102)

The impedance Z0 is dependent on the system earthing. In an isolated system (withoutneutral point apparatus) the impedance is equal to the capacitive coupling betweenthe phase conductors and earth:

phase

0 c

j

3 UZ jX j

I

×= - = -

(Equation 103)

Where

Ij is the capacitive earth fault current at a non-resistive phase to earth fault

In a system with a neutral point resistor (resistance grounded system) the impedanceZ0 can be calculated as:

c n0

c n

jX 3RZ

jX 3R

- ×=

- +(Equation 104)

Where

Rn is the resistance of the neutral point resistor



247

In many systems there is also a neutral point reactor (Petersen coil) connected to oneor more transformer neutral points. In such a system the impedance Z0 can becalculated as:

( )n n c

0 c n n

n c n n c

9R X XZ jX // 3R // j3X

3X X j3R 3X X= - =

+ × -(Equation 105)

Where

Xn is the reactance of the Petersen coil. If the Petersen coil is well tuned we have 3Xn = Xc In thiscase the impedance Z0 will be: Z0 = 3Rn

Now consider a system with an earthing via a resistor giving higher earth fault currentthan the high impedance earthing. The series impedances in the system can no longerbe neglected. The system with a single phase to earth fault can be described as infigure 108.

Substation A

Substation B

ZlineAB,1 (pos. seq)ZlineAB,0 (zero seq)

ZlineBC,1 (pos. seq)ZlineBC,0 (zero seq)

U0A

U0B

3I0

Phase to earth fault

RNZT,1 (pos. seq)ZT,0 (zero seq)

Source impedanceZsc (pos. seq)

en06000654.vsd

Figure 108: Equivalent of power system for calculation of setting

The residual fault current can be written:



REG 670

phase

0

1 0 f

3U3I

2 Z Z 3 R=

× + + ×(Equation 106)

Where

Uphase is the phase voltage in the fault point before the fault

Z1 is the total positive sequence impedance to the fault point. Z1 = Zsc+ZT,1+ZlineAB,1+ZlineBC,1

Z0 is the total zero sequence impedance to the fault point. Z0 = ZT,0+3RN+ZlineAB,0+ZlineBC,0

Rf is the fault resistance.

The residual voltages in stations A and B can be written:

( )0 A 0 T,0 NU 3I Z 3R= × +(Equation 107)

OB 0 T,0 N lineAB,0U 3I (Z 3R Z )= × + +(Equation 108)

The residual power, measured by the sensitive earth fault protections in A and B willbe:

0 A 0A 0S 3U 3I= ×(Equation 109)

0 B 0B 0S 3U 3I= ×(Equation 110)

The residual power is a complex quantity. The protection will have a maximumsensitivity in the characteristic angle RCA. The apparent residual power componentin the characteristic angle, measured by the protection, can be written:

0 A ,prot 0A 0 AS 3U 3I cosj= × ×(Equation 111)

0 B,prot 0B 0 BS 3U 3I cosj= × ×(Equation 112)

The angles φA and φB are the phase angles between the residual current and theresidual voltage in the station compensated with the characteristic angle RCA.

The protection will use the power components in the characteristic angle directionfor measurement, and as base for the inverse time delay.

The inverse time delay is defined as:



249

0 0inv

0 0

kSN (3I 3U cos (reference))t

3I 3U cos (measured)f

f× × ×

=×

(Equation 113)

In the setting of the function a number of parameters shall be given.

The function can be set On/Off with the setting of Operation

The setting IBase gives the base current in A. Normally the primary rated current ofthe CT feeding the protection should be chosen.

The setting UBase gives the base voltage in kV. Normally the system phase toearth voltage is chosen.

The setting SBase gives the base voltage in kVA. Normally IBase*UBase is chosen.

With the setting OpMode the principle of directional function is chosen.

With OpMode set to 3I0cosFi the current component in the direction equal to thecharacteristic angle RCADir is measured. The characteristic is for RCADir equal to0° is shown in figure 109.

-3U0=Uref

3I0

RCA = 0°, ROA = 90°

= ang(3I0) - ang(3Uref)

3I0 cos

en06000648.vsd

Uref

Figure 109: Characteristic for RCADir equal to 0°

The characteristic is for RCADir equal to -90° is shown in figure 110.



REG 670

-3U0

3I0

RCA = -90°, ROA = 90°

= ang(3I0) – ang(Uref)

3I0 cos

Uref

en06000649.vsd

Figure 110: Characteristic for RCADir equal to -90°

With OpMode set to 3U03I0cosFi the apparent residual power component in thedirection is measured.

With OpMode set to 3I0 and Fi the function will operate if the residual current is largerthan the setting INDir> and the residual current angle is within the sector RCADir± ROADir.

The characteristic for RCADir = 0° and ROADir = 80° is shown in figure 111.



251

-3U0

RCA = 0°

8080

ROA = 80°

Operate area

3I0

en06000652.vsd

Figure 111: Characteristic for RCADir = 0° and ROADir = 80°

DirMode is set Forward or Reverse to set the direction of the trip function from thedirectional residual current function.

All the directional protection modes have a residual current release level settingINRel> which is set in % of the base current. This setting should be chosen smallerthan or equal to the lowest fault current to be detected.

All the directional protection modes have a residual voltage release level settingUNRel> which is set in % of the base voltage. This setting should be chosen smallerthan or equal to the lowest fault residual voltage to be detected.

tDef is the definite time delay, given in s, for the directional residual current protectionif definite time delay is chosen.

tReset is the reset time for definite time delay, given in s. With a tReset time of severalperiods there is increased possibilities to clear intermittent earth faults correctly. Thesetting shall be much shorter than the set trip delay.

The characteristic angle of the directional functions RCADir is set in degrees.RCADir is normally set equal to 0° in a high impedance earthed network with a neutralpoint resistor as the active current component is appearing out on the faulted feederonly. RCADir is set equal to -90° in an isolated network as all currents are mainlycapacitive.

The relay open angle ROADir is set in degrees. For angles differing more thanROADir from RCADir the function from the protection is blocked. The setting canbe used to prevent unwanted function for non-faulted feeders, with large capacitiveearth fault current contributions, due to CT phase angle error.



REG 670

INCosPhi> is the operate current level for the directional function when OpMode isset INCosPhi. The setting is given in % of IBase. The setting should be based oncalculation of the active or capacitive earth fault current at required sensitivity of theprotection.

SN> is the operate power level for the directional function when OpMode is setINUNCosPhi. The setting is given in % of IBase. The setting should be based oncalculation of the active or capacitive earth fault residual power at required sensitivityof the protection.

If the time delay for residual power is chosen the delay time is dependent on twosetting parameters. SRef is the reference residual power, given in % of SBase. kSN isthe time multiplier. The time delay will follow the following expression:

inv0 0

kSN Sreft

3I 3U cos (measured)j×

=× ×

(Equation 114)

INDir> is the operate current level for the directional function when OpMode is setIN and Phi. The setting is given in % of IBase. The setting should be based oncalculation of the earth fault current at required sensitivity of the protection.

OpINNonDir> is set On to activate the non-directional residual current protection.

INNonDir> is the operate current level for the non-directional function. The settingis given in % of IBase. This function can be used for detection and clearance of cross-country faults in a shorter time than for the directional function. The current settingshould be larger than the maximum single phase residual current out on the protectedline.

TimeChar is the selection of time delay characteristic for the non-directional residualcurrent protection. Definite time delay and different types of inverse time delaycharacteristics are available:

Curve name Curve index nr.

ANSI Extremely Inverse 1

ANSI Very Inverse 2

ANSI Normal Inverse 3

ANSI Moderately Inverse 4

ANSI/IEEE Definite time 5

ANSI Long Time Extremely Inverse 6

ANSI Long Time Very Inverse 7

ANSI Long Time Inverse 8

IEC Normal Inverse 9

IEC Very Inverse 10

IEC Inverse 11

IEC Extremely Inverse 12




253

IEC Short Time Inverse 13

IEC Long Time Inverse 14

IEC Definite time 15

User Programmable 17

ASEA RI 18

RXIDG (logarithmic) 19

The different characteristics are described in the Technical referens manual, chapterTime inverse characteristics.

tPCrv, tACrv, tBCrv, tCCrv: Parameters for customer creation of inverse timecharacteristic curve (Curve type = 17). The time characteristic equation is:

[ ] = + ×

->

æ öç ÷ç ÷ç ÷æ ö

ç ÷ç ÷è øè ø

p

At s B InMult

iC

in (Equation 115)

Further description can be found in chapter xx.

tINNonDir is the definite time delay for the non directional earth fault currentprotection, given in s.

OpUN> is set On to activate the trip function of the residual voltage protection.

tUNNonDir is the definite time delay for the trip function of the residual voltageprotection, given in s.


Table 72: Basic general settings for the SDEPSDE_67N (SDE1-) function

Parameter Range Step Default Unit DescriptionIBase 1 - 99999 1 100 A Base Current, in A

UBase 0.05 - 2000.00 0.05 63.50 kV Base Voltage, in kVPhase to Neutral

SBase 0.05 -200000000.00

0.05 6350.00 kVA Base Power, in kVA.IBase*Ubase



REG 670

Table 73: Basic parameter group settings for the SDEPSDE_67N (SDE1-) function



OpMode 3I0Cosfi3I03U0Cosfi3I0 and fi

- 3I0Cosfi - Selection of operationmode for protection

DirMode ForwardReverse

- Forward - Direction of operationforward or reverse

RCADir -179 - 180 1 -90 Deg Relay characteristicangle RCA, in deg

RCAComp -10.0 - 10.0 0.1 0.0 Deg Relay characteristicangle compensation

ROADir 0 - 90 1 90 Deg Relay open angleROA used as releasein phase mode, in deg

INCosPhi> 0.25 - 200.00 0.01 1.00 %IB Set level for 3I0cosFi,directional res overcurrent, in %Ib

SN> 0.25 - 200.00 0.01 10.00 %SB Set level for3I03U0cosFi, startinginv time count, in %Sb

INDir> 0.25 - 200.00 0.01 5.00 %IB Set level fordirectional residualover current prot, in%Ib

tDef 0.000 - 60.000 0.001 0.100 s Definite time delaydirectional residualovercurrent, in sec

SRef 0.03 - 200.00 0.01 10.00 %SB Reference value ofres power for inversetime count, in %Sb

kSN 0.00 - 2.00 0.01 0.10 - Time multiplier settingfor directional residualpower mode

OpINNonDir> OffOn

- Off - Operation of non-directional residualovercurrentprotection

INNonDir> 1.00 - 400.00 0.01 10.00 %IB Set level for nondirectional residualover current, in %Ib

tINNonDir 0.000 - 60.000 0.001 1.000 s Time delay for non-directional residualover current, in sec




255

Parameter Range Step Default Unit DescriptionTimeChar ANSI Ext. inv.


- IEC Norm. inv. - Operation curveselection for IDMToperation

tMin 0.000 - 60.000 0.001 0.040 s Minimum operatetime for IEC IDMTcurves, in sec

kIN 0.00 - 2.00 0.01 1.00 - IDMT time mult fornon-dir res overcurrent protection

OpUN> OffOn

- Off - Operation of non-directional residualovervoltageprotection

UN> 1.00 - 200.00 0.01 20.00 %UB Set level for non-directional residualover voltage, in %Ub

tUNNonDir 0.000 - 60.000 0.001 0.100 s Time delay for non-directional residualover voltage, in sec

INRel> 0.25 - 200.00 0.01 1.00 %IB Residual releasecurrent for alldirectional modes, in%Ib

UNRel> 0.01 - 200.00 0.01 3.00 %UB Residual releasevoltage for alldirection modes, in%Ub

Table 74: Advanced general settings for the SDEPSDE_67N (SDE1-) function

Parameter Range Step Default Unit DescriptionRotResU 0 deg

180 deg- 180 deg - Setting for rotating

polarizing quantity ifnecessary



REG 670

Table 75: Advanced parameter group settings for the SDEPSDE_67N (SDE1-) function

Parameter Range Step Default Unit DescriptiontReset 0.000 - 60.000 0.001 0.040 s Time delay used for

reset of definitetimers, in sec

tPCrv 0.005 - 3.000 0.001 1.000 - Setting P for customerprogrammable curve

tACrv 0.005 - 200.000 0.001 13.500 - Setting A for customerprogrammable curve

tBCrv 0.00 - 20.00 0.01 0.00 - Setting B for customerprogrammable curve

tCCrv 0.1 - 10.0 0.1 1.0 - Setting C forcustomerprogrammable curve

ResetTypeCrv ImmediateIEC ResetANSI reset

- IEC Reset - Reset mode whencurrent drops off.

tPRCrv 0.005 - 3.000 0.001 0.500 - Setting PR forcustomerprogrammable curve

tTRCrv 0.005 - 100.000 0.001 13.500 - Setting TR forcustomerprogrammable curve

tCRCrv 0.1 - 10.0 0.1 1.0 - Setting CR forcustomerprogrammable curve

4.7.6 Thermal overload protection, two time constants (PTTR, 49)

Function block name: TTRx- IEC 60617 graphical symbol:

ANSI number: 49

IEC 61850 logical node name:TRPTTR

4.7.6.1 Application

Transformers in the power system are constructed for a certain maximum load current(power) level. If the current exceeds this level the losses are higher than expected. Asa consequence the temperature of the transformer will increase. If the temperature ofthe transformer reaches too high values the equipment might be damaged:



257

• The insulation within the transformer will have forced ageing. As a consequenceof this the risk of internal phase to phase or phase to earth faults will increase.

• There might be hot spots within the transformer. This will degrade the quality ofthe transformer oil.

In stressed situations in the power system it can be required to overload transformersfor a limited time. This should be done without the above-mentioned risks. Thethermal overload protection provides information and makes temporary overloadingof transformers possible.

The permissible load level of a power transformer is highly dependent on the coolingsystem of the transformer. We have two main principles:

• ONAN: The air is naturally circulated to the coolers without fans and the oil isnaturally circulated without pumps.

• OFAF: The coolers have fans to force air for cooling and pumps to force thecirculation of the transformer oil.

The protection can have two sets of parameters, one for non-forced cooling and onefor forced cooling. Both the permissive steady state loading level as well as thethermal time constant is influenced by the cooling system of the transformer. Theactivation of the two parameter sets can be switched by activation of binary inputsignals COOLING to the function. This can be used for transformers where forcedcooling can be taken out of operation, for example at fan or pump faults.

The thermal overload protection estimates the internal heat content of the transformer(temperature) continuously. This estimation is made by using a thermal model of thetransformer, which is based on current measurement.

If the heat content of the protected transformer reaches a set warning level a signalcan be given to the operator. Two warning levels are available. This enables actionsin the power system to be done before dangerous temperatures are reached. If thetemperature continues to increase to the trip value, the protection initiates trip of theprotected transformer.

After trip from the thermal overload protection the transformer will be cooling. Therewill be a time gap before the heat content (temperature) reaches a level so that thetransformer can be taken into service again. Therefore the protection will continue toestimate the heat content using a set cooling time constant. Energizing of thetransformer can be blocked until the heat content is reduced to a set level.

4.7.6.2 Setting guideline

The parameters for the thermal overload protection, two time constants function(TTR) are set via the local HMI or Protection and Control IED Manager (PCM 600).

The following settings can be done for the thermal overload protection.

Operation: Off/On



REG 670

IBase: Base current in primary A. This current is used as reference for current setting.It can be suitable to set this parameter to the rated primary current of the transformerwinding where the current measurement is made.

IRef: Reference level of the current given in % of IBase. When the current is equalto IRef the final (steady state) heat content is equal to 1. It is suggested to give a settingcorresponding to the rated power of the transformer winding.

IRefMult: If a binary input ENMULT is activated the reference current value can bemultiplied by the factor IRefMult. The activation could be used in case of deviatingambient temperature from the reference value. In the standard for loading of atransformer an ambient temperature of 20°C is used. For lower ambient temperaturesthe load ability is increased and vice versa. IRefMult can be set within a range: 0.01- 10.00.

IBase1: Base current for setting given as percentage of IBase. This setting shall berelated to the status Off of COOLING input. It is suggested to give a settingcorresponding to the rated power of the transformer with natural cooling (ONAN).

IBase2: Base current for setting given as percentage of IBase. This setting shall berelated to the status On of COOLING input. It is suggested to give a settingcorresponding to the rated power of the transformer with forced cooling (OFAF). Ifthe transformer has no forced cooling IBase2 can be set equal to IBase1.

Tau1: The thermal time constant of the protected transformer, related to IBase1 (inputOff) given in minutes.

Tau2: The thermal time constant of the protected transformer, related to IBase2 (inputOn) given in minutes.

The thermal time constant can be obtained from the manufacturers manuals. Thethermal time constant is dependent on the cooling and the amount of oil. Normal timeconstants for medium and large transformers (according to IEC 60354) are about 2.5hours for naturally cooled transformers and 1.5 hours for forced cooled transformers.The time constant can be estimated from measurements of the oil temperature duringa cooling sequence (described in IEC 60354). It is assumed that the transformer isoperated at a certain load level with a constant oil temperature (steady state operation).The oil temperature above the ambient temperature is DQo0. The transformer isdisconnected from the grid (no load). After a time t of at least 30 minutes thetemperature of the oil is measured again. Now the oil temperature above the ambienttemperature is DQot. The thermal time constant can now be estimated as:

0ln lno ot

tt =DQ - DQ

(Equation 116)

If the transformer has forced cooling (OFAF) the measurement should be made bothwith and without the forced cooling in operation, giving Tau2 and Tau1.



259

The time constants can be changed if the current is higher than a set value or lowerthan a set value. If the current is high it is assumed that the forced cooling is activatedwhile it is deactivated at low current. The setting of the parameters below enablesautomatic adjustment of the time constant.

Tau1High: Multiplication factor to adjust the time constant Tau1 if the current ishigher than the set value IHighTau1. IHighTau1 is set in % of IBase1.

Tau1Low: Multiplication factor to adjust the time constant Tau1 if the current is lowerthan the set value ILowTau1. ILowTau1 is set in % of IBase1.

Tau2High: Multiplication factor to adjust the time constant Tau2 if the current ishigher than the set value IHighTau2. IHighTau2 is set in % of IBase2.

Tau2Low: Multiplication factor to adjust the time constant Tau2 if the current is lowerthan the set value ILowTau2. ILowTau2 is set in % of IBase2.

The possibility to change time constant with the current value as the base can be usefulin different applications. Below some examples are given:

• In case a total interruption (low current) of the protected device all coolingpossibilities will be inactive. This can result in a changed value of the timeconstant.

• If other components (motors) are included in the thermal protection function,there is a risk of overheating of that equipment in case of very high current. Thethermal time constant is often smaller for a motor than for the transformer.

ITrip: The steady state current that steady state continuous current that the transformercan withstand. The setting is given in % of Ibasex.

Alarm1: Heat content level for activation of the signal Alarm1. Alarm1 is set in % ofthe trip heat content level.

Alarm2: Heat content level for activation of the signal Alarm2. Alarm2 is set in % ofthe trip heat content level.

ResLo: Lockout release level of heat content to release the lockout signal. When thethermal overload protection trips a lock-out signal is activated. This signal is intendedto block switch in of the protected circuit (transformer) as long as the transformertemperature is high. The signal is released when the estimated heat content is belowthe set value. This temperature value should be chosen below the alarm temperature.ResLo is set in % of the trip heat content level.

ThetaInit: Heat content before activation of the function. This setting can be set alittle below the alarm level. If the transformer is loaded before the activation of theprotection function, its temperature can be higher than the ambient temperature. Thestart point given in the setting will prevent risk of no trip at overtemperature duringthe first moments after activation. ThetaInit is set in % of the trip heat content level.

Warning: If the calculated time to trip factor is below the setting Warning a warningsignal is activated. The setting is given in minutes.



REG 670

Table 76: Basic parameter group settings for the TRPTTR_49 (TTR1-) function



IBase 1 - 99999 1 3000 A Base current in A

IRef 10.0 - 1000.0 1.0 100.0 %IB Reference current in% of IBASE

IRefMult 0.01 - 10.00 0.01 1.00 - Multiplication Factorfor reference current

IBase1 30.0 - 250.0 1.0 100.0 %IB Base current,IBase1without Coolinginpout in % of IBASE

IBase2 30.0 - 250.0 1.0 100.0 %IB Base Current,IBase2,with Cooling input ONin % of IBASE

Tau1 1.0 - 500.0 1.0 60.0 Min Time constant withoutcooling input in min,with IBase1

Tau2 1.0 - 500.0 1.0 60.0 Min Time constant withcooling input in min,with IBase2

IHighTau1 30.0 - 250.0 1.0 100.0 %IB1 Current Sett, in % ofIBase1 for rescalingTC1 by TC1-IHIGH

Tau1High 5 - 2000 1 100 %tC1 Multiplier in % to TC1when current is >IHIGH-TC1

ILowTau1 30.0 - 250.0 1.0 100.0 %IB1 Current Set, in % ofIBase1 for rescalingTC1 by TC1-ILOW

Tau1Low 5 - 2000 1 100 %tC1 Multiplier in % to TC1when current is <ILOW-TC1

IHighTau2 30.0 - 250.0 1.0 100.0 %IB2 Current Set, in % ofIBase2 for rescalingTC2 by TC2-IHIGH

Tau2High 5 - 2000 1 100 %tC2 Multiplier in % to TC2when current is>IHIGH-TC2

ILowTau2 30.0 - 250.0 1.0 100.0 %IB2 Current Set, in % ofIBase2 for rescalingTC2 by TC2-ILOW

Tau2Low 5 - 2000 1 100 %tC2 Multiplier in % to TC2when current is <ILOW-TC2

ITrip 50.0 - 250.0 1.0 110.0 %IBx Steady state operatecurrent level in % ofIBasex




261

Parameter Range Step Default Unit DescriptionAlarm1 50.0 - 99.0 1.0 80.0 %Itr First alarm level in %

of heat content tripvalue

Alarm2 50.0 - 99.0 1.0 90.0 %Itr Second alarm level in% of heat content tripvalue

ResLo 10.0 - 95.0 1.0 60.0 %Itr Lockout reset level in% of heat content tripvalue

ThetaInit 0.0 - 95.0 1.0 50.0 % Initial Heat content, in% of heat content tripvalue

Warning 1.0 - 500.0 0.1 30.0 Min Time setting, belowwhich warning wouldbe set (in min)

tPulse 0.01 - 0.30 0.01 0.10 s Length of the pulse fortrip signal (in msec).

4.7.7 Breaker failure protection (RBRF, 50BF)

Function block name: BFPx- IEC 60617 graphical symbol:

3I>BF

ANSI number: 50BF

IEC 61850 logical node name:CCRBRF

4.7.7.1 Application

In the design of the fault clearance system the N-1 criterion is often used. This meansthat a fault shall be cleared even if any component in the fault clearance system isfaulty. One necessary component in the fault clearance system is the circuit breaker.It is from practical and economical reason not feasible to duplicate the circuit breakerfor the protected component. Instead a breaker failure protection is used.

The breaker protection function will issue a back-up trip command to adjacent circuitbreakers in case of failure to trip of the “normal” circuit breaker for the protectedcomponent. The detection of failure to break the current through the breaker is madeby means of current measurement or as detection of remaining trip signal(unconditional).

The breaker failure protection can also give a re-trip. This means that a second tripsignal is sent to the protected circuit breaker. The re-trip function can be used toincrease the probability of operation of the breaker, or it can be used to avoid back-up trip of many breakers in case of mistakes during relay maintenance and test.



REG 670


The parameters for the breaker failure protection function (BFP) are set via the localHMI or Protection and Control IED Manager (PCM 600).

The following settings can be done for the breaker failure protection.

Operation: Off/On

IBase: Base current in primary A. This current is used as reference for current setting.It can be suitable to set this parameter to the rated primary current of the currenttransformer where the current measurement is made.

FunctionMode: This parameter can be set Current/Contact. This states the way thedetection of failure of the breaker is performed. In the mode current the currentmeasurement is used for the detection. In the mode Contact the long duration ofstart signal (trip) is used as indicator of failure of the breaker. The mode Current andContact means that both ways of detections are activated. Contact mode can be usablein applications where the fault current through the circuit breaker is small. This canbe the case for some generator protection application (for example reverse powerprotection) or in case of line ends with weak end infeed.

BuTripMode: Back-up trip mode is given to state sufficient current criteria to detectfailure to break. For Current operation 2 out of 4 means that at least 2 currents, of thethree phase currents and the residual current, shall be high to indicate breaker failure.1 out of 3 means that at least 1 current of the three phase currents shall be high toindicate breaker failure. 1 out of 4 means that at least 1 current of the three phasecurrents or the residual current shall be high to indicate breaker failure. In mostapplications 1 out of 3 is sufficient. For Contact operation means back-up trip is donewhen circuit breaker is closed (breaker position is used).

RetripMode: This setting states how the re-trip function shall operate. Retrip Offmeans that the re-trip function is not activated. CB Pos Check (circuit breaker positioncheck) and Current means that a phase current must be larger than the operate levelto allow re-trip. CB Pos Check (circuit breaker position check) and Contact meansre-trip is done when circuit breaker is closed (breaker position is used). No CB PosCheck means re-trip is done without check of breaker position.

IP>: Current level for detection of breaker failure, set in % of IBase. This parametershould be set so that faults with small fault current can be detected. The setting canbe chosen in accordance with the most sensitive protection function to start the breakerfailure protection. Typical setting is 10% of IBase.

I>BlkCont: If any contact based detection of breaker failure is used this function canbe blocked if any phase current is larger than this setting level. If theFunctionMode is set Current and Contact breaker failure for high current faults aresafely detected by the current measurement function. To increase security the contactbased function should be disabled for high currents. The setting can be given withinthe range 5 – 200% of IBase.



263

IN>: Residual current level for detection of breaker failure set in % of IBase. In highimpedance earthed systems the residual current at phase to earth faults are normallymuch smaller than the short circuit currents. In order to detect breaker failure at single-phase earth faults in these systems it is necessary to measure the residual currentseparately. Also in effectively earthed systems the setting of the earth fault currentprotection can be chosen to relatively low current level. The BuTripMode is set 1 outof 4. The current setting should be chosen in accordance to the setting of the sensitiveearth fault protection. The setting can be given within he range 2 – 200 % of IBase.

t1: Time delay of the re-trip. The setting can be given within the range 0 – 60 s insteps of 0.001 s. Typical setting is 0 – 50 ms.

t2: Time delay of the back-up trip. The choice of this setting is made as short aspossible at the same time as unwanted operation must be avoided. Typical setting is90 – 150 ms (also dependent of re-trip timer).

The minimum time delay for the re-trip can be estimated as:

_2 1³ + + +cbopen BFP reset margint t t t t(Equation 117)

where:

tcbopen is the maximum opening time for the circuit breaker

tBFP_reset is the maximum time for breaker failure protection to detect correct breaker function (the currentcriteria reset)

tmargin is a safety margin

It is often required that the total fault clearance time shall be less than a given criticaltime. This time is often dependent of the ability to maintain transient stability in caseof a fault close to a power plant.



REG 670

Time

The faultoccurs

Protectionoperate time

Trip and StartBFP

Normal tcbopen

Margin

Retrip delay t1 tcbopen after re-trip

tBFPreset

Minimum back-up trip delay t2

Critical fault clearance time for stability

en05000479.vsd

Figure 112: Time sequence

t2MPh: Time delay of the back-up trip at multi-phase start. The critical fault clearancetime is often shorter in case of multi-phase faults, compared to single phase to earthfaults. Therefore there is a possibility to reduce the back-up trip delay for multi-phasefaults. Typical setting is 90 – 150 ms.

t3: Additional time delay to t2 for a second back-up trip TRBU2. In some applicationsthere might be a requirement to have separated back-up trip functions, trippingdifferent back-up circuit breakers.

tCBAlarm: Time delay for alarm in case of indication of faulty circuit breaker. Thereis a binary input CBFLT from the circuit breaker. This signal is activated wheninternal supervision in the circuit breaker detect that the circuit breaker is unable toclear fault. This could be the case when gas pressure is low in a SF6 circuit breaker,of others. After the set time an alarm is given, so that actions can be done to repairthe circuit breaker. The time delay for back-up trip is bypassed when the CBFLT isactive. Typical setting is 2.0 seconds.

tPulse: Trip pulse duration. This setting must be larger than the critical impulse timeof circuit breakers to be tripped from the breaker failure protection. Typical settingis 200 ms.




265

Table 77: Basic parameter group settings for the CCRBRF_50BF (BFP1-) function




FunctionMode CurrentContactCurrent&Contact

- Current - Detection principle forback-up trip

BuTripMode 2 out of 41 out of 31 out of 4

- 1 out of 3 - Back-up trip mode

RetripMode Retrip OffCB Pos CheckNo CBPos Check

- Retrip Off - Operation mode of re-trip logic

IP> 5 - 200 1 10 %IB Operate phasecurrent level in % ofIBase

IN> 2 - 200 1 10 %IB Operate residualcurrent level in % ofIBase

t1 0.000 - 60.000 0.001 0.000 s Time delay of re-trip

t2 0.000 - 60.000 0.001 0.150 s Time delay of back-uptrip

t2MPh 0.000 - 60.000 0.001 0.150 s Time delay of back-uptrip at multi-phasestart

tPulse 0.000 - 60.000 0.001 0.200 s Trip pulse duration

Table 78: Advanced parameter group settings for the CCRBRF_50BF (BFP1-) function

Parameter Range Step Default Unit DescriptionI>BlkCont 5 - 200 1 20 %IB Current for blocking of

CB contact operationin % of IBase

t3 0.000 - 60.000 0.001 0.030 s Additional time delayto t2 for a secondback-up trip

tCBAlarm 0.000 - 60.000 0.001 5.000 s Time delay for CBfaulty signal

4.7.8 Pole discordance protection (RPLD, 52PD)

Function block name: PDx-- IEC 60617 graphical symbol:

PD

ANSI number: 50PD

IEC 61850 logical node name:CCRPLD



REG 670

4.7.8.1 Application

There is a risk that a circuit breaker will get discordance between the poles at circuitbreaker operation: closing or opening. One pole can be open and the other two closed,or two poles can be open and one closed. Pole discordance of a circuit breaker willcase unsymmetrical currents in the power system. The consequence of this can be:

• Negative sequence currents that will give stress on rotating machines• Zero sequence currents that might give unwanted operation of sensitive earth

fault protections in the power system.

It is therefore important to detect situations with pole discordance of circuit breakers.When this is detected the breaker should be tripped directly.

The pole discordance protection will detect situation with deviating positions of thepoles of the protected circuit breaker. The protection has two different options tomake this detection:

• By connecting the auxiliary contacts in the circuit breaker so that a logic iscreated, a signal can be sent to the protection, indicating pole discordance. Thislogic can also be realized within the protection itself, by using opened and closesignals for each circuit breaker pole, connected to the protection

• Each phase current through the circuit breaker is measured. If the differencebetween the phase current is larger than a CurrUnsymLevel this is an indicationof pole discordance, and the protection will operate.


The parameters for the pole-discordance protection function (PDx) are set via thelocal HMI or Protection and Control IED Manager (PCM 600).

The following settings can be done for the pole-discordance protection.

Operation: Off/On

IBase: Base current in primary A. This current is used as reference for current setting.It can be suitable to set this parameter to the rated primary current of the protectedobject where the current measurement is made.

timeDelayTrip: Time delay of the operation.

ContSel: Operation of the contact based pole discordance function. Can be set: Off/PD signal fromCB/Pole pos aux. cont. If PD signal fromCB is chosen the logic todetect pole discordance is made close to the breaker auxiliary contacts and only onesignal is connected to the IED. If the CB/Pole pos aux cont. alternative is chosen eachopen close signal is connected to the IED and the logic to detect pole discordance isrealised within the function itself.



267

CurrSel: Operation of the current based pole discordance function. Can be set: Off/CB open monitor/Continuous monitor. In the alternative CB open monitor thefunction is activated only directly in connection to breaker open or close command(during 200 ms). In the alternative Continuous monitor function is continuouslyactivated.

CurrUnsymLevel: Unsymmetrical magnitude of lowest phase current compared tothe highest, set in % of the highest phase current. Natural difference between phasecurrent in 1 1/2 breaker installations must be considered. For circuit breakers in 1 1/2breaker configurated switchyards there might be natural unbalance currents throughthe breaker. This is due to the existence of low impedance current paths in theswitchyard. This phenomenon must be considered in the setting of the parameter.

CurrRelLevel: Current level of the largest phase current to allow operation of thecurrent.


Table 79: Basic parameter group settings for the CCRPLD_52PD (PD01-) function



IBase 1 - 99999 1 3000 - Base current

tTrip 0.000 - 60.000 0.001 0.300 s Time delay betweentrip condition and tripsignal

ContSel OffPD signal from CBPole pos aux cont.

- Off - Contact functionselection

CurrSel OffCB oper monitorContinuousmonitor

- Off - Current functionselection

CurrUnsymLevel 0 - 100 1 80 % Unsym magn oflowest phase currentcompared to thehighest.

CurrRelLevel 0 - 100 1 10 %IB Current magnitude forrelease of the functionin % of IBase

4.7.9 Directional underpower protection (PDUP, 32)


P><ANSI number: 32




REG 670

4.7.9.1 Application

The task of a generator in a power plant is to convert mechanical energy available asa torque on a rotating shaft to electric energy.

Sometimes, the mechanical power from a prime mover may decrease so much that itdoes not cover bearing losses and ventilation losses. Then, the synchronous generatorbecomes a synchronous motor and starts to take electric power from the rest of thepower system. This operating state, where individual synchronous machines operateas motors, implies no risk for the machine itself. If the generator under considerationis very large and if it consumes lots of electric power, it may be desirable to disconnectit to ease the task for the rest of the power system.

Often, the motoring condition may imply that the turbine is in a very dangerous state.The task of the reverse power protection is to protect the turbine and not to protectthe generator itself.

Steam turbines easily become overheated if the steam flow becomes too low or if thesteam ceases to flow through the turbine. Therefore, turbo-generators should havereverse power protection. There are several contingencies that may cause reversepower: break of a main steam pipe, damage to one or more blades in the steam turbineor inadvertent closing of the main stop valves. In the last case, it is highly desirableto have a reliable reverse power protection. It may prevent damage to an otherwiseundamaged plant.

During the routine shutdown of many thermal power units, the reverse powerprotection gives the tripping impulse to the generator breaker (the unit breaker). Bydoing so, one prevents the disconnection of the unit before the mechanical power hasbecome zero. Earlier disconnection would cause an acceleration of the turbinegenerator at all routine shutdowns. This should have caused overspeed and highcentrifugal stresses.

When the steam ceases to flow through a turbine, the cooling of the turbine bladeswill disappear. Now, it is not possible to remove all heat generated by the windagelosses. Instead, the heat will increase the temperature in the steam turbine andespecially of the blades. When a steam turbine rotates without steam supply, theelectric power consumption will be about 2% of rated power. Even if the turbinerotates in vacuum, it will soon become overheated and damaged. The turbineoverheats within minutes if the turbine loses the vacuum.

The critical time to overheating of a steam turbine varies from about 0.5 to 30 minutesdepending on the type of turbine. A high-pressure turbine with small and thin bladeswill become overheated more easily than a low-pressure turbine with long and heavyblades. The conditions vary from turbine to turbine and it is necessary to ask theturbine manufacturer in each case.

Power to the power plant auxiliaries may come from a station service transformerconnected to the primary side of the step-up transformer. Power may also come froma start-up service transformer connected to the external network. One has to design



269

the reverse power protection so that it can detect reverse power independent of theflow of power to the power plant auxiliaries.

Hydro turbines tolerate reverse power much better than steam turbines do. OnlyKaplan turbine and bulb turbines may suffer from reverse power. There is a risk thatthe turbine runner moves axially and touches stationary parts. They are not alwaysstrong enough to withstand the associated stresses.

Ice and snow may block the intake when the outdoor temperature falls far below zero.Branches and leaves may also block the trash gates. A complete blockage of the intakemay cause cavitation. The risk for damages to hydro turbines can justify reverse powerprotection in unattended plants.

A hydro turbine that rotates in water with closed wicket gates will draw electric powerfrom the rest of the power system. This power will be about 10% of the rated power.If there is only air in the hydro turbine, the power demand will fall to about 3%.

Diesel engines should have reverse power protection. The generator will take about15% of its rated power or more from the system. A stiff engine may require perhaps25% of the rated power to motor it. An engine that is well run in might need no morethan 5%. It is necessary to obtain information from the engine manufacturer and tomeasure the reverse power during commissioning.

Gas turbines usually do not require reverse power protection.

Figure 113 illustrates the reverse power protection with underpower relay and withoverpower relay. The underpower relay gives a higher margin and should providebetter dependability. On the other hand, the risk for unwanted operation immediatelyafter synchronization may be higher. One should set the underpower relay to trip ifthe active power from the generator is less than about 2%. One should set theoverpower relay to trip if the power flow from the network to the generator is higherthan 1%.

Underpower Relay Overpower Relay

Q Q

P P

Operating pointwithoutturbine torque

Margin Margin

OperateLine

OperateLine


en06000315.vsd

Figure 113: Reverse power protection with underpower relay and overpowerrelay



REG 670



IBase: The parameter IBase is set to the generator rated current in A, seeequation 118.

3N

N

SIBase

U=

×(Equation 118)


measureMode: The voltage and current used for the power measurement is set by theparameter measureMode. The setting possibilities are shown in table 80.

Table 80: Complex power calculation

Set value measureMode Formula used for complex power calculationL1, L2, L3

* * *1 1 2 2 3 3L L L L L LS U I U I U I= × + × + ×

Arone* *

1 2 1 2 3 3L L L L L LS U I U I= × - ×

PosSeq*3 PosSeq PosSeqS U I= × ×

L1L2* *

1 2 1 2( )L L L LS U I I= × -

L2L3* *

2 3 2 3( )L L L LS U I I= × -

L3L1* *

3 1 3 1( )L L L LS U I I= × -

L1*

1 13 L LS U I= × ×

L2*

2 23 L LS U I= × ×

L3*

3 33 L LS U I= × ×

The function has two stages with the same setting parameters.

OpMode1(2) is set to define the function of the stage. Possible settings are:

On: the stage is activated Off: the stage is disabled



271

The function gives trip if the power component in the direction defined by the settingAngle1(2) is smaller than the set pick up power value Power1(2)

Operate

Angle1(2)

Power1(2)

P

Q

en06000441.vsd

Figure 114: Underpower mode

The setting Power1(2) gives the powercomponent pick up value in the Angle1(2)direction. The setting is given in pu of the generator rated power, see equation 128.

3NS UBase IBase= × ×(Equation 128)

The setting Angle1(2) gives the characteristic angle giving maximum sensitivity ofthe power protection function. The setting is given in degrees. For active power theset angle should be 0° or 180°. 0° should be used for generator low forward powerprotection.



REG 670

OperateAngle1(2) = 0°

Power1(2)

P

Q

en06000556.vsd

Figure 115: For reactive power the set angle should be 90° or -90°

TripDelay1(2) is set in seconds to give the time delay for trip of the stage after pickup.

Hysteresis1(2) is given in pu of generator rated power according to equation 129.


The drop out power will be Power1(2) + Hysteresis1(2).

The possibility to have low pass filtering of the measured power can be made as shownin the formula:

( )1Old CalculatedS k S k S= × + - ×(Equation 130)

Where

S is a new measured value to be used for the protection function

Sold is the measured value given from the function in previous execution cycle

SCalculated is the new calculated value in the present execution cycle

k is settable parameter

The default value of k = 0 is recommended in generator applications as the trip delayis normally longer than the execution cycle of the function.



273

The calibration factors for current and voltage measurement errors are set % of ratedcurrent/voltage:

IAmpComp5, IAmpComp30, IAmpComp100

UAmpComp5, UAmpComp30, UAmpComp100

IAngComp5, IAngComp30, IAngComp100

The angle compensation is given as difference between current and voltage angleerrors.

The values are given for operating points 5, 30 and 100% of rated current/voltage.The values should be available from instrument transformer test protocols.


Table 81: Basic general settings for the GUPPDUP_37 (GUP1-) function

Parameter Range Step Default Unit DescriptionIBase 1 - 99999 1 3000 A Current-Reference

(primary current A)

UBase 0.05 - 2000.00 0.05 400.00 kV Voltage-Reference(primary voltage kV)

Mode L1, L2, L3AronePos SeqL1L2L2L3L3L1L1L2L3

- Pos Seq - Selection ofmeasured current andvoltage

Table 82: Basic parameter group settings for the GUPPDUP_37 (GUP1-) function



OpMode1 OffUnderPower

- UnderPower - Operation mode 1

Power1 0.0 - 500.0 0.1 1.0 %SB Power setting forstage 1 in % of Sbase

Angle1 -180.0 - 180.0 0.1 0.0 Deg Angle for stage 1

TripDelay1 0.010 - 6000.000 0.001 1.000 s Trip delay for stage 1

DropDelay1 0.010 - 6000.000 0.001 0.060 s Drop delay for stage 1

OpMode2 OffUnderPower

- UnderPower - Operation mode 2





REG 670

Parameter Range Step Default Unit DescriptionAngle2 -180.0 - 180.0 0.1 0.0 Deg Angle for stage 2



Table 83: Advanced parameter group settings for the GUPPDUP_37 (GUP1-) function

Parameter Range Step Default Unit Descriptionk 0.00 - 0.99 0.01 0.00 - Low pass filter

coefficient for powermeasurement, P andQ

Hysteresis1 0.2 - 5.0 0.1 0.5 pu Absolute hysteresis ofstage 1

Hysteresis2 0.2 - 5.0 0.1 0.5 pu Absolute hysteresis ofstage 2

IAmpComp5 -10.000 - 10.000 0.001 0.000 % Amplitude factor tocalibrate current at5% of Ir



UAmpComp5 -10.000 - 10.000 0.001 0.000 % Amplitude factor tocalibrate voltage at5% of Ur



IAngComp5 -10.000 - 10.000 0.001 0.000 Deg Angle calibration forcurrent at 5% of Ir



4.7.10 Directional overpower protection (PDOP, 32)

Function block name: GOPx IEC 60617 graphical symbol:

P><ANSI number: 32

IEC 61850 logical node name:GOPPDOP



275


The task of a generator in a power plant is to convert mechanical energy available asa torque on a rotating shaft to electric energy.

Sometimes, the mechanical power from a prime mover may decrease so much that itdoes not cover bearing losses and ventilation losses. Then, the synchronous generatorbecomes a synchronous motor and starts to take electric power from the rest of thepower system. This operating state, where individual synchronous machines operateas motors, implies no risk for the machine itself. If the generator under considerationis very large and if it consumes lots of electric power, it may be desirable to disconnectit to ease the task for the rest of the power system.

Often, the motoring condition may imply that the turbine is in a very dangerous state.The task of the reverse power protection is to protect the turbine and not to protectthe generator itself.

Steam turbines easily become overheated if the steam flow becomes too low or if thesteam ceases to flow through the turbine. Therefore, turbo-generators should havereverse power protection. There are several contingencies that may cause reversepower: break of a main steam pipe, damage to one or more blades in the steam turbineor inadvertent closing of the main stop valves. In the last case, it is highly desirableto have a reliable reverse power protection. It may prevent damage to an otherwiseundamaged plant.

During the routine shutdown of many thermal power units, the reverse powerprotection gives the tripping impulse to the generator breaker (the unit breaker). Bydoing so, one prevents the disconnection of the unit before the mechanical power hasbecome zero. Earlier disconnection would cause an acceleration of the turbinegenerator at all routine shutdowns. This should have caused overspeed and highcentrifugal stresses.

When the steam ceases to flow through a turbine, the cooling of the turbine bladeswill disappear. Now, it is not possible to remove all heat generated by the windagelosses. Instead, the heat will increase the temperature in the steam turbine andespecially of the blades. When a steam turbine rotates without steam supply, theelectric power consumption will be about 2% of rated power. Even if the turbinerotates in vacuum, it will soon become overheated and damaged. The turbineoverheats within minutes if the turbine loses the vacuum.

The critical time to overheating of a steam turbine varies from about 0.5 to 30 minutesdepending on the type of turbine. A high-pressure turbine with small and thin bladeswill become overheated more easily than a low-pressure turbine with long and heavyblades. The conditions vary from turbine to turbine and it is necessary to ask theturbine manufacturer in each case.

Power to the power plant auxiliaries may come from a station service transformerconnected to the primary side of the step-up transformer. Power may also come froma start-up service transformer connected to the external network. One has to design



REG 670

the reverse power protection so that it can detect reverse power independent of theflow of power to the power plant auxiliaries.

Hydro turbines tolerate reverse power much better than steam turbines do. OnlyKaplan turbine and bulb turbines may suffer from reverse power. There is a risk thatthe turbine runner moves axially and touches stationary parts. They are not alwaysstrong enough to withstand the associated stresses.

Ice and snow may block the intake when the outdoor temperature falls far below zero.Branches and leaves may also block the trash gates. A complete blockage of the intakemay cause cavitation. The risk for damages to hydro turbines can justify reverse powerprotection in unattended plants.

A hydro turbine that rotates in water with closed wicket gates will draw electric powerfrom the rest of the power system. This power will be about 10% of the rated power.If there is only air in the hydro turbine, the power demand will fall to about 3%.

Diesel engines should have reverse power protection. The generator will take about15% of its rated power or more from the system. A stiff engine may require perhaps25% of the rated power to motor it. An engine that is well run in might need no morethan 5%. It is necessary to obtain information from the engine manufacturer and tomeasure the reverse power during commissioning.

Gas turbines usually do not require reverse power protection.

Figure 116 illustrates the reverse power protection with underpower relay and withoverpower relay. The underpower relay gives a higher margin and should providebetter dependability. On the other hand, the risk for unwanted operation immediatelyafter synchronization may be higher. One should set the underpower relay to trip ifthe active power from the generator is less than about 2%. One should set theoverpower relay to trip if the power flow from the network to the generator is higherthan 1%.

Underpower Relay Overpower Relay

Q Q

P P


Margin Margin

OperateLine

OperateLine


en06000315.vsd

Figure 116: Reverse power protection with underpower relay and overpowerrelay



277



IBase: The parameter IBase is set to the generator rated current in A, seeequation 131.

3N

N

SIBase

U=

×(Equation 131)


measureMode: The voltage and current used for the power measurement is set by theparameter measureMode. The setting possibilities are shown in table 84.

Table 84: Complex power calculation

Set value measureMode Formula used for complex power calculationL1, L2, L3

* * *1 1 2 2 3 3L L L L L LS U I U I U I= × + × + ×

Arone* *

1 2 1 2 3 3L L L L L LS U I U I= × - ×

PosSeq*3 PosSeq PosSeqS U I= × ×

L1L2* *

1 2 1 2( )L L L LS U I I= × -

L2L3* *

2 3 2 3( )L L L LS U I I= × -

L3L1* *

3 1 3 1( )L L L LS U I I= × -

L1*

1 13 L LS U I= × ×

L2*

2 23 L LS U I= × ×

L3*

3 33 L LS U I= × ×

The function has two stages with the same setting parameters.

OpMode1(2) is set to define the function of the stage. Possible settings are:

On: the stage is activated Off: the stage is disabled



REG 670

The function gives trip if the power component in the direction defined by the settingAngle1(2) is largerr than the set pick up power value Power1(2)

Operate

Angle1(2)

Power1(2)

P

Q

en06000440.vsd

Figure 117: Overpower mode

The setting Power1(2) gives the powercomponent pick up value in the Angle1(2)direction. The setting is given in pu of the generator rated power, see equation 141.


The setting Angle1(2) gives the characteristic angle giving maximum sensitivity ofthe power protection function. The setting is given in degrees. For active power theset angle should be 0° or 180°. 180° should be used for generator reverse powerprotection.



279

Operate Angle1(2) = 180p

Power1(2)

P

Q

en06000557.vsd

Figure 118: For reactive power the set angle should be 90° or -90°

TripDelay1(2) is set in seconds to give the time delay for trip of the stage after pickup.

Hysteresis1(2) is given in pu of generator rated power according to equation 142.


The drop out power will be Power1(2) - Hysteresis1(2).

The possibility to have low pass filtering of the measured power can be made as shownin the formula:

( )1Old CalculatedS k S k S= × + - ×(Equation 143)

Where

S is a new measured value to be used for the protection function

Sold is the measured value given from the function in previous execution cycle

SCalculated is the new calculated value in the present execution cycle

k is settable parameter



REG 670

The default value of k = 0 is recommended in generator applications as the trip delayis normally longer than the execution cycle of the function.

The calibration factors for current and voltage measurement errors are set % of ratedcurrent/voltage:

IAmpComp5, IAmpComp30, IAmpComp100

UAmpComp5, UAmpComp30, UAmpComp100

IAngComp5, IAngComp30, IAngComp100

The angle compensation is given as difference between current and voltage angleerrors.

The values are given for operating points 5, 30 and 100% of rated current/voltage.The values should be available from instrument transformer test protocols.


Table 85: Basic general settings for the GOPPDOP_32 (GOP1-) function

Parameter Range Step Default Unit DescriptionIBase 1 - 99999 1 3000 A Current-Reference

(primary current A)

UBase 0.05 - 2000.00 0.05 400.00 kV Voltage-Reference(primary voltage kV)


- Pos Seq - Selection ofmeasured current andvoltage

Table 86: Basic parameter group settings for the GOPPDOP_32 (GOP1-) function



OpMode1 OffOverPower

- OverPower - Operation mode 1





OpMode2 OffOverPower

- OverPower - Operation mode 2




281

Parameter Range Step Default Unit DescriptionPower2 0.0 - 500.0 0.1 120.0 %SB Power setting for

stage 2 in % of Sbase




Table 87: Advanced parameter group settings for the GOPPDOP_32 (GOP1-) function

Parameter Range Step Default Unit Descriptionk 0.00 - 0.99 0.01 0.00 - Low pass filter

coefficient for powermeasurement, P andQ

Hysteresis1 0.2 - 5.0 0.1 0.5 pu Absolute hysteresis ofstage 1 in % of Sbase

Hysteresis2 0.2 - 5.0 0.1 0.5 pu Absolute hysteresis ofstage 2 in % of Sbase










4.8 Voltage protection

4.8.1 Two step undervoltage protection (PTUV, 27)



REG 670

Function block name: TUVx- IEC 60617 graphical symbol:

3U<

ANSI number: 27

IEC 61850 logical node name:UV2PTUV

4.8.1.1 Application

The two-step undervoltage protection function (TUV) is applicable in all situations,where reliable detection of low phase voltages is necessary. The function can also beused as a supervision and fault detection function for other protection functions, toincrease the security of a complete protection system.

The undervoltage protection is applied to power system elements, such as generators,transformers, motors and power lines in order to detect low voltage conditions. Lowvoltage conditions are caused by abnormal operation or fault in the power system.The undervoltage protection can be used in combination with overcurrent protections,either as restraint or in logic "and gates" of the trip signals issued by the two functions.Other applications are the detection of "no voltage" condition, e.g. before theenergization of a HV line or for automatic breaker trip in case of a blackout. Theundervoltage protection is also used to initiate voltage correction measures, likeinsertion of shunt capacitor banks to compensate for reactive load and therebyincreasing the voltage. The function has a high measuring accuracy and settinghysteresis to allow applications to control reactive load.

The undervoltage protection can be used to disconnect from the network apparatuses,like electric motors, which will be damaged when subject to service under low voltageconditions. The undervoltage protection TUV deals with low voltage conditions atpower system frequency, which can be caused by:

1. Malfunctioning of a voltage regulator or wrong settings under manual control(symmetrical voltage decrease).

2. Overload (symmetrical voltage decrease).3. Short circuits, often as phase to earth faults (unsymmetrical voltage decrease).

Undervoltage protection prevents sensitive equipment from running under conditionsthat could cause their overheating and thus shorten their life time expectancy. In manycases, it is a useful function in circuits for local or remote automation processes inthe power system.


The parameters for the two-step undervoltage protection function (TUV) are set viathe local HMI or Protection and Control IED Manager (PCM 600).



283

All the voltage conditions in the system where the TUV performs its functions shouldbe considered. The same also applies to the associated equipment, its voltage andtime characteristic.

There is a very wide application area where general undervoltage functions are used.All voltage related settings are made as a percentage of a settable base voltage, whichnormally is set to the primary nominal voltage level (phase-phase) of the powersystem or the high voltage equipment under consideration.

The setting for the TUV function is normally not critical, since there must be enoughtime available for the main protection to clear short-circuits and earth-faults.

Below, some applications and related setting guidelines for the voltage level aregiven:

Equipment protection, such as for motors and generatorsThe setting has to be well below the lowest occurring "normal" voltage and well abovethe lowest acceptable voltage for the equipment.

Disconnected equipment detectionThe setting has to be well below the lowest occurring "normal" voltage and well abovethe highest occurring voltage, caused by inductive or capacitive coupling, when theequipment is disconnected.

Power supply qualityThe setting has to be well below the lowest occurring "normal" voltage and well abovethe lowest acceptable voltage, due to regulation, good practice or other agreements.

Voltage instability mitigationThis setting is very much dependent on the power system characteristics, andthorough studies have to be made to find the suitable levels.

Backup protection for power system faultsThe setting has to be well below the lowest occurring "normal" voltage and well abovethe highest occurring voltage during the fault conditions under consideration.

The following settings can be done for the two step undervoltageprotection.ConnType: Sets whether the measurement shall be phase to earth fundamental value,phase to phase fundamental value, phase to earth RMS value or phase to phase RMSvalue Operation: Off/On

UBase: Base voltage phase to phase in primary kV. This voltage is used as referencefor voltage setting. It can be suitable to set this parameter to the rated primary voltageof the voltage transformer where the current measurement is made. The undervoltageprotection function measures selectively phase to earth voltages, or phase to phasevoltage choosen by the setting ConnType. The function will operate if the voltagegets lover than the set percentage of the set base voltage UBase. This means operationfor phase to earth voltage under:



REG 670

(%) ( )3

U UBase kV< ×

(Equation 144)

and operation for phase to phase voltage under:

U (%) UBase(kV)< ×(Equation 145)

The below described setting parameters are identical for the two steps. Therefore thesetting parameters are described only once.

Characteristicn: This parameter gives the type of time delay to be used. The settingcan be. Definite time/Inverse Curve A/Inverse Curve B/Prog. inv. curve. The choiceis highly dependent of the protection application.

OpModen: This parameter describes how many of the three measured voltages thatshould be below the set level to give operation. The setting can be. 1 out of 3/2 outof 3/3 out of 3. In most applications it is sufficient that one phase voltage is low togive operation. If the function shall be insensitive for single phase to earth faults 2out of 3 can be chosen.

Un<: Set operate undervoltage operation value for step n, given as % of UBase. Thesetting is highly dependent of the protection application. Here it is essential toconsider the minimum voltage at non-faulted situations. Normally this voltage islarger than 90% of nominal voltage.

tn: time delay of step n, given in s. The setting is highly dependent of the protectionapplication. In many applications the protection function shall not directly trip in caseof short circuits or earth faults in the system. The time delay must be co-ordinated tothe short circuit protections.

tResetn: Reset time for step n if definite time delay is used, given in s. The defaultvalue is 25 ms.

tnMin: Minimum operation time for inverse time characteristic for step n, given in s.For very low voltages the undervoltage function, using inverse time characteristic,can give very short operation time. This might lead to unselective trip. By settingt1Min longer than the operation time for other protections such unselective trippingcan be avoided.

ResetTypeCrvn: This parameter can be set: Instantaneous/Frozen time/Linearlydecreased. The default setting is Instantaneous.

tIResetn: Reset time for step n if inverse time delay is used, given in s. The defaultvalue is 25 ms.

kn: Time multiplier for inverse time characteristic. This parameter is used for co-ordination between different inverse time delayed undervoltage protections.



285

ACrvn, BCrvn, CCrvn, DCrvn, PCrvn: Parameters to set to create programmableunder voltage inverse time characteristic. Description of this can be found in the“Technical reference manual”.

CrvSatn: When the denominator in the expression of the programmable curve is equalto zero the time delay will be infinity. There will be an undesired discontinuity.Therefore a tuning parameter CrvSatn is set to compensate for this phenomenon. Inthe voltage interval U> up to U> *(1.0 - CrvSatn/100) the used voltage will be:U>*(1.0 - CrvSatn/100). If the programmable curve is used this parameter must becalculated so that:

0100

CrvSatnB C× - >(Equation 146)

IntBlkSeln: This parameter can be set: Off/Block of trip/Block all. In case of a lowvoltage the undervoltage function can be blocked. This function can be used to preventfunction when the protected object is switched off. If the parameter is set Block oftrip or Block all this unwanted trip is prevented.

IntBlkStValn: Voltage level under which the blocking is activated set in % ofUBase. This setting must be lower than the setting Un<.As switch of shall be detectedthe setting can be very low, i.e. about 10%.

tBlkUVn: Time delay the undervoltage step n when the voltage level is belowIntBlkStValn, given in s. It is important that this delay is shorter than the operate timedelay of the undervoltage protection step.

HystAbsn: Absolute hysteresis set in % of UBase. The setting of this parameter ishighly dependent of the application. If the function is used as control for automaticswitching of reactive compensation devices the hysteresis must be set smaller thanthe voltage change after switching of the compensation device.

HystAbsIntBlkn: Absolute hysteresis of the internal blocking function set in % ofUBase


Table 88: Basic general settings for the UV2PTUV_27 (TUV1-) function

Parameter Range Step Default Unit DescriptionConnType PhN DFT

PhPh RMSPhN RMSPhPh DFT

- PhN DFT - Group selector forconnection type



REG 670

Table 89: Basic parameter group settings for the UV2PTUV_27 (TUV1-) function




OperationStep1 OffOn

- On - Enable execution ofstep 1

Characterist1 Definite timeInverse curve AInverse curve BProg. inv. curve

- Definite time - Selection of timedelay curve type forstep 1

OpMode1 1 out of 32 out of 33 out of 3

- 1 out of 3 - Number of phasesrequired for op (1 of 3,2 of 3, 3 of 3) fromstep 1

U1< 1 - 100 1 70 %UB Voltage setting/startval (DT & IDMT) in %of UBase, step 1



k1 0.05 0.01 0.05 - 1.10 - Time multiplier for theinverse time delay forstep 1

IntBlkSel1 OffBlock of tripBlock all

- Off - Internal (low level)blocking mode, step 1

IntBlkStVal1 1 - 100 1 20 %UB Voltage setting forinternal blocking in %of UBase, step 1

tBlkUV1 0.000 - 60.000 0.001 0.000 s Time delay of internal(low level) blocking forstep 1

HystAbs1 0.0 - 100.0 0.1 0.5 %UB Absolute hysteresis in% of UBase, step 1



Characterist2 Definite timeInverse curve AInverse curve BProg. inv. curve




U2< 1 - 100 1 50 %UB Voltage setting/startval (DT & IDMT) in %of UBase, step 2





287

Parameter Range Step Default Unit Descriptiont2Min 0.000 - 60.000 0.001 5.000 s Minimum operate

time for inversecurves for step 2

k2 0.05 0.01 0.05 - 1.10 - Time multiplier for theinverse time delay forstep 2

IntBlkSel2 OffBlock of tripBlock all

- Off - Internal (low level)blocking mode, step 2

IntBlkStVal2 1 - 100 1 20 %UB Voltage setting forinternal blocking in %of UBase, step 2

tBlkUV2 0.000 - 60.000 0.001 0.000 s Time delay of internal(low level) blocking forstep 2


Table 90: Advanced parameter group settings for the UV2PTUV_27 (TUV1-) function

Parameter Range Step Default Unit DescriptiontReset1 0.000 - 60.000 0.001 0.025 s Reset time delay used

in IEC Definite Timecurve step 1

ResetTypeCrv1 InstantaneousFrozen timerLinearlydecreased


tIReset1 0.000 - 60.000 0.001 0.025 s Time delay in IDMTreset (s), step 1

ACrv1 1.000 0.001 0.005 - 200.000 - Parameter A forcustomerprogrammable curvefor step 1

BCrv1 1.00 0.01 0.50 - 100.00 - Parameter B forcustomerprogrammable curvefor step 1

CCrv1 0.0 0.1 0.0 - 1.0 - Parameter C forcustomerprogrammable curvefor step 1

DCrv1 0.000 0.001 0.000 - 60.000 - Parameter D forcustomerprogrammable curvefor step 1

PCrv1 1.000 0.001 0.000 - 3.000 - Parameter P forcustomerprogrammable curvefor step 1

CrvSat1 0 - 100 1 0 % Tuning param forprog. under voltageIDMT curve, step 1




REG 670






ACrv2 1.000 0.001 0.005 - 200.000 - Parameter A forcustomerprogrammable curvefor step 2

BCrv2 1.00 0.01 0.50 - 100.00 - Parameter B forcustomerprogrammable curvefor step 2

CCrv2 0.0 0.1 0.0 - 1.0 - Parameter C forcustomerprogrammable curvefor step 2

DCrv2 0.000 0.001 0.000 - 60.000 - Parameter D forcustomerprogrammable curvefor step 2

PCrv2 1.000 0.001 0.000 - 3.000 - Parameter P forcustomerprogrammable curvefor step 2

CrvSat2 0 - 100 1 0 % Tuning param forprog. under voltageIDMT curve, step 2

4.8.2 Two step overvoltage protection (PTOV, 59)

Function block name: TOVx- IEC 60617 graphical symbol:

3U>

ANSI number: 59

IEC 61850 logical node name:OV2PTOV

4.8.2.1 Application

The two-step overvoltage protection function (TOV) is applicable in all situations,where reliable detection of high voltage is necessary. The TOV function can also beused for supervision and detection of abnormal conditions, which, in combinationwith other protection functions, increase the security of a complete protection system.



289

High voltage conditions are caused by abnormal situations in the power system. Theovervoltage protection is applied to power system elements, such as generators,transformers, motors and power lines in order to detect high voltage conditions. Theovervoltage protection can be used in combination with low current signals, toidentify a transmission line, open in the remote end. The overvoltage protection isalso used to initiate voltage correction measures, like insertion of shunt reactors, tocompensate for low load, and thereby decreasing the voltage. The function has a highmeasuring accuracy and setting hysteresis to allow applications to control reactiveload.

The overvoltage protection can be used to disconnect, from the network, apparatuses,like electric motors, which will be damaged when subject to service under highvoltage conditions. TOV deals with high voltage conditions at power systemfrequency, which can be caused by:

1. Different kinds of faults, where a too high voltage appears in a certain powersystem, like metallic connection to a higher voltage level (broken conductorfalling down to a crossing overhead line, transformer flash over fault from thehigh voltage winding to the low voltage winding, etc.).

2. Malfunctioning of a voltage regulator or wrong settings under manual control(symmetrical voltage decrease).

3. Low load compared to the reactive power generation (symmetrical voltagedecrease).

4. Earth-faults in high impedance earthed systems causes, beside the high voltagein the neutral, high voltages in the two non-faulted phases, (unsymmetricalvoltage increase).

Overvoltage protection prevents sensitive equipment from running under conditionsthat could cause their overheating or stress of insulation material, and thus shortentheir life time expectancy. In many cases, it is a useful function in circuits for localor remote automation processes in the power system.


The parameters for the two-step overvoltage protection function (TOV) are set viathe local HMI or Protection and Control IED Manager (PCM600).

All the voltage conditions in the system where TOV performs its functions should beconsidered. The same also applies to the associated equipment, its voltage and timecharacteristic.

There is a very wide application area where general overvoltage functions are used.All voltage related settings are made as a percentage of a settable base primaryvoltage, which normally is set to the nominal voltage level (phase-phase) of the powersystem or the high voltage equipment under consideration.

The time delay for the TOV function can sometimes be critical and related to the sizeof the overvoltage - a power system or a high voltage component can withstand



REG 670

smaller overvoltages for some time, but in case of large overvoltages the relatedequipment should be disconnected more rapidly.

Below, some applications and related setting guidelines for the voltage level aregiven:

Equipment protection, such as for motors, generators, reactors andtransformersHigh voltage will cause overexcitation of the core and deteriorate the windinginsulation. The setting has to be well above the highest occurring "normal" voltageand well below the highest acceptable voltage for the equipment.

Equipment protection, capacitorsHigh voltage will deteriorate the dielectricum and the insulation. The setting has tobe well above the highest occurring "normal" voltage and well below the highestacceptable voltage for the capacitor.

Power supply qualityThe setting has to be well above the highest occurring "normal" voltage and belowthe highest acceptable voltage, due to regulation, good practice or other agreements.

High impedance earthedgrounded systemsIn high impedance earthed systems, earth-faults cause a voltage increase in the non-faulty phases. The overvoltage protection can be used to detect such faults. The settinghas to be well above the highest occurring "normal" voltage and well below the lowestoccurring voltage during faults. A metallic single-phase earth-fault causes the non-faulted phase voltages to increase a factor of √3.

The following settings can be done for the two step overvoltageprotectionConnType: Sets whether the measurement shall be phase to earth fundamental value,phase to phase fundamental value, phase to earth RMS value or phase to phase RMSvalue Operation: Off/On

UBase: Base voltage phase to phase in primary kV. This voltage is used as referencefor voltage setting. It can be suitable to set this parameter to the rated primary voltageof the voltage transformer where the current measurement is made. The overvoltageprotection function measures the phase to earth voltages, or phase to phase voltagesas selected. The function will operate if the voltage gets higher than the set percentageof the set base voltage UBase. This means operation for phase to earth voltage over:

(%) ( )3

U UBase kV< ×

(Equation 147)

and operation for phase to phase voltage under:

U (%) UBase(kV)> ×(Equation 148)



291


Characteristicn: This parameter gives the type of time delay to be used. The settingcan be. Definite time/Inverse Curve A/Inverse Curve B/Inverse Curve C/Prog. inv.curve. The choice is highly dependent of the protection application.

OpModen: This parameter describes how many of the three measured voltages thatshould be above the set level to give operation. The setting can be. 1 out of 3/2 out of3/3 out of 3. In most applications it is sufficient that one phase voltage is high to giveoperation. If the function shall be insensitive for single phase to earth faults 1 out of3 can be chosen, because the voltage will normally rise in the non-faulted phases atsingle phase to earth faults.

UnPickup'n': Set operate overvoltage operation value for step n, given as % ofUBase. The setting is highly dependent of the protection application. Here it isessential to consider the Maximum voltage at non-faulted situations. Normally thisvoltage is less than 110% of nominal voltage.

tn: time delay of step n, given in s. The setting is highly dependent of the protectionapplication. In many applications the protection function has the task to preventdamages to the protected object. The speed might be important for example in caseof protection of transformer that might be overexcited. The time delay must be co-ordinated with other automated actions in the system.


tnMin: Minimum operation time for inverse time characteristic for step n, given in s.For very high voltages the overvoltage function, using inverse time characteristic,can give very short operation time. This might lead to unselective trip. By settingt1Min longer than the operation time for other protections such unselective trippingcan be avoided.





CrvSatn: When the denominator in the expression of the programmable curve is equalto zero the time delay will be infinity. There will be an undesired discontinuity.Therefore a tuning parameter CrvSatn is set to compensate for this phenomenon. Inthe voltage interval U> up to U>·(1.0 + CrvSatn/100) the used voltage will be:



REG 670

U>·(1.0 + CrvSatn/100). If the programmable curve is used this parameter must becalculated so that:

0100


HystAbsn: Absolute hysteresis set in % of UBase. The setting of this parameter ishighly dependent of the application. If the function is used as control for automaticswitching of reactive compensation devices the hysteresis must be set smaller thanthe voltage change after switching of the compensation device.


Table 91: Basic general settings for the OV2PTOV_59 (TOV1-) function

Parameter Range Step Default Unit DescriptionConnType PhG

PhPhPhG RMSPhPh RMS

- PhG - TBD

Table 92: Basic parameter group settings for the OV2PTOV_59 (TOV1-) function






Characterist1 Definite timeInverse curve AInverse curve BInverse curve CProg. inv. curve




U1> 1 - 200 1 120 %UB Voltage setting/startval (DT & IDMT) in %of UBase, step 1







293

Parameter Range Step Default Unit DescriptionHystAbs1 0.0 - 100.0 0.1 0.5 %UB Absolute hysteresis in

% of UBase, step 1







U2> 1 - 200 1 150 %UB Voltage setting/startval (DT & IDMT) in %of UBase, step 2





Table 93: Advanced parameter group settings for the OV2PTOV_59 (TOV1-) function






ACrv1 0.005 - 200.000 0.001 1.000 - Parameter A forcustomerprogrammable curvefor step 1

BCrv1 0.50 - 100.00 0.01 1.00 - Parameter B forcustomerprogrammable curvefor step 1

CCrv1 0.0 - 1.0 0.1 0.0 - Parameter C forcustomerprogrammable curvefor step 1




REG 670

Parameter Range Step Default Unit DescriptionDCrv1 0.000 - 60.000 0.001 0.000 - Parameter D for


PCrv1 0.000 - 3.000 0.001 1.000 - Parameter P forcustomerprogrammable curvefor step 1

CrvSat1 0 - 100 1 0 % Tuning param forprog. over voltageIDMT curve, step 1








DCrv2 0.000 - 60.000 0.001 0.000 - Parameter D forcustomerprogrammable curvefor step 2



4.8.3 Two step residual overvoltage protection (PTOV, 59N)

Function block name: TRVx- IEC 60617 graphical symbol:

3U0ANSI number: 59N

IEC 61850 logical node name:ROV2PTOV



295

4.8.3.1 Application

The two-step residual overvoltage protection function (TRV) is primarily used in highimpedance earthed distribution networks, mainly as a backup for the primary earth-fault protection of the feeders and the transformer. To increase the security fordifferent earth-fault related functions, the residual overvoltage signal can be used asa release signal. The residual voltage can be measured either at the transformer neutralor from a voltage transformer open delta connection. The residual voltage can alsobe calculated internally, based on measurement of the three phase-voltages.

In high impedanceearthed systems the system neutral voltage, i.e. the residual voltage,will increase in case of any fault connected to earth. Depending on the type of faultand fault resistance the residual voltage will reach different values. The highestresidual voltage, equal to the phase-earth voltage, is achieved for a single phase-earth fault. The residual voltage will increase approximately the same amount in thewhole system and does not provide any guidance in finding the faulted component.Therefore TRV is often used as a backup protection or as a release signal for the feederearth-fault protection.


The parameters for the two-step residual overvoltage protection function (TRV) areset via the local HMI or Protection and Control IED Manager (PCM 600).

All the voltage conditions in the system where the TRV performs its functions shouldbe considered. The same also applies to the associated equipment, its voltage andtime characteristic.

There is a very wide application area where general single input or residualovervoltage functions are used. All voltage related settings are made as a percentageof a settable base voltage, which can be set to the primary nominal voltage (phase-phase) level of the power system or the high voltage equipment under consideration.

The time delay for the TRV function are seldom critical, since residual voltage isrelated to earth-faults in a high impedance earthed system, and enough time mustnormally be give single input for the primary protection to clear the fault. In somemore specific situations, where the single overvoltage protection is used to protectsome specific equipment the time delay can be shorter.

Below, some applications and related setting guidelines for the residual voltage levelare given.

Equipment protection, such as for motors, generators, reactors andtransformersHigh residual voltage indicates earth fault in the system, perhaps in the componentto which the residual overvoltage function is connected. After some time delay, togive the primary protection for the faulted device a chance to trip, the residual voltageprotection has to trip the component. The setting has to be well above the highest



REG 670

occurring "normal" residual voltage and well below the highest acceptable residualvoltage for the equipment

Equipment protection, capacitorsHigh voltage will deteriorate the dielectricum and the insulation. The residualovervoltage protection has to be connected to a neutral or open delta winding. Thesetting has to be well above the highest occurring "normal" residual voltage and wellbelow the highest acceptable residual voltage for the capacitor.

Power supply qualityThe setting has to be well above the highest occurring "normal" residual voltage andbelow the highest acceptable residual voltage, due to regulation, good practice orother agreements.

High impedance earthedgrounded systemsIn high impedance earthed systems, earth-faults cause a neutral voltage in the feedingtransformer neutral. The residual overvoltage protection can be used to trip thetransformer, as a backup protection for the feeder earth fault protection, and of courseas a backup for the transformer primary earth-fault protection. The setting has to bewell above the highest occurring "normal" residual voltage, and well below the lowestoccurring residual voltage during the faults under consideration. A metallic single-phase earth-fault causes a transformer neutral to reach a voltage equal to the normalphase-earth voltage.

The voltage transformers measuring the phase to earth voltages will then measurezero voltage in the faulty phase. The two healthy phases will measure full phase tophase voltage, as the earth is available on the faulty phase and the neutral has a fullphase to earth voltage. The residual overvoltage will be three time the phase to earthvoltage. See figure "".



297

Figure 119: Non-effectively earthed systems

Direct earthed systemsIn direct earthed systems an earth fault on one phase will mean a voltage collapse inthat phase. The two healthy phases will to earth have normal phase to earth voltages.The residual sum will have the same value as phase to earth voltage. See figure120 .



REG 670

Figure 120: Direct earthed system

The following settings can be done for the two step residual overvoltageprotectionOperation: Off/On

UBase: This voltage is used as reference for the voltage setting. We have differentpossibilities to feed the IED for this protection function.

1.The IED is fed from a normal voltage transformer group where the residual voltageis created from the phase to earth voltages within the protection software. The settingof the analogue input is given as:

Set UBase = Uph - (ph*√3)

Set UBase = Uph - (ph/3)

2.The IED is fed from a broken delta connection normal voltage transformer group.In a open delta connection the protection is fed by the voltage 3U0 (single input). Thesetting of the analogue input is given as the ratio of the voltage transformer e.g 230/√3/110 or 20/√3 /(110/3).

3.The IED is fed from a single voltage transformer connected to the neutral point ofa power transformer in the power system. In this connection the protection is fed bythe voltage UN (single input). The setting of the analogue input is given as primaryphase to earth voltage and secondary phase to earth voltage. The protection functionwill measure the residual voltage corresponding nominal phase to earth voltage. Themeasurement will be based on the neutral voltage displacement.



299


Characteristicn: This parameter gives the type of time delay to be used. The settingcan be. Definite time/Inverse Curve A/Inverse Curve B/Inverse Curve C/Prog. inv.curve. The choice is highly dependent of the protection application.

Un>: Set operate overvoltage operation value for step n, given as % of residualvoltage corresponding to UBase:

U > (%)*UBase(kV)

The setting is dependent of the required sensitivity of the protection and the systemearthing. In non-effectively earthed systems the residual voltage can be maximumthe rated phase to earth voltage, which should correspond to 100%.

In effectively earthed systems this value is dependent of the ratio Z0/Z1. The requiredsetting to detect high resistive earth faults must be based on network calculations.

tn: time delay of step n, given in s. The setting is highly dependent of the protectionapplication. In many applications the protection function has the task to preventdamages to the protected object. The speed might be important for example in caseof protection of transformer that might be overexcited. The time delay must be co-ordinated with other automated actions in the system.


tnMin: Minimum operation time for inverse time characteristic for step n, given in s.For very high voltages the overvoltage function, using inverse time characteristic,can give very short operation time. This might lead to unselective trip. By settingt1Min longer than the operation time for other protections such unselective trippingcan be avoided.





CrvSatn: When the denominator in the expression of the programmable curve is equalto zero the time delay will be infinity. There will be an undesired discontinuity.Therefore a tuning parameter CrvSatn is set to compensate for this phenomenon. Inthe voltage interval U> up to U>·(1.0 + CrvSatn/100) the used voltage will be:



REG 670

U>·(1.0 + CrvSatn/100). If the programmable curve is used this parameter must becalculated so that:

0100


HystAbsn: Absolute hysteresis set in % of UBase. The setting of this parameter ishighly dependent of the application.


Table 94: Basic parameter group settings for the ROV2PTOV_59N (TRV1-) function








U1> 1 - 200 1 30 %UB Voltage setting/startval (DT & IDMT), step1 in % of UBase









U2> 1 - 100 1 45 %UB Voltage setting/startval (DT & IDMT), step2 in % of UBase





301

Parameter Range Step Default Unit Descriptiont2Min 0.000 - 60.000 0.001 5.000 s Minimum operate

time for inversecurves for step 2



Table 95: Advanced parameter group settings for the ROV2PTOV_59N (TRV1-) function












tReset2 0.000 - 60.000 0.001 0.025 s Time delay in DTreset (s), step 2







REG 670

Parameter Range Step Default Unit DescriptionACrv2 0.005 - 200.000 0.001 1.000 - Parameter A for







4.8.4 Overexcitation protection (PVPH, 24)

Function block name: OEXx- IEC 60617 graphical symbol:

U/f >

ANSI number: 24

IEC 61850 logical node name:OEXPVPH

4.8.4.1 Application

When the laminated core of a power transformer is subjected to a magnetic fluxdensity beyond its design limits, stray flux will flow into non-laminated componentsnot designed to carry flux and cause eddy currents to flow. The eddy currents cancause excessive heating and severe damage to insulation and adjacent parts in arelatively short time.

Overvoltage, or underfrequency, or a combination of both, will result in an excessiveflux density level, which is denominated overfluxing or over-excitation.

The greatest risk for overexcitation exists in a thermal power station when thegenerator-transformer block is disconnected from the rest of the network, or innetwork “islands”occuring at disturbance where high voltages and/or low frequenciescan occur. Overexcitation can occur during start-up and shut-down of the generator



303

if the field current is not properly adjusted. Loss-of load or load-shedding can alsoresult in overexcitation if the voltage control and frequency governor is notfunctioning properly. Loss of load or load-shedding at a transformer substation canresult in overexcitation if the voltage control function is insufficient or out oforder.Low frequency in a system isolated from the main network can result inoverexcitation if the voltage regulating system maintains normal voltage.

According to the IEC standards, the power transformers shall be capable of deliveringrated load current continuously at an applied voltage of 105% of rated value (at ratedfrequency). For special cases, the purchaser may specify that the transformer shall becapable of operating continuously at an applied voltage 110% of rated value at noload, reduced to 105% at rated secondary load current.

According to ANSI/IEEE standards, the transformers shall be capable of deliveringrated load current continuously at an output voltage of 105% of rated value (at ratedfrequency) and operate continuously with output voltage equal to 110% of rated valueat no load.

The capability of a transformer (or generator) to withstand overexcitation can beillustrated in the form of a thermal capability curve, i.e. a diagram which shows thepermissible time as a function of the level of over-excitation. When the transformeris loaded, the induced voltage and hence the flux density in the core can not be readoff directly from the transformer terminal voltage. Normally, the leakage reactanceof each separate winding is not known and the flux density in the transformer corecan then not be calculated. In two-winding transformers, the low voltage winding isnormally located close to the core and the voltage across this winding reflects the fluxdensity in the core. However, depending on the design, the flux flowing in the yokemay be critical for the ability of the transformer to handle excess flux. The OEXfunction has currents inputs to allow calculation of the load influence when theleakage reactance, of the winding where the OEX function is connected, is known.This gives a more exact measurement of the magnetizing flow. For powertransformers with unidirectional load flow, the voltage to the V/Hz protectionfunction should therefore be taken from the feeder side.

Heat accumulated in critical parts during a period of overexcitation will be reducedgradually when the excitation retains the normal value. If a new period ofoverexcitation occurs after a short time interval, the heating will start from a higherlevel. The overexcitation protection function should therefore have a thermalmemory. In RET670, the cooling time constant is settable within a wide range.

The general experience is that the overexcitation characteristics for a number of powertransformers are not in accordance with standard inverse time curves. In order to makeoptimal settings possible, a transformer adapted characteristic is available in RET670.The operate characteristic of the protection function can be set to correspond quitewell with any characteristic by setting the operate time for six different figures ofoverexcitation in the range from 100% to 180% of rated V/Hz.

The V/Hz function can be configured to any single-phase (phase-phase) or three-phase voltage input and any one or thee-phase current input. It uses the fundamentalfrequency component of current and voltages.



REG 670

When configured to a single phase-to-phase voltage input, a single-phase current iscalculated which has the same phase angle relative the phase-to-phase voltage as thephase currents have relative the phase voltages in a symmetrical system. The functionshould preferable be configured to use a three-phase voltage input if available. It thenuses the positive sequence quantities of voltages and currents.

Analog measurements must not be taken from any winding whereOLTC is located.

Some different connection alternatives are shown in figure 121.

G

U/f>

24

U/f>

24

U/f>

24

en05000208.vsd

Figure 121: Alternative connections of an overexcitation (Volt/Hertz) function


Setting and configurationThe signals are configured by use of the CAP configuration tool and the SignalMatrixtool forming part of the PCM 600 tool.

The setting parameters for the Overexcitation function are set at the local HMI(Human Machine Interface) or by use of the PST (Parameter Setting Tool) formingpart of PCM 600 tool installed on a PC connected to the control or protection unit.Please refer to the Technical reference manual (TRM) for a list of setting parameters.

Recommendations for Input signalsPlease see the default factory configuration for examples of configuration!

BLOCK: The input will block the operation of the Overexcitation function. Can beused e.g. to for a limited time block the operation during special service conditions.



305

RESET: The function has a thermal memory which can take very long time to reset.Activation of the reset input will reset the function

Recommendations for Output signalsPlease see the default factory configuration for examples of configuration!

ERROR: The output indicates a measuring error. The reason can e.g. be configurationproblems where analogue signals are missing.

START: The start output indicates that the level U/f> has been reached. It can beused to initiate time measurement.

TRIP: The trip output is activated after the operate time for the U/f level which hasbeen reached. The output signal is used to trip the circuit breaker.

ALARM: The output is activated when alarm level has been reached and the alarmtimer has elapsed. The output is used to give alarm to operator that the system voltageis high.

Setting parametersOperation: The operation of the Overexcitation function can be switched On-Off.

UBase: The UBase setting is the setting of the base (per unit) voltage on which allpercentage settings are based. The setting is normally the system voltage level.

IBase: The IBase setting is the setting of the base (per unit) current on which allpercentage settings are based. Normally the power transformer rated current is usedbut alternatively the current transformer rated current can be set.

MeasuredU: The phases involved in the measurement are set here. Normally the threephase measurement measuring the positive sequence voltage should be used but whenonly individual VT"s are used a single phase to phase can be used.

MeasuredI: The phases involved in the measurement are set here. MeasuredI mustbe in accordance with MeasuredU.

V/Hz>: Operating level for the inverse characteristic, IEEE or tailor made. Theoperation is based on the relation between rated voltage and rated frequency and setas a percentage factor. Normal setting is around 108-110% depending of the capabilitycurve for the transformer.

V/Hz>>: Operating level for the tMin definite time delay used at high overvoltages.The operation is based on the relation between rated voltage and rated frequency andset as a percentage factor. Normal setting is around 150-180% depending of thecapability curve for the transformer. Setting should be above the knee-point when thecharacteristic starts to be straight on the high side.

XLeak: The transformer leakage reactance on which the compensation of voltagemeasurement with load current is based. The setting shall be the transformer leakreactance in primary ohms. If no current compensation is used (mostly the case) thesetting is not used.



REG 670

TripPulse: The length of the trip pulse. Normally the final trip pulse is decided by thetrip function block. A typical pulse length can be 50 ms.

CurveType: Selection of the curve type for the inverse delay. The IEEE curves ortailor made curve can be selected depending of which one matches the capabilitycurve best.

kforIEEE: The time constant for the inverse characteristic. Select the one giving thebest match to the transformer capability.

tCooling: The cooling time constant giving the reset time when voltages drops belowthe set value. Shall be set above the cooling time constant of the transformer. If theconstant is not known set a high value to overprotect.

tMin: The operating times at voltages higher than the set U/f>>. The setting shallmatch capabilities on these high voltages. Typical setting can be 1-10 second.

tMax: For overvoltages close to the set value times can be extremely long if a highK time constant is used. A maximum time can then be set to cut the longest times.Typical settings are 1800-3600 seconds (30-60 minutes)

AlarmLevel: Setting of the alarm level in percentage of the set trip level. The alarmlevel is normally set at around 98% of the trip level.

tAlarm: Setting of the time to alarm is given from when the alarm level has beenreached. Typical setting is 5 seconds.

Service value reportA number of internal parameters are available as service values for use atcommissioning and during service. Remaining time to trip (in seconds) TMTOTRIP,flux density VPERHZ, internal thermal content in percentage of trip valueTHERMSTA. The values are available at Local HMI, Substation SAsystem and PCM600.

Setting exampleSufficient information about the overexcitation capability of the protected object(s)must be available when making the settings. The most complete information is givenin an overexcitation capability diagram as shown in figure 122.

The settings V/Hz>> and V/Hz> are made in per unit of the rated voltage of thetransformer winding at rated frequency.

Set the transformer adapted curve for a transformer with overexcitation characteristicsin according to figure 122.

V/Hz> for the protection is set equal to the permissible continuos overexcitationaccording to figure 122 = 105%. When the overexcitation is equal to V/Hz>, trippingis obtained after a time equal to the setting of t1.



307

This is the case when UBase is equal to the transformer rated voltages.For other values, the percentage settings need to be adjustedaccordingly.

When the overexcitation is equal to the set value of V/Hz>>, tripping is obtained aftera time equal to the setting of t6. A suitable setting would be V/Hz>> = 140% and t6= 4 s.

The interval between V/Hz>> and V/Hz> is automatically divided up in five equalsteps, and the time delays t2 to t5 will be allocated to these values of overexcitation.In this example, each step will be (140-105) /5 = 7%. The setting of time delays t1 tot6 ar listed in table 96.

Table 96: Settings

U/f op (%) Timer Time set (s)105 t1 7200 (max)

112 t2 600

119 t3 60

126 t4 20

133 t5 8

140 t6 4

Information on the cooling time constant Tcool should be retrieved from the powertransformer manufacturer.



REG 670

1 2 5 50 200

110

120

130

140

150

1000.05 0.1 0.2 0.5 10 20 100

V/Hz%

Continous

Time(minutes)

t6 t5 t4 t3 t2 t1

transformer capability curverelay operate characteristic

en01000377.vsd

Figure 122: Example on overexcitation capability curve and V/Hz protectionsettings for power transformer


Table 97: Basic general settings for the OEXPVPH_24 (OEX1-) function

Parameter Range Step Default Unit DescriptionMeasuredU PosSeq

L1L2L2L3L3L1

- L1L2 - Selection ofmeasured voltage

MeasuredI L1L2L2L3L3L1PosSeq

- L1L2 - Selection ofmeasured current



309

Table 98: Basic parameter group settings for the OEXPVPH_24 (OEX1-) function



IBase 1 - 99999 1 3000 A Base current (ratedphase current) in A

UBase 0.05 - 2000.00 0.05 400.00 kV Base voltage (mainvoltage) in kV

V/Hz> 100.0 - 180.0 0.1 110.0 %UB/f Operate level of V/Hzat no load and ratedfreq in % of (Ubase/frated)

V/Hz>> 100.0 - 200.0 0.1 140.0 %UB/f High level of V/Hzabove which tMin isused, in % of (Ubase/frated)

XLeak 0.000 - 200.000 0.001 0.000 ohm Winding leakagereactance in primaryohms

TrPulse 0.000 - 60.000 0.001 0.100 s Length of the pulse fortrip signal (in sec)

tMin 0.000 - 60.000 0.001 7.000 s Minimum trip delay forV/Hz inverse curve, insec

tMax 0.00 - 9000.00 0.01 1800.00 s Maximum trip delayfor V/Hz inversecurve, in sec

tCooling 0.10 - 9000.00 0.01 1200.00 s Transformermagnetic core coolingtime constant, in sec

CurveType IEEETailor made

- IEEE - Inverse time curveselection, IEEE/Tailormade

kForIEEE 1 - 60 1 1 - Time multiplier forIEEE inverse typecurve

AlarmLevel 50.0 - 120.0 0.1 100.0 % Alarm operate levelas % of operate level

tAlarm 0.00 - 9000.00 0.01 5.00 s Alarm time delay, insec

Table 99: Advanced parameter group settings for the OEXPVPH_24 (OEX1-) function

Parameter Range Step Default Unit Descriptiont1Tailor 0.00 - 9000.00 0.01 7200.00 s Time delay t1

(longest) for tailormade curve, in sec

t2Tailor 0.00 - 9000.00 0.01 3600.00 s Time delay t2 for tailormade curve, in sec





REG 670

Parameter Range Step Default Unit Descriptiont4Tailor 0.00 - 9000.00 0.01 900.00 s Time delay t4 for tailor

made curve, in sec


t6Tailor 0.00 - 9000.00 0.01 225.00 s Time delay t6(shortest) for tailormade curve, in sec

4.8.5 Voltage differential protection (PTOV, 60)

Function block name: VDC IEC 60617 graphical symbol:

ANSI number: 60

IEC 61850 logical node name:VDCPTOV

4.8.5.1 Application

The voltage differential functions can be used in some different applications.

• Voltage unbalance protection for capacitor banks. The voltage on the bus issupervised with the voltage in the capacitor bank, phase- by phase. Differenceindicates a fault, either short-circuited or open element in the capacitor bank. Itis mainly used on elements with external fuses but can also be used on elementswith internal fuses instead of a current unbalance protection measuring thecurrent between the neutrals of two half’s of the capacitor bank. The function



311

requires voltage transformers in all phases of the capacitor bank. Figure 123shows some different alternative connections of this function.

Ud>L1

Ph L2Ph L3

U1

U2

Ud>L1

Ph L2Ph L3

U1 U2

Ph L3 Ph L2

en06000390.vsd

Single grounded wye

Double wye

Figure 123: Connection of voltage differential function to detect unbalance incapacitor banks (one phase only is shown)

The function has a block input (BLOCK) where a fuse failure supervision (or MCBtripped) can be connected to prevent problems if one fuse in the capacitor bank voltagetransformer set has opened and not the other (capacitor voltage is connected to inputU2). It will also ensure that a fuse failure alarm is given instead of a Undervoltage orDifferential voltage alarm and/or tripping.

• Fuse supervision function for voltage transformers. In many application thevoltages of two fuse groups of the same voltage transformer or fuse groups oftwo separate voltage transformers measuring the same voltage can be supervisedwith this function. It will be an alternative for e.g. generator units where oftentwo voltage transformers are supplied for measurement and excitationequipment.

The application to supervise the voltage on two voltage transformers in the generatorcircuit is shown in figure 124.



REG 670

Ud>U1

U2

To Protection

To Excitation

Gen en06000389.vsd

Figure 124: Supervision of fuses on generator circuit voltage transformers


The parameters for the voltage differential function are set via the local HMI orProtection and Control Manager software PCM600.

The following settings are done for the voltage differential function.

Operation: Off/On

UBase: Base voltage level in kV. The base voltage is used as reference for the voltagesetting factors. Normally it is set to the system voltage level.

BlkDiffAtULow: The setting is to block the function when the voltages in the phasesare low.

RFLx: Is the setting of the voltage ratio compensation factor where possibledifferences between the voltages is compensated for. The differences can be due todifferent voltage transformer ratios, different voltage levels e.g. the voltagemeasurement inside the capacitor bank can have a different voltage level but thedifference can also e.g. be used by voltage drop in the secondary circuits. The settingis normally done at site by evaluating the differential voltage achieved as a servicevalue for each phase. The factor is defined as U2*RFLx and shall be equal to theU1 voltage. Each phase has its own ratio factor.



313

UDTrip: The voltage differential level required for tripping is set with this parameter.For application on capacitor banks the setting will depend of the capacitor bankvoltage and the number of elements per phase in series and parallel. Capacitor banksmust be tripped before excessive voltage occurs on the healthy capacitor elements.The setting values required are normally given by the capacitor bank supplier. Forother applications it has to be decided case by case. For fuse supervision normallyonly the alarm level is used.

tTrip: The time delay for tripping is set by this parameter. Normally the delay doesnot need to be so short in capacitor bank applications as there is no fault requiringurgent tripping.

tReset: The time delay for reset of tripping level element is set by this parameter.Normally it can be set to a short delay as faults are permanent when they occur.

For the advanced users following parameters are also available for setting. Defaultvalues are here expected to be acceptable.

U1Low: The setting of the undervoltage level for the first voltage input is decided bythis parameter. The proposed default setting is 70%.

U2Low: The setting of the undervoltage level for the second voltage input is decidedby this parameter. The proposed default setting is 70%.

tBlock: The time delay for blocking of the function at detected undervoltages is setby this parameter.

UDAlarm: The voltage differential level required for alarm is set with this parameter.For application on capacitor banks the setting will depend of the capacitor bankvoltage and the number of elements per phase in series and parallel. Normally valuesrequired are given by capacitor bank supplier.

For fuse supervision normally only this alarm level is used and a suitable voltagelevel is 3-5% if the ratio correction factor has been properly evaluated duringcommissioning.

For other applications it has to be decided case by case.

tAlarm: The time delay for alarm is set by this parameter. Normally some secondsdelay can be used on capacitor banks alarm. For fuse failure supervision the alarmdelay can be set to zero.




REG 670

Table 100: Basic parameter group settings for the VDCPTOV_60 (VDC1-) function




BlkDiffAtULow NoYes

- Yes - Block operation at lowvoltage

UDTrip 0.0 - 100.0 0.1 5.0 %UB Operate level, in % ofUBase

tTrip 0.000 - 60.000 0.001 1.000 s Time delay for voltagedifferential operate, inmilliseconds

tReset 0.000 - 60.000 0.001 0.000 s Time delay for voltagedifferential reset, inseconds

U1Low 0.0 - 100.0 0.1 70.0 %UB Input 1 undervoltagelevel, in % of UBase

U2Low 0.0 - 100.0 0.1 70.0 %UB Input 2 undervoltagelevel, in % of UBase

tBlock 0.000 - 60.000 0.001 0.000 s Reset time forundervoltage block

UDAlarm 0.0 - 100.0 0.1 2.0 %UB Alarm level, in % ofUBase

tAlarm 0.000 - 60.000 0.001 2.000 s Time delay for voltagedifferential alarm, inseconds

Table 101: Advanced parameter group settings for the VDCPTOV_60 (VDC1-) function

Parameter Range Step Default Unit DescriptionRFL1 0.000 - 3.000 0.001 1.000 - Ratio compensation

factor phase L1UCap*RFL1=UL1Bus

RFL2 0.000 - 3.000 0.001 1.000 - Ratio compensationfactor phase L2UCap*RFL2=UL2Bus

RFL3 0.000 - 3.000 0.001 1.000 - Ratio compensationfactor phase L3UCap*RFL3=UL3Bus

4.8.6 95% and 100% Stator earthground fault protection based on3rd harmonic


UN> / U0d(3rd harm)

ANSI number: 64S




315

4.8.6.1 Application

Stator earth fault is a fault type having relatively high fault rate. Medium and largegenerators normally have high impedance earth, i.e. earthing via a neutral pointresistor. This resistor is dimensioned to give an earth fault current in the range 5 – 15A at a solid earth fault directly at the generator high voltage terminal. The relativelysmall earth fault currents give much less thermal and mechanical stress on thegenerator, compared to the short circuit case. Anyhow, the earth faults in the generatorhave to be detected and the generator has to be tripped, even if longer fault time,compared to short circuits, can be allowed.

The relation between the amplitude of the generator earth fault current and the faulttime, with defined consequence, is shown in figure 125.

en06000316.vsd

Negligible burning area

Figure 125: Relation between the amplitude of the generator earth fault currentand the fault time



REG 670

As mentioned earlier, for medium and large generators, the normal procedure is tohave high impedance earthing of generating units. The most common earthing systemis to use a neutral point resistor, giving an earth fault current in the range 5 – 15 A ata non-resistive earth fault at the high voltage side of the generator. Other types ofsystem earthing of generator units, such as direct earthing and isolated neutral, areused but are quite rare.

In normal non-faulted operation of the generating unit the neutral point voltage isclose to zero, and there is no zero sequence current flow in the generator. When aphase-to-earth fault occurs the neutral point voltage will increase and there will be acurrent flow from the neutral point resistor.

To detect an earth fault on the windings of a generating unit one may use a neutralpoint overvoltage relay, a neutral point overcurrent relay, a zero sequence overvoltagerelay or a residual differential protection. These protection schemes are simple andhave served well during many years. However, at best these simple schemes protectonly 95% of the stator winding. They leave 5% at the neutral end unprotected. Underunfavorable conditions the blind zone may extend to 20% from the neutral. Somedifferent earth fault protection solutions are shown in figure 126 and figure 127.

Generator unit transformer

- UN +en06000317.vsd

Figure 126: Broken delta voltage transformer measurement of neutral pointvoltage



317


en06000318.vsd

- UN +

Figure 127: Neutral point voltage transformer measurement of neutral pointvoltage

In some applications the neutral point resistor is connected to the low voltage side ofa single-phase transformer, connected to the generator neutral point. In such a casethe voltage measurement can be made directly across the neutral point resistor.


en06000319.vsd

IN

Figure 128: Neutral point current measurement

In some power plants the connection of the neutral point resistor is made to thegenerator unit transformer neutral point. This is often done if several generators areconnected to the same bus. The detection of earth fault can be made by currentmeasurement as shown in figure 129.



REG 670


en06000320.vsd

IN = IL1 + IL2 + IL3

Figure 129: Residual current measurement

One difficulty with this solution is that the current transformer ratio is normally solarge so that the secondary residual current will be very small. The false residualcurrent, due to difference between the three phase current transformers, can be in thesame range as the secondary earth fault current.

As indicated above there will be very small neutral voltage or residual current if thestator earth fault is situated close to the generator neutral. The probability for thisfault is quite small but not zero. For small generators the risk of not detecting thestator earth fault, close to the neutral, can be accepted. For large generator it ishowever often a requirement that also theses faults have to be detected. Therefore aspecial neutral end earth fault protection (100% stator earth fault protection) isrequired. The 100% earth fault protection can be realized in different ways. The twomain principles are:

• 3rd harmonic voltage detection• Neutral point voltage injection

The 3rd harmonic voltage detection is based on the fact that the generator will generatesome degree of 3rd harmonic voltage. For the voltage with a frequency to be a factor3 times the fundamental, the voltage has the same phase angle in the three phases.This means that there will be a residual 3rd harmonic voltage in the generator neutralduring normal operation. This component is used for detection of earth faults in thegenerator, close to the neutral.

If the 3rd harmonic voltage, generated in the generator, is very small (less than about1% of the fundamental frequency voltage, the 3rd harmonic based protection cannotbe used. In this case a protection based on neutral point voltage injection is used. Thebasic principle of this protection is that the injected voltage has a characteristicdifferent from the fundamental frequency voltage of the generator. The injectedvoltage can be sinusoidal with a frequency different from the fundamental or it can



319

have another waveform. In non-faulted conditions there will be no current related tothe injected voltage. In case of a stator earth fault a current related to the injectedvoltage will be detected.

In this protection function, available in REG 670, a 3rd harmonic residual voltagedifferential principle is used.


The 3rd harmonic based 100% stator earth fault protection is using the 3rd harmonicvoltage generated by the generator itself. To assure reliable function of the protectionit is necessary that the 3rd harmonic voltage generation is at least 1% of the generatorrated voltage.

Operation: The parameter Operation is used to set the function On/Off.

GenRatedVoltage: GenRatedVoltage is set to the rated phase to phase voltage in kVof the generator.

TVoltType: The protection function is always fed from a voltage transformer in thegenerator neutral. TVoltType defines how the protection function is fed from voltagetransformers at the high voltage side of the generator. The setting alternatives are:

• NoVoltageAvailable which is used when there are no voltage transformersconnected to the generator terminals. In this case the protection will operate asa 3rd harmonic undervoltage protection.

• OpenDeltaVoltage which is used if the protection is fed from an open deltaconnected three-phase group of voltage transformers connected to the generatorterminals. This is the recommended alternative.

• ResidualVoltage3U0 is used when the protection is fed from the three phasevoltage transformers. The third harmonic residual voltage is derived internallyfrom the phase voltages.

• OneSinglePhaseVoltage, L1 L2 or L3, is used when there is only one phasevoltage transformer available at the generator terminals.

The setting beta gives the proportion of the 3rd harmonic voltage in the neutral pointof the generator to be used as restrain quantity. Beta must be set so that there is norisk of trip during normal, non-faulted, operation of the generator. On the other hand,if beta is set high, this will limit the portion of the stator winding covered by theprotection. The default setting 1.0 will in most cases give acceptable conditions. Onepossibility to assure best performance is to make measurements during normaloperation of the generator. From the function the following quantities are available:

• UT3, the 3rd harmonic voltage at the generator terminal side• UN3, the 3rd harmonic voltage at the generator neutral side• E3, the induced 3rd harmonic voltage• ANGLE, the phase angle between UT3 and UN3• DU3, the differential voltage caused by UT3 and UN3 (|UT3 + UN3|)• BU3, the bias voltage (beta · UN3)



REG 670

For different operation points (P and Q) of the generator the differential voltageDU3 can be compared to the bias BU3, and a suitable factor beta can be chosen toassure security.

CBexists: CBexists is set to YES if there is a generator breaker (breaker between thegenerator and the block transformer). In such a case the setting of factorCBopen isactivated.

factorCBopen: The setting factorCBopen gives a constant to be multiplied to beta ifthe generator circuit breaker is open.

UN3rdLimit: The setting UN3rdLimit gives the undervoltage operation level if thevoltage measurement is only made in the generator neutral point. In all otherconnection alternatives this setting is not active. The setting is given as % of the ratedphase-to-earth voltage. The setting should be based on neutral point 3rd harmonicvoltage measurement at normal operation.

UNFundLimit: UNFundLimit gives the operation level for the fundamental frequencyresidual voltage stator earth fault protection. The setting is given as % of the ratedphase-to-earth voltage. A normal setting is in the range 5 – 10%.

UT3BlkLevel: UT3BlkLevel gives a voltage level for the 3rd harmonic voltage levelat the terminal side. If this level is lower than the setting the function is blocked. Thesetting is given as % of the rated phase-to-earth voltage. The setting is typically 1 %.

Delay3rd: Delay3rd gives the trip delay of the 3rd harmonic stator earth faultprotection. The setting is given in s. Normally a relatively long delay (about 10 s) isacceptable as the earth fault current is small.

DelayUNFund: DelayUNFund gives the trip delay of the fundamental frequencyresidual voltage stator earth fault protection. The setting is given in s. A delay in therange 0.5 – 2 s is acceptable.


Table 102: Basic general settings for the STEFPHIZ_59THD (STE1-) function

Parameter Range Step Default Unit DescriptionGenRatedVolt 1.0 - 100.0 0.1 10.0 kV Generator rated

(nominal) phase-to-phase voltage in kV

TVoltType NoVoltageResidualVoltageAllThreePhasesPhaseL1PhaseL2PhaseL3

- ResidualVoltage - Used connection typefor gen. terminalvoltage transformer



321

Table 103: Basic parameter group settings for the STEFPHIZ_59THD (STE1-) function



Beta 0.50 - 10.00 0.01 1.00 - Portion ofvoltN3rdHarmonicused as bias

CBexists NoYes

- No - Defines if generatorCB exists (betweenGen & Transformer)

FactorCBopen 1.00 - 10.00 0.01 1.00 - Beta is multiplied bythis factor when CB isopen

UN3rdH< 0.5 - 10.0 0.1 2.0 % Pickup 3rd Harm U<protection (whenactivated) % of UB/1,732

UT3BlkLevel 0.1 - 10.0 0.1 1.0 % If UT3 is below limit3rdH Diff is blocked,in % of UB/1,732

UNFund> 1.0 - 50.0 0.1 5.0 % Pickup fundamentalUN> protection (95%SEF), % of UB/1,732

t3rdH 0.020 - 60.000 0.001 1.000 s Operation delay of 3rdharm-basedprotection (100%SEF) in s

tUNFund 0.020 - 60.000 0.001 0.500 s Operation delay offundamental UN>protection (95% SEF)in s

4.8.7 Rotor earthground fault protection


IN> Rotor

ANSI number: 64R



Rotor earthground faultThe COMBIFLEX injection unit RXTTE4 is used for injection of an AC voltage tothe generator rotor winding. From RXTTE4 the measured injected current isconnected to an analog current input of REG 670 and the injected voltage is connectedto an analog voltage input of REG 670. Due to quite low level of injected currentsignal 1 A rated CT input into REG 670 must be used for this protection. Forapplications where 5 A rated CTs are used for other protection functions one mixed



REG 670

TRM with 1 A and 5 A CT inputs shall be ordered. For this current input a ratedprimary and secondary current shall be set. The primary rated CT current is set to1000 A and the secondary rated CT current should be set to 1 A. By doing so thedisplayed primary current under service value will correspond to mA value of theinjected current into field winding. Parameter CTearthing shall be set to the defaultvalue ToObject. The voltage input is taken directly from the 120 V voltage tap thatis fed to RXTTE4 as shown in figure 130. The primary rated VT voltage is set to 100kV and the secondary rated VT voltage is set to 100 V. By doing so the displayedprimary voltage under service value will correspond to the value of the injectedvoltage on 120 V tap.

en07000185.vsd

REG 670

RXTTE 4

I

U

230 V AC

120 V AC

0

Generator rotor winding

G

313

314

315

421

428

324

325

221 222

Optional external resistor

Connection to be done by the panel builder / field contractor

321

Figure 130: Connection of rotor earth fault protection

For small generators only I can be measured (i.e. non-directional OC is used), seefigure 130.

CurrentInput: The parameter CurrentInput shall be set to phase1. In the signal matrixtool the input current signal from RXTTE4 is linked to phase 1.

IBase: The parameter IBase shall be set to primary current of the CT, which means1000 A.



323

VoltageInput: The parameter VoltageInput shall be set to phase 1. In the signal matrixtool the voltage signal from RXTTE4 is linked to the first input of the usedprepossessing block.

UBase: The parameter UBase shall be set to primary set primary Voltage of the VT,which means 100 kV.

OperHarmRestr: The possibility for harmonic restrain of the functions should not beused as this could block the function at a faulted condition. Therefore the parameterOperHarmRestr shall be set Off.

EnRestrainCurr: No current restrain shall be used. Therefore the parameterEnRestrainCurr shall be set Off.

Directional characteristic parameters shall be set as follows: RCADir=0 degree;ROADir=90 degree.

Operation_OC1: The first stage (OC1) of the current function shall be used for alarmwith the highest sensitivity. Therefore the parameter Operation_OC1 shall be setOn.

StartCurr_OC1: The sensitivity of the alarm signal shall be set high. It is proposedto set the primary current pick-up level to 30 mA, which will give a sensitivity 10 –20 kohm. StartCurr_OC1 is proposed to be set to 3% of IBase.

CurrMult_OC1: The binary input ENMULTOC1 is not used in this application.Therefore the setting of the parameter CurrMult_OC1 is of no importance. Can beset to 1.0.

CurveType_OC1: The time delay of the alarm signal should be constant with a delayof about 10.0 s or what the user requires. Set CurveType_OC1 to IEC Def. Time orANSI Def. Time. tDef_OC1 is set according to user preference, recommended value10 s.

ResCrvType_OC1: The alarm signal should reset immediately when the earth faultdetection resets. Therefore the ResCrvType_OC1 is set Instantaneous.

VCntrlMode_OC1: There shall be no voltage control/restrain of the current function.Therefore VCntrlMode_OC1 is set Off.

DirMode_OC1, DirPrinc_OC1: The current measuring function shall be sensitivefor the active component of the injected current (in phase with the injected voltage).DirMode_OC1 is set to Forward. DirPrinc_OC1 is set IcosPhi&U.

ActLowVolt1_VM: If the injected voltage gets low the function shall block to avoidunwanted signal. ActLowVolt1_VM is set Block.

Operation_OC2: The second stage (OC2) of the current function shall be used fortrip with a lower sensitivity compared to the alarm stage. Therefore the parameterOperation_OC2 shall be set On.



REG 670

StartCurr_OC2: The sensitivity of the trip signal shall be set according to userpreference. It is proposed to set the primary current pick-up level to 70 mA, whichwill give a sensitivity 3 – 5 kohm depending on the capacitance of the field windingto ground. StartCurr_OC2 is proposed to be set to 7% of IBase.

CurrMult_OC2: The binary input ENMULTOC2 is not used in this application.Therefore the setting of the parameter CurrMult_OC2 is of no importance. Can beset to 1.0.

CurveType_OC2: The time delay of the alarm trip should be constant with a delay ofabout 0.5 s or what the user requires. Set CurveType_OC2 to IEC Def. Time or ANSIDef. Time. tDef_OC2 is set according to user preference, recommended value 0.5 s.

ResCrvType_OC2: The alarm signal should reset immediately when the earth faultdetection resets. Therefore the ResCrvType_OC2 is set Instantaneous.

VCntrlMode_OC2: There shall be no voltage control/restrain of the current function.Therefore VCntrlMode_OC2 is set Off.

DirMode_OC2, DirPrinc_OC2: The current measuring function shall be sensitivefor the active component (in phase with the injected voltage) of the injected current.DirMode_OC2 is set to Forward. DirPrinc_OC2 is set IcosPhi&U.

ActLowVolt2_VM: If the injected voltage gets low the function shall block to avoidunwanted signal. ActLowVolt2_VM is set Block.

Operation_UC1, Operation_UC2: The undercurrent functions are not used.Therefore Operation_UC1 and Operation_UC2 are set Off.

Stage UC1 can be used for supervision of injected current into therotor winding. In that case it could detect that injection path has beenbroken and give an alarm. However this must be check for everyindividual installation if the injected current is sufficiently high inorder to use undercurrent supervision.

Operation_OV1, Operation_OV2: The overvoltage functions are not used. ThereforeOperation_OV1 and Operation_OV2 are set Off.

Operation_UV1: The undervoltage stage is used to give a signal if the injectionvoltage gets low. Operation_UV1 is set On.

StartVolt_UV1: The signal of low injection voltage should be given if this voltage islower than about 80% of the normal voltage. This means 80% of 100kV (i.e. 100V).This corresponds to the setting StartVolt_UV1: of 80V at 120V tap of RXTTE4.

CurveType_UV1: The time delay of the alarm signal should be constant with a delayof about 10.0 s or what the user requires. Set CurveType_UV1 to Definite time.tDef_UV1 is set according to user preference, recommended value 10 s.

ResCrvType_UV1: The alarm signal should reset immediately when the earth faultdetection resets. Therefore the ResCrvType_UV1 is set Instantaneous.



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Operation_UV2: The second stage of the overvoltage function is not used. ThereforeOperation_UV2 is set Off.

When directional principle is used, the actual phase angle shiftbetween injected current and injected voltage for Rotor earth faultprotection shall be checked during commissioning of the generatorprotection. The injected current shall lead the injected voltage forapproximately 90 degrees (e.g. Angle_Uinj=0° & Angle_Iinj=+90°).This can be checked on the built-in HMI under Menu for TRM servicevalues. If during this check can be seen that injected current is actuallylagging the injection voltage for approximately 90° some mistake inthe wiring has taken place. Thus, either this mistake shall be rectifiedor setting parameters DirMode_OC1 and DirMode_OC2 shall bechanged to value Reverse. Anyhow it is strongly recommended tofinally perform the "Primary Testing" of this function by intentionallyconnecting resistance of 500 Ohms between connection terminal 221on the RXTTE4 unit and ground. Rotor earth fault function shouldthen operate in accordance with preset time. During this test theconnection to the generator field winding can be temporarydisconnected if so required by utility safety regulations.

4.9 Frequency protection

4.9.1 Underfrequency protection (PTUF, 81)

Function block name: TUFx- IEC 60617 graphical symbol:

f <

ANSI number: 81

IEC 61850 logical node name:SAPTUF

4.9.1.1 Application

The underfrequency function (TUF) is applicable in all situations, where reliabledetection of low fundamental power system voltage frequency is needed. The powersystem frequency, and rate of change of frequency, is a measure of the unbalancebetween the actual generation and the load demand. Low fundamental frequency ina power system indicates that the available generation is too low to fully supply thepower demanded by the load connected to the power grid. The underfrequencyfunction detects such situations and provides an output signal, suitable for loadshedding, generator boosting, HVDC-set-point change, gas turbine start up, etc.



REG 670

Sometimes also shunt reactors are automatically switched in due to low frequency,in order to reduce the power system voltage and hence also reduce the voltagedependent part of the load. The underfrequency function is very sensitive and accurateand can also be used to alert operators that frequency has slightly deviated from theset-point, and that manual actions might be enough. The underfrequency signal isalso used for overexcitation detection. This is especially important for generator step-up transformers, which might be connected to the generator but disconnected fromthe grid, during a roll-out sequence. If the generator is still energized, the system willexperience overexcitation, due to the low frequency.


The parameters for the underfrequency (TUF) function are set via the local HMI orProtection and Control IED Manager (PCM 600).

All the frequency and voltage magnitude conditions in the system where theunderfrequency protection performs its functions should be considered. The samealso applies to the associated equipment, its frequency and time characteristic.

There are especially two application areas for underfrequency protection:

1. to protect equipment against damage due to low frequency, such as generators,transformers, and motors. Overexcitation is also related to low frequency

2. to protect a power system, or a part of a power system, against breakdown, byshedding load, in generation deficit situations.

The underfrequency start value is set in Hz. All voltage magnitude related settingsare made as a percentage of a settable base voltage, which normally is set to thenominal primary voltage level (phase-phase) of the power system or the high voltageequipment under consideration.

The underfrequency function is not instantaneous, since the frequency is related tomovements of the system inertia, but the time and frequency steps between differentactions might be critical, and sometimes a rather short operation time is required, e.g.down to 70 ms.

Below, some applications and related setting guidelines for the frequency level aregiven:

Equipment protection, such as for motors and generatorsThe setting has to be well below the lowest occurring "normal" frequency and wellabove the lowest acceptable frequency for the equipment.

Power system protection, by load sheddingThe setting has to be well below the lowest occurring "normal" frequency and wellabove the lowest acceptable frequency for power stations, or sensitive loads. Thesetting level, the number of levels and the distance between two levels (in time and/or in frequency) depends very much on the characteristics of the power system underconsideration. The size of the "largest loss of production" compared to "the size of



327

the power system" is a critical parameter. In large systems, the load shedding can beset at a fairly high frequency level, and the time delay is normally not critical. Insmaller systems the frequency start level has to be set at a lower value, and the timedelay must be rather short.

The voltage related time delay is used for load shedding. The settings of theunderfrequency function could be the same all over the power system. The loadshedding is then performed firstly in areas with low voltage magnitude, whichnormally are the most problematic areas, where the load shedding also is mostefficient.


Table 104: Basic parameter group settings for the SAPTUF_81 (TUF1-) function




StartFrequency 35.00 - 75.00 0.01 48.80 Hz Frequency setting/start value.

IntBlockLevel 0 - 100 1 50 %UB Internal blocking levelin % of UBase.

TimeDlyOperate 0.000 - 60.000 0.001 0.200 s Operate time delay inover/under-frequencymode.

TimeDlyReset 0.000 - 60.000 0.001 0.000 s Time delay for reset.

TimeDlyRestore 0.000 - 60.000 0.001 0.000 s Restore time delay.

RestoreFreq 45.00 - 65.00 0.01 50.10 Hz Restore frequency iffrequency is abovefrequency value.

TimerOperation Definite timerVolt based timer

- Definite timer - Setting for choosingtimer mode.

UNom 50 - 150 1 100 %UB Nominal voltage in %of UBase for voltagebased timer.

UMin 50 - 150 1 90 %UB Lower operation limitin % of UBase forvoltage based timer.

Exponent 1.0 0.1 0.0 - 5.0 - For calculation of thecurve form for voltagebased timer.

tMax 0.010 - 60.000 0.001 1.000 s Maximum timeoperation limit forvoltage based timer.

tMin 0.010 - 60.000 0.001 1.000 s Minimum timeoperation limit forvoltage based timer.



REG 670

4.9.2 Overfrequency protection (PTOF, 81)

Function block name: TOFx- IEC 60617 graphical symbol:

f >

ANSI number: 81

IEC 61850 logical node name:SAPTOF

4.9.2.1 Application

The overfrequency function (TOF) is applicable in all situations, where reliabledetection of high fundamental power system voltage frequency is needed. The powersystem frequency, and rate of change of frequency, is a measure of the unbalancebetween the actual generation and the load demand. High fundamental frequency ina power system indicates that the available generation is too large compared to thepower demanded by the load connected to the power grid. The overfrequency functiondetects such situations and provides an output signal, suitable for generator shedding,HVDC-set-point change, etc. The overfrequency function is very sensitive andaccurate and can also be used to alert operators that frequency has slightly deviatedfrom the set-point, and that manual actions might be enough.


The parameters for the overfrequency (TOF) function are set via the local HMI orProtection and Control IED Manager (PCM 600).

All the frequency and voltage magnitude conditions in the system where theoverfrequency protection performs its functions should be considered. The same alsoapplies to the associated equipment, its frequency and time characteristic.

There are especially two application areas for overfrequency protection:

1. to protect equipment against damage due to high frequency, such as generators,and motors

2. to protect a power system, or a part of a power system, against breakdown, byshedding generation, in generation surplus situations.

The overfrequency start value is set in Hz. All voltage magnitude related settings aremade as a percentage of a settable base voltage, which normally is set to the nominalvoltage level (phase-phase) of the power system or the high voltage equipment underconsideration.

The overfrequency function is not instantaneous, since the frequency is related tomovements of the system inertia, but the time and frequency steps between different



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actions might be critical, and sometimes a rather short operation time is required, e.g.down to 70 ms.

Below, some applications and related setting guidelines for the frequency level aregiven.

Equipment protection, such as for motors and generatorsThe setting has to be well above the highest occurring "normal" frequency and wellbelow the highest acceptable frequency for the equipment.

Power system protection, by generator sheddingThe setting has to be well above the highest occurring "normal" frequency and wellbelow the highest acceptable frequency for power stations, or sensitive loads. Thesetting level, the number of levels and the distance between two levels (in time and/or in frequency) depend very much on the characteristics of the power system underconsideration. The size of the "largest loss of load" compared to "the size of the powersystem" is a critical parameter. In large systems, the generator shedding can be set ata fairly low frequency level, and the time delay is normally not critical. In smallersystems the frequency start level has to be set at a higher value, and the time delaymust be rather short.


Table 105: Basic parameter group settings for the SAPTOF_81 (TOF1-) function




StartFrequency 35.00 - 75.00 0.01 51.20 Hz Frequency setting/start value.


TimeDlyOperate 0.000 - 60.000 0.001 0.000 s Operate time delay inover/under-frequencymode.

TimeDlyReset 0.000 - 60.000 0.001 0.000 s Time delay for reset.

4.9.3 Rate-of-change frequency protection (PFRC, 81)

Function block name: RCFx- IEC 60617 graphical symbol:

df/dt ><

ANSI number: 81

IEC 61850 logical node name:SAPFRC



REG 670

4.9.3.1 Application

The rate-of-change frequency function (RCF), is applicable in all situations, wherereliable detection of change of the fundamental power system voltage frequency isneeded. The RCF can be used both for increasing frequency and for decreasingfrequency. The RCF provides an output signal, suitable for load shedding or generatorshedding, generator boosting, HVDC-set-point change, gas turbine start up, etc. Veryoften the rate-of-change of frequency is used in combination with a low frequencysignal, especially in smaller power systems, where loss of a fairly large generator willrequire quick remedial actions to secure the power system integrity. In such situationsload shedding actions are required at a rather high frequency level, but in combinationwith a large negative rate-of-change of frequency the underfrequency protection canbe used - at a rather high setting.


The parameters for the rate-of-change of frequency (RCF) function are set via thelocal HMI or Protection and Control IED Manager (PCM 600).

All the frequency and voltage magnitude conditions in the system where the rate-of-change of frequency protection performs its functions should be considered. The samealso applies to the associated equipment, its frequency and time characteristic.

There are especially two application areas for rate-of-change of frequency protection:

1. to protect equipment against damage due to high or to low frequency, such asgenerators, transformers, and motors

2. to protect a power system, or a part of a power system, against breakdown, byshedding load or generation, in situations where load and generation are not inbalance.

The rate-of-change of frequency (RFC) function is normally used together with anover- or underfrequency function, in small power systems, where a single event cancause a large imbalance between load and generation. In such situations load orgeneration shedding has to take place very quickly, and there might not be enoughtime to wait until the frequency signal has reached an abnormal value. Actions aretherefore taken at a frequency level closer to the primary nominal level, if the rate-of-change of frequency is large (with respect to sign).

The rate-of-change of frequency start value is set in Hz/s. All voltage magnituderelated settings are made as a percentage of a settable base voltage, which normallyis set to the primary nominal voltage level (phase-phase) of the power system or thehigh voltage equipment under consideration.

The rate-of-change of frequency function is not instantaneous, since the functionneeds some time to supply a stable value. It is recommended to have a time delaylong enough to take care of signal noise. However, the time, rate-of-change offrequency and frequency steps between different actions might be critical, andsometimes a rather short operation time is required, e.g. down to 70 ms.



331

Smaller industrial systems might experience rate-of-change of frequency as large as5 Hz/s, due to a single event. Even large power systems may form small islands witha large imbalance between load and generation, when severe faults (or combinationsof faults) are cleared - up to 3 Hz/s has been experienced when a small island wasisolated from a large system. For more "normal" severe disturbances in large powersystems, the rate-of-change of frequency is much less, most often just a fraction of1.0 Hz/s.


Table 106: Basic parameter group settings for the SAPFRC_81 (RCF1-) function



UBase 0.05 - 2000.00 0.05 400.00 kV Base setting for thephase-phase voltagein kV

StartFreqGrad -10.00 - 10.00 0.01 0.50 Hz/s Frequency gradientstart value. Signdefines direction.


tTrip 0.000 - 60.000 0.001 0.200 s Operate time delay inpos./neg. frequencygradient mode.

RestoreFreq 45.00 - 65.00 0.01 49.90 Hz Restore frequency iffrequency is abovefrequency value (Hz)

tRestore 0.000 - 60.000 0.001 0.000 s Restore time delay.

tReset 0.000 - 60.000 0.001 0.000 s Time delay for reset.

4.10 Multipurpose protection

4.10.1 General current and voltage protection (GAPC)



REG 670

Function block name: GFxx- IEC 60617 graphical symbol:

ANSI number: 46, 51, 67, 51N, 67N, 27, 59, 21,40

I

IEC 61850 logical node name: CVGAPC

U


A breakdown of the insulation between phase conductors or a phase conductor andearth results in a short-circuit or an earth fault. Such faults can result in large faultcurrents and may cause severe damage to the power system primary equipment.Depending on the magnitude and type of the fault different overcurrent protections,based on measurement of phase, ground or sequence current components can be usedto clear these faults. Additionally it is sometimes required that these overcurrentprotections shall be directional and/or voltage controlled/restrained.

The over/under voltage protection is applied on power system elements, such asgenerators, transformers, motors and power lines in order to detect abnormal voltageconditions. Depending on the type of voltage deviation and type of power systemabnormal condition different over/under voltage protections based on measurementof phase-to-ground, phase-to-phase, residual or sequence voltage components can beused to detect and operate for such incident.

The IED can be provided with multiple General Function (GF) protection modules.The function is always connected to three-phase current and three-phase voltage inputin the configuration tool, but it will always measure only one current and one voltagequantity selected by the end user in the setting tool.

Each general current and voltage protection function module has got four independentprotection elements built into it.

1. Two overcurrent steps with the following built-in features:• Definite time delay or Inverse Time Overcurrent TOC/IDMT delay for

both steps• Second harmonic supervision is available in order to only allow operation

of the overcurrent stage(s) if the content of the second harmonic in themeasured current is lower than pre-set level

• Directional supervision is available in order to only allow operation of theovercurrent stage(s) if the fault location is in the pre-set direction (i.e.



333

Forward or Reverse). Its behavior during low-level polarizing voltage issettable (i.e. Non-Directional / Block / Memory)

• Voltage restrained/controlled feature is available in order to modify thepick-up level of the overcurrent stage(s) in proportion to the magnitude ofthe measured voltage

• Current restrained feature is available in order to only allow operation ofthe overcurrent stage(s) if the measured current quantity is bigger than theset percentage of the current restrain quantity.

2. Two undercurrent steps with the following built-in features:• Definite time delay for both steps

3. Two overvoltage steps with the following built-in features• Definite time delay or Inverse Time Overcurrent TOC/IDMT delay for

both steps4. Two undervoltage steps with the following built-in features

• Definite time delay or Inverse Time Overcurrent TOC/IDMT delay forboth steps

All these four protection elements within one general protection function worksindependently from each other and they can be individually enabled or disabled.However it shall be once more noted that all these four protection elements measureone selected current quantity and one selected voltage quantity (see table 107 andtable 108). It is possible to simultaneously use all four-protection elements and theirindividual stages. Sometimes in order to obtain desired application functionality it isnecessary to provide interaction between two or more protection elements/stageswithin one GF function by appropriate IED configuration (e.g. dead machineprotection for generators).

Current and voltage selection for GF functionThe function is always connected to three-phase current and three-phase voltage inputin the configuration tool, but it will always measure only the single current and thesingle voltage quantity selected by the end user in the setting tool (i.e. selected currentquantity and selected voltage quantity).

The user can select, by a setting parameter CurrentInput, to measure one of thefollowing current quantities shown in table 107.

Table 107: Available selection for current quantity within GF function

Set value for parameter"CurrentInput”

Comment

1 Phase1 GF function will measure the phase L1 current phasor



4 PosSeq GF function will measure internally calculated positive sequencecurrent phasor

5 NegSeq GF function will measure internally calculated negativesequence current phasor




REG 670

Set value for parameter"CurrentInput”

Comment

6 3ZeroSeq GF function will measure internally calculated zero sequencecurrent phasor multiplied by factor 3

7 MaxPh GF function will measure current phasor of the phase withmaximum magnitude

8 MinPh GF function will measure current phasor of the phase withminimum magnitude

9 UnbalancePh GF function will measure magnitude of unbalance current, whichis internally calculated as the algebraic magnitude differencebetween the current phasor of the phase with maximummagnitude and current phasor of the phase with minimummagnitude. Phase angle will be set to 0°all the time

10 Phase1-Phase2 GF function will measure the current phasor internally calculatedas the vector difference between the phase L1 current phasorand phase L2 current phasor (i.e. IL1-IL2)



13 MaxPh-Ph GF function will measure ph-ph current phasor with themaximum magnitude

14 MinPh-Ph GF function will measure ph-ph current phasor with the minimummagnitude

15 UnbalancePh-Ph GF function will measure magnitude of unbalance current, whichis internally calculated as the algebraic magnitude differencebetween the ph-ph current phasor with maximum magnitude andph-ph current phasor with minimum magnitude. Phase angle willbe set to 0o all the time

The user can select, by a setting parameter VoltageInput, to measure one of thefollowing voltage quantities shown in table 108.

Table 108: Available selection for voltage quantity within GF function

Set value for parameter"VoltageInput"

Comment

1 Phase1 GF function will measure the phase L1 voltage phasor



4 PosSeq GF function will measure internally calculated positive sequencevoltage phasor

5 -NegSeq GF function will measure internally calculated negativesequence voltage phasor. This voltage phasor will beintentionally rotated for 180o in order to enable easier settingsfor the directional feature when used.

6 -3ZeroSeq GF function will measure internally calculated zero sequencevoltage phasor multiplied by factor 3. This voltage phasor will beintentionally rotated for 180o in order to enable easier settingsfor the directional feature when used.




335

Set value for parameter"VoltageInput"

Comment

7 MaxPh GF function will measure voltage phasor of the phase withmaximum magnitude

8 MinPh GF function will measure voltage phasor of the phase withminimum magnitude

9 UnbalancePh GF function will measure magnitude of unbalance voltage, whichis internally calculated as the algebraic magnitude differencebetween the voltage phasor of the phase with maximummagnitude and voltage phasor of the phase with minimummagnitude. Phase angle will be set to 0° all the time

10 Phase1-Phase2 GF function will measure the voltage phasor internally calculatedas the vector difference between the phase L1 voltage phasorand phase L2 voltage phasor (i.e. UL1-UL2VA-VB)

11 Phase2-Phase3 GF function will measure the voltage phasor internally calculatedas the vector difference between the phase L2 voltage phasorand phase L3 voltage phasor (i.e. UL2-UL3)

12 Phase3-Phase1 GF function will measure the voltage phasor internally calculatedas the vector difference between the phase L3 voltage phasorand phase L1 voltage phasor (i.e. UL3-UL1)

13 MaxPh-Ph GF function will measure ph-ph voltage phasor with themaximum magnitude

14 MinPh-Ph GF function will measure ph-ph voltage phasor with the minimummagnitude

15 UnbalancePh-Ph GF function will measure magnitude of unbalance voltage, whichis internally calculated as the algebraic magnitude differencebetween the ph-ph voltage phasor with maximum magnitude andph-ph voltage phasor with minimum magnitude. Phase angle willbe set to 0o all the time

It is important to notice that the voltage selection from table 108 is always applicableregardless the actual external VT connections. The three-phase VT inputs can beconnected to IED as either three phase-to-ground voltages UL1, UL2 & UL3 or threephase-to-phase voltages UL1L2, UL2L3 & UL3L1VAB, VBC and VCA. Thisinformation about actual VT connection is entered as a setting parameter for the pre-processing block, which will then take automatic care about it.

Base quantities for GF functionThe parameter settings for the base quantities, which represent the base (i.e. 100%)for pickup levels of all measuring stages shall be entered as setting parameters forevery GF function.

Base current shall be entered as:

1. rated phase current of the protected object in primary amperes, when themeasured Current Quantity is selected from 1 to 9, as shown in table 107.

2. rated phase current of the protected object in primary amperes multiplied by √3(i.e. 1,732 x Iphase), when the measured Current Quantity is selected from 10 to15, as shown in table 107.

Base voltage shall be entered as:



REG 670

1. rated phase-to-ground voltage of the protected object in primary kV, when themeasured Voltage Quantity is selected from 1 to 9, as shown in table 108.

2. rated phase-to-phase voltage of the protected object in primary kV, when themeasured Voltage Quantity is selected from 10 to 15, as shown intable 108.

Application possibilitiesDue to its flexibility the GF can be used, with appropriate settings and configurationin many different applications. Some of possible examples are given below:

1. Transformer and line applications:• Underimpedance protection (circular, non-directional characteristic) (21)• Underimpedance protection (circular mho characteristic) (21)• Voltage Controlled/Restrained Overcurrent protection (51C, 51V)• Phase or Negative/Positive/Zero Sequence (Non-Directional or

Directional) Overcurrent protection (50, 51, 46, 67, 67N, 67Q)• Phase or phase-to-phase or Negative/Positive/Zero Sequence over/under

voltage protection (27, 59, 47)• Special thermal overload protection (49)• Open Phase protection• Unbalance protection

2. Generator protection• 80-95% Stator EF protection (measured or calculated 3Uo) (59GN)• Rotor EF protection (with external COMBIFLEX RXTTE4 injection unit)

(64F)• Underimpedance protection (21)• Voltage Controlled/Restrained Overcurrent protection (51C, 51V)• Turn-to-Turn & Differential Backup protection (directional Negative

Sequence. Overcurrent protection connected to generator HV terminal CTslooking into generator) (67Q)

• Stator Overload protection (49S)• Rotor Overload protection (49R)• Loss of Excitation protection (directional pos. seq. OC protection) (40)• Reverse power/Low forward power protection (directional pos. seq. OC

protection, 2% sensitivity) (32)• Dead-Machine/Inadvertent-Energizing protection (51/27)• Breaker head flashover protection• Improper synchronizing detection• Sensitive negative sequence generator over current protection and alarm

(46)



337

• Phase or phase-to-phase or Negative/Positive/Zero Sequence over/undervoltage protection (27x, 59x, 47)

• Generator out-of-step detection (based on directional pos. seq. OC) (78)• Inadvertent generator energization

Inadvertent generator energizationWhen the generator is taken out of service, and non-rotating, there is a risk that thegenerator circuit breaker is closed by mistake.

Three-phase energizing of a generator, which is at standstill or on turning gear, causesit to behave and accelerate similarly to an induction motor. The machine, at this point,essentially represents the subtransient reactance to the system and it can be expectedto draw from one to four per unit current, depending on the equivalent systemimpedance. Machine terminal voltage can range from 20% to 70% of rated voltage,again, depending on the system equivalent impedance (including the blocktransformer). Higher quantities of machine current and voltage (3 to 4 per unit currentand 50% to 70% rated voltage) can be expected if the generator is connected to astrong system. Lower current and voltage values (1 to 2 per unit current and 20% to40% rated voltage) are representative of weaker systems.

Since a generator behaves similarly to an induction motor, high currents will developin the rotor during the period it is accelerating. Although the rotor may be thermallydamaged from excessive high currents, the time to damage will be on the order of afew seconds. Of more critical concern, however, is the bearing, which can be damagedin a fraction of a second due to low oil pressure. Therefore, it is essential that highspeed tripping is provided. This tripping should be almost instantaneous (< 100 ms).

There is a risk that the current into the generator at inadvertent energization will belimited so that the “normal” overcurrent or underimpedance protection will not detectthe dangerous situation. The delay of these protection functions might be too long.The reverse power protection might detect the situation but the operation time of thisprotection is normally too long.

For big and important machines, fast protection against inadvertent energizing should,therefore, be included in the protective scheme.

The protection against inadvertent energization can be made by a combination ofundervoltage, overvoltage and overcurrent protection functions. The undervoltagefunction will, with a delay for example 10 s, detect the situation when the generatoris not connected to the grid (standstill) and activate the overcurrent function. Theovervoltage function will detect the situation when the generator is taken intooperation and will disable the overcurrent function. The overcurrent function willhave a pick-up value about 50% of the rated current of the generator. The trip delaywill be about 50 ms.




REG 670

The parameters for the general current and voltage protection function (GF) are setvia the local HMI or Protection and Control IED Manager (PCM 600).

Directional negative sequence overcurrent protectionDirectional negative sequence overcurrent protection is typically used as sensitiveearth-fault protection of power lines were incorrect zero sequence polarization mayresult from mutual induction between two or more parallel lines. Additionally it canbe used in applications on underground cables where zero-sequence impedancedepends on the fault current return paths, but the cable negative-sequence impedanceis practically constant. It shall be noted that directional negative sequence OC elementoffers protection against all unbalance faults (i.e. phase-to-phase faults as well). Careshall be taken that the minimum pickup of such protection function shall be set abovenatural system unbalance level.

Example will be given how by using negative sequence directional overcurrentprotection elements within a GF function, sensitive earth fault protection for powerlines can be achieved.

This functionality can be achieved by using one GF function. The following shall bedone in order to ensure proper operation of the function:

1. Connect three-phase power line currents and three-phase power line voltages toone GF instance (e.g. GF04)

2. Set parameter CurrentInput to NegSeq (please note that function measures I2current and NOT 3I2 current; this is essential for proper OC pickup level setting)

3. Set parameter VoltageInput to -NegSeq (please note that the negative sequencevoltage phasor is intentionally inverted in order to simplify directionality

4. Set base current value equal to the rated primary current of power line CTs5. Set base voltage value equal to the rated power line phase-to-phase voltage in

kV6. Set parameter RCA_DIR to value +65 degrees (i.e. NegSeq current typically lags

the inverted NegSeq voltage for this angle during the fault)7. Set parameter ROA_DIR to value 90 degree8. Set parameter LowVolt_VM to value 2% (NegSeq voltage level above which

the directional element will be enabled)9. Enable one overcurrent stage (e.g. OC1)10. By parameter CurveType_OC1 select appropriate TOC/IDMT or definite time

delayed curve in accordance with your network protection philosophy11. Set parameter StartCurr_OC1 to value between 3-10% (typical values)12. Set parameter tDef_OC1 or parameter “k” when TOC/IDMT curves are used to

insure proper time coordination with other ground fault protections installed inthe vicinity of this power line

13. Set parameter DirMode_OC1 to Forward14. Set parameter DirPrinc_OC1 to IcosΦ&U15. Set parameter ActLowVolt1_VM to Block

• In order to insure proper restraining of this element for CT saturationsduring three-phase faults it is possible to use current restraint feature andenable this element to operate only when NegSeq current is bigger than acertain percentage (i.e. 10% is typical value) of measured PosSeq current



339

in the power line. To do this the following settings within the same functionshall be done:

16. Set parameter EnRestrainCurr to On17. Set parameter RestrCurrInput to PosSeq18. Set parameter RestrCurrCoeff to value 0.10

If required this function can be used in directional comparison protection scheme forthe power line protection if communication channels to the remote end of this powerline are available. In that case typically two NegSeq overcurrent steps are required.One for forward and one for reverse direction. As explained before the OC1 stagecan be used to detect faults in forward direction. The built-in OC2 stage can be usedto detect faults in reverse direction.

However the following shall be noted for such application:

• the set values for RCA_Dir and ROA_Dir setting parameters will be as wellapplicable for OC2 stage

• setting parameter DirMode_OC2 shall be set to Reverse• setting parameter StartCurr_OC2 shall be made more sensitive than pickup value

of forward OC1 element (i.e. typically 60% of OC1 set pickup level) in order toinsure proper operation of the directional comparison scheme during currentreversal situations

• start signals from OC1 and OC2 elements shall be used to send forward andreverse signals to the remote end of the power line

• the available scheme communications function block within REx670 IED shallbe used between multipurpose protection function and the communicationequipment in order to insure proper conditioning of the above two start signals

Furthermore the other built-in UC, OV and UV protection elements can be used forother protection and alarming purposes.

Negative sequence overcurrent protectionExample will be given how to use one GF function to provide negative sequenceinverse time overcurrent protection for a generator with capability constant of 20s,and maximum continuous negative sequence rating of 7% of the generator ratedcurrent.

The capability curve for a generator negative sequence overcurrent protection, oftenused world-wide, is defined by the ANSI standard in accordance with the followingformula:

2op

NS

r

ktII

=æ öç ÷è ø (Equation 151)

where:

top is the operating time in seconds of the negative sequence overcurrent relay



REG 670

k is the generator capability constant in seconds

INS is the measured negative sequence current

Ir is the generator rated current

By defining parameter x equal to maximum continuous negative sequence rating ofthe generator in accordance with the following formula

7% 0, 07x pu= =(Equation 152)

Equation 151 can be re-written in the following way without changing the value forthe operate time of the negative sequence inverse overcurrent relay:

2

2

1

op

NS

r

kxt

Ix I

×=

æ öç ÷×è ø (Equation 153)

In order to achieve such protection functionality with one GF functions the followingmust be done:

1. Connect three-phase generator currents to one GF instance (e.g. GF01)2. Set parameter CurrentInput to value NegSeq3. Set base current value to the rated generator current in primary amperes4. Enable one overcurrent step (e.g. OC1)5. Select parameter CurveType_OC1 to value "Programmable"

op P

At k BM C

æ ö= × +ç ÷-è ø (Equation 154)

where:

top is the operating time in seconds of the Inverse Time Overcurrent TOC/IDMT algorithm

k is time multiplier (parameter setting)

M is ratio between measured current magnitude and set pickup current level

A, B, C and P are user settable coefficients which determine the curve used for Inverse TimeOvercurrent TOC/IDMT calculation

When the equation 151 is compared with the equation 153 for the inverse timecharacteristic of the OC1 it is obvious that if the following rules are followed:



341

1. set k equal to the generator negative sequence capability value2. set parameter A_OC1 equal to the value 1/x23. set parameters B_OC1 = 0.0, C_OC1=0.0 and P_OC1=2.04. set StartCurr_OC1 equal to the value x

then the OC1 step of the GF function can be used for generator negative sequenceinverse overcurrent protection.

For this particular example the following settings shall be entered to insure properfunction operation:

1. select negative sequence current as measuring quantity for this GF function2. make sure that the base current value for the GF function is equal to the generator

rated current3. set k_OC1 = 204. set A_OC1= 1/0.072 = 204.08165. set B_OC1 = 0.0, C_OC1 = 0.0 and P_OC1 = 2.06. set StartCurr_OC1 = 7%

Proper timing of the GF function made in this way can easily be verified by secondaryinjection. All other settings can be left at the default values. If required delayed timereset for OC1 step can be set in order to ensure proper function operation in case ofrepetitive unbalance conditions.

Furthermore the other built-in protection elements can be used for other protectionand alarming purposes (e.g. use OC2 for negative sequence overcurrent alarm andOV1 for negative sequence overvoltage alarm).

Generator stator overload protection in accordance with IEC or ANSIstandardsExample will be given how to use one GF function to provide generator statoroverload protection in accordance with IEC or ANSI standard if minimum-operatingcurrent shall be set to 116% of generator rating.

The generator stator overload protection is defined by IEC or ANSI standard for turbogenerators in accordance with the following formula:

2

1op

m

r

ktII

=æ ö

-ç ÷è ø (Equation 155)

where:

top is the operating time of the generator stator overload relay

k is the generator capability constant in accordance with the relevant standard (k = 37.5 for theIEC standard or k = 41.4 for the ANSI standard)

Im is the magnitude of the measured current

Ir is the generator rated current



REG 670

This formula is applicable only when measured current (e.g. positive sequencecurrent) exceeds a pre-set value (typically in the range from 105 to 125% of thegenerator rated current).

By defining parameter x equal to the per unit value for the desired pickup for theoverload relay in accordance with the following formula:

116% 1,16x pu= =(Equation 156)

formula 3.5can be re-written in the following way without changing the value for theoperate time of the generator stator overload relay:

2

2

2

1

1op

m

r

kxt

Ix I x

×=

æ ö-ç ÷×è ø (Equation 157)

In order to achieve such protection functionality with one GF functions the followingmust be done:

1. Connect three-phase generator currents to one GF instance (e.g. GF01)2. Set parameter CurrentInput to value "PosSeq"3. Set base current value to the rated generator current in primary amperes4. Enable one overcurrent step (e.g. OC1)5. Select parameter CurveType_OC1 to value "Programmable"

op P

At k BM C

æ ö= × +ç ÷-è ø (Equation 158)

where:

top is the operating time in seconds of the Inverse Time Overcurrent TOC/IDMT algorithm

k is time multiplier (parameter setting)

M is ratio between measured current magnitude and set pickup current level

A, B, C and P are user settable coefficients which determine the curve used for Inverse TimeOvercurrent TOC/IDMT calculation

When the equation 157 is compared with the equation 158 for the inverse timecharacteristic of the OC1 step in it is obvious that if the following rules are followed:

1. set k equal to the IEC or ANSI standard generator capability value2. set parameter A_OC1 equal to the value 1/x23. set parameter C_OC1 equal to the value 1/x24. set parameters B_OC1 = 0.0 and P_OC1=2.05. set StartCurr_OC1 equal to the value x



343

then the OC1 step of the GF function can be used for generator negative sequenceinverse overcurrent protection.

1. select positive sequence current as measuring quantity for this GF function2. make sure that the base current value for the GF function is equal to the generator

rated current3. set k = 37.5 for the IEC standard or k = 41.4 for the ANSI standard4. set A_OC1= 1/1.162 = 0.74325. set C_OC1= 1/1.162 = 0.74326. set B_OC1 = 0.0 and P_OC1 = 2.07. set StartCurr_OC1 = 116%

Proper timing of the GF function made in this way can easily be verified by secondaryinjection. All other settings can be left at the default values. If required delayed timereset for OC1 step can be set in order to insure proper function operation in case ofrepetitive overload conditions.

Furthermore the other built-in protection elements can be used for other protectionand alarming purposes.

In the similar way rotor overload protection in accordance with ANSI standard canbe achieved.

Open phase protection for transformer, lines or generators and circuitbreaker head flashover protection for generatorsExample will be given how to use one GF function to provide open phase protection.This can be achieved by using one GF function by comparing the unbalance currentwith a pre-set level. In order to make such a function more secure it is possible torestrain it by requiring that at the same time the measured unbalance current must bebigger than 97% of the maximum phase current. By doing this it will be insured thatfunction can only pickup if one of the phases is open circuited. Such an arrangementis easy to obtain in the GF function by enabling the current restraint feature. Thefollowing shall be done in order to insure proper operation of the function:

1. Connect three-phase currents from the protected object to one GF instance (e.g.GF03)

2. Set parameter CurrentInput to value "UnbalancePh"3. Set parameter EnRestrainCurr to "On"4. Set parameter RestrCurrInput to "MaxPh"5. Set parameter RestrCurrCoeff to value 0.976. Set base current value to the rated current of the protected object in primary

amperes7. Enable one overcurrent step (e.g. OC1)8. Select parameter CurveType_OC1 to value "IEC Def. Time"9. Set parameter StartCurr_OC1 to value 5%10. Set parameter tDef_OC1 to desired time delay (e.g. 2.0s)

Proper operation of the GF function made in this way can easily be verified bysecondary injection. All other settings can be left at the default values. However it



REG 670

shall be noted that set values for restrain current and its coefficient will as well beapplicable for OC2 step as soon as it is enabled.

Furthermore the other built-in protection elements can be used for other protectionand alarming purposes. For example in case of generator application by enabling OC2step with set pickup to 200% and time delay to 0.1s simple but effective protectionagainst circuit breaker head flashover protection is achieved.

Voltage restrained overcurrent protection for generator and step-uptransformerExample will be given how to use one GF function to provide voltage restrainedovercurrent protection for a generator. Let us assume that the time coordination studygives the following required settings:

• Inverse Time Over Current TOC/IDMT curve: ANSI very inverse• Pickup current of 185% of generator rated current at rated generator voltage• Pickup current 25% of the original pickup current value for generator voltages

below 25% of rated voltage

This functionality can be achieved by using one GF function. The following shall bedone in order to insure proper operation of the function:

1. Connect three-phase generator currents and voltages to one GF instance (e.g.GF05)

2. Set parameter "CurrentInput" to value "MaxPh"3. Set parameter "VoltageInput" to value "MinPh-Ph" (i.e. it is assumed that

minimum phase-to-phase voltage shall be used for restraining. Alternativelypositive sequence voltage can be used for restraining by selecting "PosSeq" forthis setting parameter)

4. Set base current value to the rated generator current primary amperes5. Set base voltage value to the rated generator phase-to-phase voltage in kV6. Enable one overcurrent step (e.g. OC1)7. Select parameter CurveType_OC1 to value "ANSI Very Inverse"8. If required set minimum operating time for this curve by using parameter

tMin_OC1 (default value 0.05s)9. Set parameter StartCurr_OC1 to value 185%10. Set parameter VCntrlMode_OC1 to "On"11. Set parameter VDepMode_OC1 to "Slope"12. Set parameter VDepFact_OC1 to value 0.2513. Set parameter UHighLimit_OC1 to value 100%14. Set parameter ULowLimit_OC1 to value 25%

Proper operation of the GF function made in this way can easily be verified bysecondary injection. All other settings can be left at the default values. Furthermorethe other built-in protection elements can be used for other protection and alarmingpurposes.



345

Loss of excitation protection for a generatorExample will be given how by using positive sequence directional overcurrentprotection element within a GF function, loss of excitation protection for a generatorcan be achieved. Let us assume that from rated generator data the following valuesare calculated:

• Maximum generator capability to contentiously absorb reactive power at zeroactive loading 38% of the generator MVA rating

• Generator pull-out angle 84 degrees

This functionality can be achieved by using one GF function. The following shall bedone in order to insure proper operation of the function:

1. Connect three-phase generator currents and three-phase generator voltages toone GF instance (e.g. GF02)

2. Set parameter CurrentInput to "PosSeq"3. Set parameter VoltageInput to "PosSeq"4. Set base current value to the rated generator current primary amperes5. Set base voltage value to the rated generator phase-to-phase voltage in kV6. Set parameter RCA_DIR to value -84 degree (i.e. current lead voltage for this

angle)7. Set parameter ROA_DIR to value 90 degree8. Set parameter LowVolt_VM to value 5%9. Enable one overcurrent step (e.g. OC1)10. Select parameter CurveType_OC1 to value "IEC Def. Time"11. Set parameter StartCurr_OC1 to value 38%12. Set parameter tDef_OC1 to value 2.0s (typical setting)13. Set parameter DirMode_OC1 to "Forward"14. Set parameter DirPrinc_OC1 to "IcosF&U"15. Set parameter ActLowVolt1_VM to "Block"

Proper operation of the GF function made in this way can easily be verified bysecondary injection. All other settings can be left at the default values. However itshall be noted that set values for RCA & ROA angles will be applicable for OC2 stepif directional feature is enabled for this step as well. Figure 131 shows overallprotection characteristic

Furthermore the other build-in protection elements can be used for other protectionand alarming purposes.



REG 670

0.2 0.4 0.6

-0.2

0.6

0.8

0.8 1

DILowSet

B

A

C

0.4

0.2

0

1.2 1.4

-0.4

-0.6

-0.8

-rca

Operating Region

Q [pu]

P[pu]

rca

UPS

IPSILowSet

Operating region

en05000535.vsd

Figure 131: Loss of excitation

Inadvertent generator energizationThe inadvertent energization function is realized by means of the general current andvoltage protection function (CAGVPC). The function is configured as shown infigure 132.



347

en06000497.vsd

3IP3UP

BLKOC1

TROV1

TROC1

CVGAPC

TRUV1³1

Figure 132: Configuration of the inadvertent energization function

The setting of the function in the inadvertent energization application is done asdescribed below. It is assumed that the instance is used only for the inadvertentenergization application. It is however possible to extent the use of the instance byusing OC2, UC1, UC2, OV2, UV2 for other protection applications.

General settings of the instanceOperation: With the parameter Operation the function can be set On/Off.

CurrentInput: The current used for the inadvertent energization application is set bythe parameter CurrentInput. Here the setting MaxPh is chosen.

IBase: The parameter IBase is set to the generator rated current according toequation 159.

3N

N

SIBase

U=

×(Equation 159)

VoltageInput: The Voltage used for the inadvertent energization application is set bythe parameter VoltageInput. Here the setting MaxPh-Ph is chosen.



REG 670


OperHarmRestr: No 2nd harmonic restrain is used in this application:OperHarmRestr is set Off. It can be set On if the instance is used also for otherprotection functions.

EnRestrainCurr: The restrain current function is not used in this application:EnRestrainCurr is set Off. It can be set On if the instance is used also for otherprotection functions.

Settings for OC1Operation_OC1: The parameter Operation_OC1 is set On to activate this function.

StartCurr_OC1: The operate current level for OC1 is set by the parameterStartCurr_OC1. The setting is made in % of IBase. The setting should be made sothat the protection picks up at all situations when the generator is switched on to thegrid at stand still situations. The generator current in such situations is dependent ofthe short circuit capacity of the external grid. It is however assumed that a setting of50% of the generator rated current will detect all situations of inadvertent energizationof the generator.

CurveType_OC1: The time delay of OC1 should be of type definite time and this isset in the parameter CurveType_OC1 where ANSI Def. Time is chosen.

tDefOC1: The time delay is set in the parameter tDefOC1 and is set to a short time.0.05 s is recommended.

VCntrlMode_OC1: Voltage control mode for OC1: VCntrlMode_OC1 is set Off.

HarmRestr_OC1: Harmonic restrain for OC1: HarmRestr_OC1 is set Off.

DirMode_OC1: Direction mode for OC1: DirMode_OC1 is set Off.

Setting for OC2Operation_OC2: Operation_OC2 is set Off if the function is not used for otherprotection function.

Setting for UC1Operation_UC1: Operation_UC1 is set Off if the function is not used for otherprotection function.

Setting for UC2Operation_UC2: Operation_UC2 is set Off if the function is not used for otherprotection function.

Settings for OV1Operation_OV1: The parameter Operation_OV1 is set On to activate this function.

StartVolt_OV1: The operate voltage level for OV1 is set by the parameterStartVolt_OV1. The setting is made in % of UBase. The setting should be made so



349

that the protection blocks the function at all situation of normal operation. The settingis done as the lowest operate voltage level of the generator with an added margin.The setting 85% can be used in most cases.

CurveType_OV1:The time delay of OV1 should be of type definite time and this isset in the parameter CurveType_OV1 where Definite time is chosen.

ResCrvType_OV1: The reset time delay of OV1 should be instataneous and this is setin the parameter ResCrvType_OV1 where Instantaneous chosen.

tDefOV1: The time delay is set in the parameter tDefOV1 and is set so that theinadvertent energization function is active a short time after energization of thegenerator. 1.0 s is recommended.

Setting for OV2Operation_OV2:Operation_OV2 is set Off if the function is not used for otherprotection function.

Settings for UV1Operation_UV1: The parameter Operation_UV1 is set On to activate this function.

StartVolt_UV1: The operate voltage level for UV1 is set by the parameterStartVolt_UV1. The setting is made in % of UBase. The setting shall be done so thatall situations with disconnected generator is detected. The setting 70% can be usedin most cases.

CurveType_UV1: The time delay of UV1 should be of type definite time and this isset in the parameter CurveType_UV1 where Definite time is chosen.

ResCrvType_UV1: The reset time delay of UV1 should be delayed a short time sothat the function is not blocked before operation of OC1 in case of inadvertentenergization of the generator. The parameter ResCrvType_UV1 is set to Frozen timer.

tDefUV1: The time delay is set in the parameter tDefUV1 and is set so that theinadvertent energization function is activated after some time when the generator isdisconnected from the grid. 10.0 s is recommended.

tResetDef_UV1: The reset time of UV1 is set by the parameter tResetDef_UV1. Thesetting 1.0 s is recommended.

Setting for UV2Operation_UV2: Operation_UV2 is set Off if the function is not used for otherprotection function.




REG 670

Table 109: Basic parameter group settings for the CVGAPC (GF01-) function



CurrentInput phase1phase2phase3PosSeqNegSeq3*ZeroSeqMaxPhMinPhUnbalancePhphase1-phase2phase2-phase3phase3-phase1MaxPh-PhMinPh-PhUnbalancePh-Ph

- MaxPh - Select current signalwhich will bemeasured insidefunction

IBase 1 - 99999 1 3000 A Base Current

VoltageInput phase1phase2phase3PosSeq-NegSeq-3*ZeroSeqMaxPhMinPhUnbalancePhphase1-phase2phase2-phase3phase3-phase1MaxPh-PhMinPh-PhUnbalancePh-Ph

- MaxPh - Select voltage signalwhich will bemeasured insidefunction


OperHarmRestr OffOn

- Off - Operation of 2ndharmonic restrain Off /On

l_2nd/l_fund 10.0 - 50.0 1.0 20.0 % Ratio of second tofundamental currentharmonic in %

BlkLevel2nd 10 - 5000 1 5000 %IB Harm analysedisabled above thiscurrent level in % ofIbase

EnRestrainCurr OffOn

- Off - Enable currentrestrain function On /Off

RestrCurrInput PosSeqNegSeq3*ZeroSeqMax

- PosSeq - Select current signalwhich will be used forcurr restrain

RestrCurrCoeff 0.00 0.01 0.00 - 5.00 - Restraining currentcoefficient

RCADir -180 - 180 1 -75 Deg Relay CharacteristicAngle




351

Parameter Range Step Default Unit DescriptionROADir 1 - 90 1 75 Deg Relay Operate Angle

LowVolt_VM 0.0 - 5.0 0.1 0.5 %UB Below this level in %of Ubase settingActLowVolt takesover

Operation_OC1 OffOn

- Off - Operation OC1 Off /On

StartCurr_OC1 2.0 - 5000.0 1.0 120.0 %IB Operate current levelfor OC1 in % of Ibase

CurveType_OC1 ANSI Ext. inv.ANSI Very inv.ANSI Norm. inv.ANSI Mod. inv.ANSI Def. TimeL.T.E. inv.L.T.V. inv.L.T. inv.IEC Norm. inv.IEC Very inv.IEC inv.IEC Ext. inv.IEC S.T. inv.IEC L.T. inv.IEC Def. TimeProgrammableRI typeRD type

- ANSI Def. Time - Selection of timedelay curve type forOC1

tDef_OC1 0.00 - 6000.00 0.01 0.50 s Independent(definitive) time delayof OC1

k_OC1 0.30 0.01 0.05 - 999.00 - Time multiplier for thedependent time delayfor OC1

tMin_OC1 0.00 - 6000.00 0.01 0.05 s Minimum operatetime for IEC IDMTcurves for OC1

VCntrlMode_OC1 Voltage controlInput controlVolt/Input controlOff

- Off - Control mode forvoltage controlledOC1 function

VDepMode_OC1 StepSlope

- Step - Voltage dependentmode OC1 (step,slope)

VDepFact_OC1 1.00 0.01 0.02 - 5.00 - Multiplying factor for Ipickup when OC1 is Udependent

ULowLimit_OC1 1.0 - 200.0 0.1 50.0 %UB Voltage low limitsetting OC1 in % ofUbase

UHighLimit_OC1 1.0 - 200.0 0.1 100.0 %UB Voltage high limitsetting OC1 in % ofUbase

HarmRestr_OC1 OffOn

- Off - Enable block of OC1by 2nd harmonicrestrain




REG 670

Parameter Range Step Default Unit DescriptionDirMode_OC1 Non-directional

ForwardReverse

- Non-directional - Directional mode ofOC1 (nondir,forward,reverse)

DirPrinc_OC1 I&UIcosPhi&U

- I&U - Measuring on IandUor IcosPhiandU forOC1

ActLowVolt1_VM Non-directionalBlockMemory

- Non-directional - Low voltage levelaction for Dir_OC1(Nodir, Blk, Mem)

Operation_OC2 OffOn

- Off - Operation OC2 Off /On

StartCurr_OC2 2.0 - 5000.0 1.0 120.0 %IB Operate current levelfor OC2 in % of Ibase

CurveType_OC2 ANSI Ext. inv.ANSI Very inv.ANSI Norm. inv.ANSI Mod. inv.ANSI Def. TimeL.T.E. inv.L.T.V. inv.L.T. inv.IEC Norm. inv.IEC Very inv.IEC inv.IEC Ext. inv.IEC S.T. inv.IEC L.T. inv.IEC Def. TimeProgrammableRI typeRD type

- ANSI Def. Time - Selection of timedelay curve type forOC2

tDef_OC2 0.00 - 6000.00 0.01 0.50 s Independent(definitive) time delayof OC2

k_OC2 0.30 0.01 0.05 - 999.00 - Time multiplier for thedependent time delayfor OC2

tMin_OC2 0.00 - 6000.00 0.01 0.05 s Minimum operatetime for IEC IDMTcurves for OC2

VCntrlMode_OC2 Voltage controlInput controlVolt/Input controlOff

- Off - Control mode forvoltage controlledOC2 function

VDepMode_OC2 StepSlope

- Step - Voltage dependentmode OC2 (step,slope)

VDepFact_OC2 1.00 0.01 0.02 - 5.00 - Multiplying factor for Ipickup when OC2 is Udependent

ULowLimit_OC2 1.0 - 200.0 0.1 50.0 %UB Voltage low limitsetting OC2 in % ofUbase

UHighLimit_OC2 1.0 - 200.0 0.1 100.0 %UB Voltage high limitsetting OC2 in % ofUbase




353

Parameter Range Step Default Unit DescriptionHarmRestr_OC2 Off

On- Off - Enable block of OC2

by 2nd harmonicrestrain

DirMode_OC2 Non-directionalForwardReverse

- Non-directional - Directional mode ofOC2 (nondir,forward,reverse)

DirPrinc_OC2 I&UIcosPhi&U

- I&U - Measuring on IandUor IcosPhiandU forOC2

ActLowVolt2_VM Non-directionalBlockMemory

- Non-directional - Low voltage levelaction for Dir_OC2(Nodir, Blk, Mem)

Operation_UC1 OffOn

- Off - Operation UC1 Off /On

EnBlkLowI_UC1 OffOn

- Off - Enable internal lowcurrent level blockingfor UC1

BlkLowCurr_UC1 0 - 150 1 20 %IB Internal low currentblocking level for UC1in % of Ibase

StartCurr_UC1 2.0 - 150.0 1.0 70.0 %IB Operate undercurrentlevel for UC1 in % ofIbase

tDef_UC1 0.00 - 6000.00 0.01 0.50 s Independent(definitive) time delayof UC1

tResetDef_UC1 0.00 - 6000.00 0.01 0.00 s Reset time delay usedin IEC Definite Timecurve UC1

HarmRestr_UC1 OffOn

- Off - Enable block of UC1by 2nd harmonicrestrain

Operation_UC2 OffOn

- Off - Operation UC2 Off /On

EnBlkLowI_UC2 OffOn

- Off - Enable internal lowcurrent level blockingfor UC2

BlkLowCurr_UC2 0 - 150 1 20 %IB Internal low currentblocking level for UC2in % of Ibase

StartCurr_UC2 2.0 - 150.0 1.0 70.0 %IB Operate undercurrentlevel for UC2 in % ofIbase

tDef_UC2 0.00 - 6000.00 0.01 0.50 s Independent(definitive) time delayof UC2

HarmRestr_UC2 OffOn

- Off - Enable block of UC2by 2nd harmonicrestrain

Operation_OV1 OffOn

- Off - Operation OV1 Off /On

StartVolt_OV1 2.0 - 200.0 0.1 150.0 %UB Operate voltage levelfor OV1 in % of Ubase




REG 670

Parameter Range Step Default Unit DescriptionCurveType_OV1 Definite time

Inverse curve AInverse curve BInverse curve CProg. inv. curve

- Definite time - Selection of timedelay curve type forOV1

tDef_OV1 0.00 - 6000.00 0.01 1.00 s Operate time delay insec for definite timeuse of OV1

tMin_OV1 0.00 - 6000.00 0.01 0.05 s Minimum operatetime for IDMT curvesfor OV1

k_OV1 0.30 0.01 0.05 - 999.00 - Time multiplier for thedependent time delayfor OV1

Operation_OV2 OffOn

- Off - Operation OV2 Off /On

StartVolt_OV2 2.0 - 200.0 0.1 150.0 %UB Operate voltage levelfor OV2 in % of Ubase

CurveType_OV2 Definite timeInverse curve AInverse curve BInverse curve CProg. inv. curve

- Definite time - Selection of timedelay curve type forOV2

tDef_OV2 0.00 - 6000.00 0.01 1.00 s Operate time delay insec for definite timeuse of OV2

tMin_OV2 0.00 - 6000.00 0.01 0.05 s Minimum operatetime for IDMT curvesfor OV2

k_OV2 0.30 0.01 0.05 - 999.00 - Time multiplier for thedependent time delayfor OV2

Operation_UV1 OffOn

- Off - Operation UV1 Off /On

StartVolt_UV1 2.0 - 150.0 0.1 50.0 %UB Operate undervoltagelevel for UV1 in % ofUbase

CurveType_UV1 Definite timeInverse curve AInverse curve BProg. inv. curve

- Definite time - Selection of timedelay curve type forUV1

tDef_UV1 0.00 - 6000.00 0.01 1.00 s Operate time delay insec for definite timeuse of UV1

tMin_UV1 0.00 - 6000.00 0.01 0.05 s Minimum operatetime for IDMT curvesfor UV1

k_UV1 0.30 0.01 0.05 - 999.00 - Time multiplier for thedependent time delayfor UV1

EnBlkLowV_UV1 OffOn

- On - Enable internal lowvoltage level blockingfor UV1




355

Parameter Range Step Default Unit DescriptionBlkLowVolt_UV1 0.0 - 5.0 0.1 0.5 %UB Internal low voltage

blocking level for UV1in % of Ubase

Operation_UV2 OffOn

- Off - Operation UV2 Off /On

StartVolt_UV2 2.0 - 150.0 0.1 50.0 %UB Operate undervoltagelevel for UV2 in % ofUbase

CurveType_UV2 Definite timeInverse curve AInverse curve BProg. inv. curve

- Definite time - Selection of timedelay curve type forUV2

tDef_UV2 0.00 - 6000.00 0.01 1.00 s Operate time delay insec for definite timeuse of UV2

tMin_UV2 0.00 - 6000.00 0.01 0.05 s Minimum operatetime for IDMT curvesfor UV2

k_UV2 0.30 0.01 0.05 - 999.00 - Time multiplier for thedependent time delayfor UV2

EnBlkLowV_UV2 OffOn

- On - Enable internal lowvoltage level blockingfor UV2

BlkLowVolt_UV2 0.0 - 5.0 0.1 0.5 %UB Internal low voltageblocking level for UV2in % of Ubase

Table 110: Advanced parameter group settings for the CVGAPC (GF01-) function

Parameter Range Step Default Unit DescriptionCurrMult_OC1 2.0 0.1 1.0 - 10.0 - Multiplier for scaling

the current settingvalue for OC1

ResCrvType_OC1 InstantaneousIEC ResetANSI reset

- Instantaneous - Selection of resetcurve type for OC1

tResetDef_OC1 0.00 - 6000.00 0.01 0.00 s Reset time delay usedin IEC Definite Timecurve OC1

P_OC1 0.020 0.001 0.001 - 10.000 - Parameter P forcustomerprogrammable curvefor OC1

A_OC1 0.140 0.001 0.000 - 999.000 - Parameter A forcustomerprogrammable curvefor OC1

B_OC1 0.000 0.001 0.000 - 99.000 - Parameter B forcustomerprogrammable curvefor OC1




REG 670

Parameter Range Step Default Unit DescriptionC_OC1 1.000 0.001 0.000 - 1.000 - Parameter C for

customerprogrammable curvefor OC1

PR_OC1 0.500 0.001 0.005 - 3.000 - Parameter PR forcustomerprogrammable curvefor OC1

TR_OC1 13.500 0.001 0.005 - 600.000 - Parameter TR forcustomerprogrammable curvefor OC1

CR_OC1 1.0 0.1 0.1 - 10.0 - Parameter CR forcustomerprogrammable curvefor OC1

CurrMult_OC2 2.0 0.1 1.0 - 10.0 - Multiplier for scalingthe current settingvalue for OC2

ResCrvType_OC2 InstantaneousIEC ResetANSI reset

- Instantaneous - Selection of resetcurve type for OC2

tResetDef_OC2 0.00 - 6000.00 0.01 0.00 s Reset time delay usedin IEC Definite Timecurve OC2

P_OC2 0.020 0.001 0.001 - 10.000 - Parameter P forcustomerprogrammable curvefor OC2

A_OC2 0.140 0.001 0.000 - 999.000 - Parameter A forcustomerprogrammable curvefor OC2

B_OC2 0.000 0.001 0.000 - 99.000 - Parameter B forcustomerprogrammable curvefor OC2

C_OC2 1.000 0.001 0.000 - 1.000 - Parameter C forcustomerprogrammable curvefor OC2

PR_OC2 0.500 0.001 0.005 - 3.000 - Parameter PR forcustomerprogrammable curvefor OC2

TR_OC2 13.500 0.001 0.005 - 600.000 - Parameter TR forcustomerprogrammable curvefor OC2

CR_OC2 1.0 0.1 0.1 - 10.0 - Parameter CR forcustomerprogrammable curvefor OC2




357

Parameter Range Step Default Unit DescriptiontResetDef_UC2 0.00 - 6000.00 0.01 0.00 s Reset time delay used

in IEC Definite Timecurve UC2

ResCrvType_OV1 InstantaneousFrozen timerLinearlydecreased

- Instantaneous - Selection of resetcurve type for OV1

tResetDef_OV1 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for definite timeuse of OV1

tResetIDMT_OV1 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for IDMT curvesfor OV1

A_OV1 0.140 0.001 0.005 - 999.000 - Parameter A forcustomerprogrammable curvefor OV1

B_OV1 1.000 0.001 0.500 - 99.000 - Parameter B forcustomerprogrammable curvefor OV1

C_OV1 1.000 0.001 0.000 - 1.000 - Parameter C forcustomerprogrammable curvefor OV1

D_OV1 0.000 0.001 0.000 - 10.000 - Parameter D forcustomerprogrammable curvefor OV1

P_OV1 0.020 0.001 0.001 - 10.000 - Parameter P forcustomerprogrammable curvefor OV1

ResCrvType_OV2 InstantaneousFrozen timerLinearlydecreased

- Instantaneous - Selection of resetcurve type for OV2

tResetDef_OV2 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for definite timeuse of OV2

tResetIDMT_OV2 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for IDMT curvesfor OV2

A_OV2 0.140 0.001 0.005 - 999.000 - Parameter A forcustomerprogrammable curvefor OV2

B_OV2 1.000 0.001 0.500 - 99.000 - Parameter B forcustomerprogrammable curvefor OV2

C_OV2 1.000 0.001 0.000 - 1.000 - Parameter C forcustomerprogrammable curvefor OV2




REG 670

Parameter Range Step Default Unit DescriptionD_OV2 0.000 0.001 0.000 - 10.000 - Parameter D for

customerprogrammable curvefor OV2

P_OV2 0.020 0.001 0.001 - 10.000 - Parameter P forcustomerprogrammable curvefor OV2

ResCrvType_UV1 InstantaneousFrozen timerLinearlydecreased

- Instantaneous - Selection of resetcurve type for UV1

tResetDef_UV1 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for definite timeuse of UV1

tResetIDMT_UV1 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for IDMT curvesfor UV1

A_UV1 0.140 0.001 0.005 - 999.000 - Parameter A forcustomerprogrammable curvefor UV1

B_UV1 1.000 0.001 0.500 - 99.000 - Parameter B forcustomerprogrammable curvefor UV1

C_UV1 1.000 0.001 0.000 - 1.000 - Parameter C forcustomerprogrammable curvefor UV1

D_UV1 0.000 0.001 0.000 - 10.000 - Parameter D forcustomerprogrammable curvefor UV1

P_UV1 0.020 0.001 0.001 - 10.000 - Parameter P forcustomerprogrammable curvefor UV1

ResCrvType_UV2 InstantaneousFrozen timerLinearlydecreased

- Instantaneous - Selection of resetcurve type for UV2

tResetDef_UV2 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for definite timeuse of UV2

tResetIDMT_UV2 0.00 - 6000.00 0.01 0.00 s Reset time delay insec for IDMT curvesfor UV2

A_UV2 0.140 0.001 0.005 - 999.000 - Parameter A forcustomerprogrammable curvefor UV2




359

Parameter Range Step Default Unit DescriptionB_UV2 1.000 0.001 0.500 - 99.000 - Parameter B for

customerprogrammable curvefor UV2

C_UV2 1.000 0.001 0.000 - 1.000 - Parameter C forcustomerprogrammable curvefor UV2

D_UV2 0.000 0.001 0.000 - 10.000 - Parameter D forcustomerprogrammable curvefor UV2

P_UV2 0.020 0.001 0.001 - 10.000 - Parameter P forcustomerprogrammable curvefor UV2

4.11 Secondary system supervision

4.11.1 Current circuit supervision (RDIF)

Function block name: CCSx- IEC 60617 graphical symbol: ANSI number:

IEC 61850 logical node name: CCSRDIF


Open or short circuited current transformer cores can cause unwanted operation ofmany protection functions such as differential, earth fault current and negativesequence current functions. When currents from two independent 3-phase sets ofCT’s, or CT cores, measuring the same primary currents are available, reliable currentcircuit supervision can be arranged by comparing the currents from the two sets. Ifan error in any CT circuit is detected, the protection functions concerned can beblocked and an alarm given.

In case of large currents, unequal transient saturation of CT cores with differentremanence or different saturation factor may result in differences in the secondarycurrents from the two CT sets. Unwanted blocking of protection functions during thetransient stage must then be avoided.

The supervision function must be sensitive and have short operate time in order toprevent unwanted tripping from fast-acting, sensitive numerical protections in caseof faulty CT secondary circuits.

Open CT circuits creates extremely high voltages in the circuits whichmay damage the insulation and cause new problems.



REG 670

The application shall thus be done with this in consideration, speciallyif protection functions are blocked.


The CCS function compares the residual current from a three phase set of currenttransformer cores with the neutral point current on a separate input taken from anotherset of cores on the same current transformer.

The minimum operate current, IMinOp, should as a minimum be set to twice theresidual current in the supervised CT circuits under normal service conditions andrated primary current.

The parameter Ip>Block is normally set at 150% in order to block the function duringtransient conditions.

The FAIL output is connected in the CAP configuration to the blocking input of theprotection function to be blocked at faulty CT secondary circuits.


Table 111: Basic parameter group settings for the CCSRDIF (CCS1-) function



IBase 1 - 99999 1 3000 A IBase value forcurrent leveldetectors

IMinOp 5 - 200 1 20 %IB Minimum operatecurrent differentiallevel in % of IBase

Table 112: Advanced parameter group settings for the CCSRDIF (CCS1-) function

Parameter Range Step Default Unit DescriptionIp>Block 5 - 500 1 150 %IB Block of the function

at high phase current,in % of IBase

4.11.2 Fuse failure supervision (RFUF)

Function block name: FSDx- IEC 60617 graphical symbol: ANSI number:

IEC 61850 logical node name: SDDRFUF



361


Different protection functions within the protection IED, operates on the basis of themeasured voltage in the relay point. Examples are:

• distance protection function• under/over-voltage function• synchrocheck function and voltage check for the weak infeed logic.

These functions can operate unnecessarily if a fault occurs in the secondary circuitsbetween the voltage instrument transformers and the IED.

It is possible to use different measures to prevent such unwanted operations. Miniaturecircuit breakers in the voltage measuring circuits, located as close as possible to thevoltage instrument transformers, are one of them. Separate fuse-failure monitoringrelays or elements within the protection and monitoring devices are anotherpossibilities. These solutions are combined to get the best possible effect in the fusefailure supervision function (FSD).

The fuse-failure supervision function as built into the IED products can operate onthe basis of external binary signals from the miniature circuit breaker or from the linedisconnector. The first case influences the operation of all voltage-dependentfunctions while the second one does not affect the impedance measuring functions.

The negative sequence detection algorithm, based on the negative-sequencemeasuring quantities, a high value of voltage 3 U2 without the presence of thenegative-sequence current 3 I2, is recommended for use in isolated or high-impedanceearthed networks.

The zero sequence detection algorithm, based on the zero sequence measuringquantities, a high value of voltage 3 U0 without the presence of the residual current3 I0, is recommended for use in directly or low impedance earthed networks. Acriterion based on delta current and delta voltage measurements can be added to thefuse failure supervision function in order to detect a three phase fuse failure, whichin practice is more associated with voltage transformer switching during stationoperations. In cases where the line can have a weak-infeed of zero sequence currentthis function shall be avoided.

A separate operation mode selector OpMode has been introduced for better adaptationto system requirements. The mode selector makes it possible to select interactionsbetween the negative sequence and zero sequence algorithm. In normal applicationsthe OpMode is set to either UNsINs for selecting negative sequence algorithm orUZsIZs for zero sequence based algorithm. If system studies or field experiencesshows that there is a risk that the fuse failure function will not be activated due to thesystem conditions, the dependability of the fuse failure function can be increased ifthe OpMode is set to UZsIZs OR UNsINs or OptimZsNs. In mode UZsIZs ORUNsINs both the negative and zero sequence based algorithm is activated and workingin an OR-condition. Also in mode OptimZsNs both the negative and zero sequencealgorithm are activated and the one that has the highest magnitude of measurednegative sequence current will operate.



REG 670

If there is a requirement to increase the security of the fuse failure functionOpMode can be selected to UZsIZs AND UNsINs which gives that both negative andzero sequence algorithm is activated working in an AND-condition, i.e. bothalgorithm must give condition for block in order to activate the output signalsBLKU or BLKZ.


GeneralThe negative and zero sequence voltages and currents always exist due to differentnon-symmetries in the primary system and differences in the current and voltageinstrument transformers. The minimum value for the operation of the current andvoltage measuring elements must always be set with a safety margin of 10 to 20%,depending on the system operating conditions.

Pay special attention to the dissymmetry of the measuring quantities when thefunction is used on longer untransposed lines, on multicircuit lines and so on.

Setting of common parametersThe settings of negative sequence, zero sequence and delta algorithm are in percentof the base voltage and base current for the function, UBase and IBase respectively.Set UBase to the primary rated voltage of the potential voltage transformer windingand IBase to the primary rated current of the current transformer winding.

The voltage threshold UPh> is used to identify low voltage condition in the system.Set UPh> below the minimum operating voltage that might occur during emergencyconditions. We propose a setting of approximately 70% of UBase.

Negative sequence basedThe setting of 3U2> should not be set lower than according to equation 160.

ΔU23U2 100UBase

> = ×(Equation 160)

where:

DU2 is maximal negative sequence voltage during normal operation condition

UBaseVBase is setting of base voltage for the function

The setting of the current limit 3I2> is done in percentage of IBase. The setting of3I2> must be higher than the normal unbalance current that might exist in the system.The setting can be calculated according to equation 161.

I23I2 100IBaseD


where:



363

DI2 is maximal negative sequence current during normal operating condition

IBase is setting of base current for the function

Zero sequence basedThe relay setting value 3U0> is given in percentage of the base voltage UBase, whereUBase is the primary base voltage, normally the rated voltage of the primary potentialvoltage transformer winding. The setting of 3U0> should not be set lower thanaccording to equation 162.

1003U0 ΔU0UBase


where:

DU0 is maximal zero sequence voltage during normal operation condition

UBase is setting of base voltage for the function

The setting of the current limit 3I0> is done in percentage of IBase, where IBase isthe primary base current, normally the rated current of the primary current transformerwinding. The setting of 3I2> must be higher than the normal unbalance current thatmight exist in the system. The setting can be calculated according to equation 163.

I03I0 s 100IBaseD

> = × ×(Equation 163)

where:

DI0 is maximal negative sequence current during normal operating condition

IBase is setting of base current for the function

dudv/dt and di/dtThe setting of du/dt is done in percentage of UBase, where UBase is the primary basevoltage, normally the rated voltage of the primary potential voltage transformerwinding. The setting of DU> should be set high (approximately 60% of UBase) toavoid unwanted operation and the current threshold dI/dt low (approximately 10% ofIBase) but higher than the setting of IMinOp (the minimum operate current of theIED). It shall always be used together with either the negative or zero sequencealgorithm. If USetprim is the primary voltage for operation of dU/dt and ISetprim theprimary current for operation of dI/dt, the setting of DU> and DI> will be givenaccording to equation 164 and equation 165.

primUSetDU 100UBase




REG 670

primISetDI 100IBase


Set the operation mode selector OperationDUDI to On if the delta function shall bein operation.

The current threshold IPh> shall be set lower than the IMinOp for the distanceprotection function. A 5-10% lower value is recommended.

Dead line detectionThe condition for operation of the dead line detection is set by the parametersIDLD< for the current threshold and UDLD< for the voltage threshold.

Set the IDLD< with a sufficient margin below the minimum expected load current.A safety margin of at least 15-20% is recommended. The operate value must howeverexceed the maximum charging current of an overhead line, when only one phase isdisconnected (mutual coupling to the other phases).

Set the UDLD< with a sufficient margin below the minimum expected operatingvoltage. A safety margin of at least 15% is recommended.


Table 113: Basic parameter group settings for the SDDRFUF (FSD1-) function


On- On - Operation Off / On



OpMode OffUNsINsUZsIZsUZsIZs ORUNsINsUZsIZs ANDUNsINsOptimZsNs

- UZsIZs - Operating modeselection

3U0> 1 - 100 1 30 %UB Operate level ofresidual overvoltageelement in % ofUBase

3I0< 1 - 100 1 10 %IB Operate level ofresidual undercurrentelement in % of IBase

3U2> 1 - 100 1 30 %UB Operate level of negseq overvoltageelement in % ofUBase




365

Parameter Range Step Default Unit Description3I2< 1 - 100 1 10 %IB Operate level of neg

seq undercurrentelement in % of IBase

OpDUDI OffOn

- Off - Operation of changebased function Off/On

DU> 1 - 100 1 60 %UB Operate level ofchange in phasevoltage in % of UBase

DI< 1 - 100 1 15 %IB Operate level ofchange in phasecurrent in % of IBase

UPh> 1 - 100 1 70 %UB Operate level ofphase voltage in % ofUBase

IPh> 1 - 100 1 10 %IB Operate level ofphase current in % ofIBase

SealIn OffOn

- On - Seal in functionalityOff/On

USealln< 1 - 100 1 70 %UB Operate level of seal-in phase voltage in %of UBase

IDLD< 1 - 100 1 5 %IB Operate level for openphase currentdetection in % ofIBase

UDLD< 1 - 100 1 60 %UB Operate level for openphase voltagedetection in % ofUBase

4.12 Control

4.12.1 Synchronizing, synchrocheck and energizing check (RSYN,25)

Function block name: SYNx- IEC 60617 graphical symbol:

sc/vc

ANSI number: 25

IEC 61850 logical node name:SESRSYN



REG 670


SynchronizingTo allow closing of breakers between asynchronous networks a synchronizingfunction is provided. The breaker close command is issued at the optimum time whenconditions across the breaker are satisfied in order to avoid stress on the network andits components.

The systems are defined to be asynchronous when the frequency difference betweenbus and line is larger than an adjustable parameter. If the frequency difference is lessthan this threshold value the system is defined to have a parallel circuit and thesynchrocheck function is used.

The synchronizing function measures the difference between the U-line and the U-bus. It operates and enables a closing command to the circuit breaker when thecalculated closing angle is equal to the measured phase angle and the followingconditions are simultaneously fulfilled:

• The voltages U-line and U-bus are higher than the set value forUHighBusSynch and UHighLineSynch of the base voltage UBase.

• The difference in the voltage is smaller than the set value of UDiffSynch.• The difference in frequency is less than the set value of FreqDiffMax and larger

than the set value of FreqDiffMin. If the frequency is less than FreqDiffMin thesynchrocheck is used and the value of FreqDiffMin must thus be identical to thevalue FreqDiffM resp FreqDiffA for synchronism check function. The bus andline frequencies must also be within a range of +/- 5 Hz from the rated frequency.When the synchronizing option is included also for auto-reclose there is no reasonto have different frequency setting for the manual and automatic Reclosing andthe frequency difference values for synchronism check should be kept low.

• The frequency rate of change is less than set value for both U-bus and U-line.• The closing angle is decided by the calculation of slip frequency and required

pre-closing time.

The synchronizing function compensates for measured slip frequency as well as thecircuit breaker closing delay. The phase advance is calculated continuously. Closingangle is the change in angle during the set breaker closing operate time tBreaker.

The reference voltage can be phase-neutral L1, L2, L3 or phase-phase L1-L2, L2-L3,L3-L1. The bus voltage must then be connected to the same phase or phases as arechosen on the HMI or a compensation angle set to compensate for the difference.

SynchrocheckThe main purpose of the synchrocheck function is to provide control over the closingof circuit breakers in power networks in order to prevent closing if conditions forsynchronism are not detected. It is also used to prevent the re-connection of twosystems, which are divided after islanding and after a three pole reclosing.



367

Single pole auto-reclosing does not require any synchrocheck sincethe system is tied together by two phases.

The synchrocheck function block includes both the synchronism check function andthe energizing function to allow closing when one side of the breaker is dead. Thesynchrocheck function also includes a built in voltage selection scheme which allowssimple application in all types of busbar arrangements.

~ ~~~ ~~

en04000179.vsd

Figure 133: Two interconnected power systems

Figure 133 shows two interconnected power systems. The cloud means that theinterconnection can be further away, i.e. a weak connection through other stations.The need for a synchronization check increases as the meshed system decreases sincethe risk of the two networks being out of synchronization at manual or automaticclosing is greater.

The synchrocheck function measures the conditions across the circuit breaker andcompares them to set limits. Output is only generated when all measured conditionsare within their set limits simultaneously. The check consists of:

• Live line and live bus.• Voltage level difference.• Frequency difference (slip). The bus and line frequency must also be within a

range of ±5 Hz from rated frequency.• Phase angle difference.

A time delay is available to ensure that the conditions are fulfilled for a minimumperiod of time.

In very stable power systems the frequency difference is insignificant or zero formanually initiated closing or closing by automatic restoration. In steady conditions abigger phase angle difference can be allowed as this is sometimes the case in a longand loaded parallel power line. For this application we accept a synchrocheck with along operation time and high sensitivity regarding the frequency difference. The phaseangle difference setting can be set for steady state conditions.

Another example, is when the operation of the power net is disturbed and high-speedauto-reclosing after fault clearance takes place. This can cause a power swing in thenet and the phase angle difference may begin to oscillate. Generally, the frequencydifference is the time derivative of the phase angle difference and will, typicallyoscillate between positive and negative values. When the circuit breaker needs to be



REG 670

closed by auto-reclosing after fault-clearance some frequency difference should betolerated, to a greater extent than in the steady condition mentioned in the case above.But if a big phase angle difference is allowed at the same time, there is some risk thatauto-reclosing will take place when the phase angle difference is big and increasing.In this case it should be safer to close when the phase angle difference is smaller.

To fulfill the above requirements the synchrocheck function is provided withduplicate settings, one for steady (Manual) conditions and one for operation underdisturbed conditions (Auto).

SynchroCheckUHighBusSC > 50 - 120 % of UbUHighLineSC > 50 - 120 % of UbUDiffSC < 2 - 50 % of UbPhaseDiffM < 5 - 90 degreesPhaseDiffA < 5 - 90 degreesFreqDiffM < 3 - 1000 mHzFreqDiffA < 3 - 1000 mHz

Fuse fail

Fuse fail

Line voltage Linereferencevoltage

Bus voltage

en07000090.vsd

Figure 134: Principle for the synchrocheck function

Energizing checkThe main purpose of the energizing check function is to facilitate the controlled re-connection of disconnected lines and buses to energized lines and buses.

The energizing check function measures the bus and line voltages and compares themto both high and low threshold values. The output is only given when the actualmeasured conditions match the set conditions. Figure 135 shows two power systems,where one (1) is energized and the other (2) is not energized. Power system 2 isenergized (DLLB) from system 1 via the circuit breaker A.



369

~1 2

A B

EnergizingCheckUHighBusEnerg > 50 - 120 % of UbUHighLineEnerg > 50 - 120 % of UbULowBusEnerg < 10 - 80 % of UbULowLineEnerg < 10 - 80 % of UbUMaxEnerg < 80 - 140 % of Ub

LinevoltageBus voltage

en07000091.vsd

Figure 135: Principle for the energizing check function

The energizing operation can operate in the dead line live bus (DLLB) direction, deadbus live line (DBLL) direction or in both directions over the circuit breaker.Energizing from different directions can be different for automatic reclosing andmanual closing of the circuit breaker. For manual closing it is also possible to allowclosing when both sides of the breaker are dead, Dead Bus Dead Line (DBDL).

The equipment is considered energized if the voltage is above a set value, e.g. 80%of the base voltage, and non-energized if it is below a set value, e.g. 30% of the basevoltage. A disconnected line can have a considerable potential because of factors suchas induction from a line running in parallel, or feeding via extinguishing capacitorsin the circuit breakers. This voltage can be as high as 50% or more of the base voltageof the line. Normally for breakers with single breaking elements (<330kV) the levelis well below 30%.

When the energizing direction corresponds to the settings, the situation has to remainconstant for a certain period of time before the close signal is permitted. The purposeof the delayed operate time is to ensure that the dead side remains de-energized andthat the condition is not due to temporary interference.

Voltage selectionThe voltage selection function is used for the connection of appropriate voltages tothe synchrocheck and energizing check functions. For example, when the IED is usedin a double bus arrangement, the voltage that should be selected depends on the statusof the breakers and/or disconnectors. By checking the status of the disconnectorsauxiliary contacts, the right voltages for the synchrocheck and energizing checkfunctions can be selected. Available voltage selection types are for single circuitbreaker with double busbars and the 1 1/2 circuit breaker arrangement. A doublecircuit breaker arrangement and single circuit breaker with a single busbar do notneed any voltage selection function. Neither does a single circuit breaker with doublebusbars using external voltage selection need any internal voltage selection.



REG 670

The voltages from busbars and lines must be physically connected to the voltageinputs in the IED and connected, using the control software, to each of the maximumtwo synchrocheck functions available in the IED.

External fuse failureExternal fuse-failure signals or signals from a tripped fuse switch/MCB are connectedto binary inputs that are configured to inputs of the synchrocheck functions in theIED. The internal fuse failure supervision module can also be used, for at least theline voltage supply. The signal FUSE-VTSU is then used and connected to theblocking input of the energizing check function block. In case of a fuse failure, thesynchrocheck and energizing check functions are blocked.

The SYN1(2)-UB1/2OK and SYN1(2)-UB1inputs are related to the busbar voltageand the SYN1(2)-ULN1/2OK and SYN1(2)-ULN/2FF inputs are related to the linevoltage.

Eternal selection of energizing direction.The energizing can be selected by use of the available logic function blocks. Belowis an example where the choice of mode is done from a symbol on the local HMIthrough selector switch function block, but alternatively there can e.g. be a physicalselector switch on the front of the panel which is connected to a binary to integerfunction block (B16I).

If the PSTO input is used, connected to the Local-Remote switch on the LHMI, thechoice can also be from the station HMI system, typically ABB Microscada throughIEC 61850 communication.

The connection example for selection of the manual energizing mode is shown infigure 136. Selected names are just examples but note that the symbol on LHMI canonly show three signs.

en07000118.vsd

SYN1(1701,8)SESRSYN_25

MENMODE

INTONE PSTO

SWPOSNNAME1NAME2OFF

DLDBDLB

SL01(180,100)SLGGIO

NAME3NAME4

Figure 136: Selection of the energizing direction from a LHMI symbol through aselector switch function block.

4.12.1.2 Application examples

The synchrocheck function block can also be used in some switchyard arrangements,but with different parameter settings. Below are some examples of how differentarrangements are connected to the IED analogue inputs and to the function block



371

(SPN). One function block is used per circuit breaker. The IED can be provided withone, two or three function blocks.

The input used below in example are typical and can be changed byuse of configuration and signal matrix tools.

Single circuit breaker with single busbar

Line

SESRSYN_25SYN1-

U3PBB1U3PBB2U3PLN1U3PLN2BLOCKBLKSYNCHBLKSCBLKENERGB1QOPENB1QCLDB2QOPENB2QCLDLN1QOPENLN1QCLDLN2QOPENLN2QCLDUB1OKUB1FFUB2OKUB2FFULN1OKULN1FFULN2OKULN2FFSTARTSYNTSTSYNCHTSTSCTSTENERGAENMODEMENMODE

SYNOKAUTOSYOKAUTOENOK

MANSYOKMANENOK

TSTSYNOKTSTAUTSYTSTMANSY

TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL

SYNPROGRSYNFAILUOKSYN

UDIFFSYNFRDIFSYNFRDIFFOKFRDERIVA

UOKSCUDIFFSCFRDIFFAPHDIFFAFRDIFFMPHDIFFMUDIFFME

FRDIFFMEPHDIFFMEMODEAENMODEMEN

lineVoltage/1/2/3

bus1Voltage

Bus 1

QB1

UREF1

UL1/UL2/UL3

QA1

FuseVT

FuseVT

en07000092.vsd

Figure 137: Connection of the Synchrocheck function block in a single busbararrangement

Figure 137 illustrates connection principles. For the synchrocheck and energizingcheck function (SPN1), there is one voltage transformer on each side of the circuitbreaker. The voltage transformer circuit connections are straightforward; no specialvoltage selection is necessary. For the synchrocheck and energizing check, the voltagefrom the busbar VT is connected to the single phase analog input UREF1 (CH10) onthe analog input module AIM1 (also referred to as TRM). The line voltage isconnected as a three-phase voltage to the analog inputs UL1 (CH07), UL2 (CH08),UL3 (CH09) on the module AIM1. Inputs and outputs not used in the function blockare dimmed in the figure. The voltage selection parameter CBConfig is set to Novoltage selection.



REG 670

Single circuit breaker with double busbar, external voltage selection

lineVoltage/1/2/3

bus Voltage

Bus 1Bus 2

QB1

QB2

Line

UREF1

UL1/UL2/UL3

QA1

FuseVT

FuseVT

FuseVT

SESRSYN _25SYN1-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





en07000093.vsd

Figure 138: Connection of the Synchrocheck function block in a single breaker,double busbar arrangement with external voltage selection.

In this type of arrangement no internal voltage selection is required. The voltageselection is made by external relays typically connected according to figure 138.Suitable voltage and VT fuse failure supervision from the two busbars are selectedbased on the position of the busbar disconnectors. That means that the connectionsto the function block will be the same as for the single busbar arrangement. Thevoltage selection parameter CBConfig is set to “No voltage selection”.



373

Single circuit breaker with double busbar, internal voltage selection

lineVoltage/1/2/3

bus1Voltage

bus2Voltage

Bus 1Bus 2

QB1

QB2

Line

UREF1UREF2

UL1/UL2/UL3

QA1

FuseVT

FuseVT

FuseVT

en07000095.vsd

SESRSYN _25SYN 1-

U3 PBB 1U3 PBB 2U3 PLN 1U3 PLN 2BLOCKBLKSYNCHBLKSCBLKENERGB1 QOPENB1 QCLDB2 QOPENB2 QCLDLN1 QOPENLN1 QCLDLN2 QOPENLN2 QCLDUB1OKUB1FFUB2OKUB2FFULN 1OKULN 1FFULN 2OKULN 2FFSTARTSYNTSTSYNCHTSTSCTSTENERGAENMODEMENMODE


MANSYOKMANENOK


TSTENOKUSELFAIL

B1 SELB2 SEL

LN1 SELLN2 SEL





Figure 139: Connection of the Synchrocheck function block in a single breaker,double busbar arrangement with internal voltage selection.

When internal voltage selection is needed, two analog input modules AIM1 (TRM+ADM) and AIM2 (TRM+ADM) are required. The voltage transformer circuitconnections are made according to figure 139. The voltages from the busbar VTs areconnected to the single phase analog input UREF1 (CH10) on the analog input moduleAIM1 and to the single phase analog input UREF2 (CH11) on the analog input moduleAIM2. The line voltage is connected as a three-phase voltage to the analog inputsUL1 (CH07), UL2 (CH08), UL3 (CH09) on the module AIM1. Inputs and outputsnot used in the function block (SPN) are dimmed in the figure. The voltage selectionparameter selectCBConfig is set to single CB, double bus.



REG 670

Double circuit breaker

lineVoltage/1/2/3

bus1Voltage

bus2Voltage

Bus 1Bus 2

QA1

QA2

Line

UREF1

UREF2

UL1/UL2/UL3

FuseVT

FuseVT

FuseVT QA1

QA2en07000096.vsd

SESRSYN_25SYN1-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





SESRSYN_25SYN2-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





Figure 140: Voltage connections in a double breaker arrangement

A double breaker arrangement requires two function blocks SPN1 and SPN2. Novoltage selection is necessary, because the two busbar reference voltages UREF1(CH10) and UREF2 (CH11) are references for two circuit breakers according to figure140. The line voltage is connected as a three-phase voltage to the analog inputsUL1,UL2, UL3 on the analog input module AIM1. Inputs and outputs not used in thefunction block (SPN) are dimmed in the figure. The voltage selection parameterselectCBConfig is set to NO VOLTAGE SELECTION for both SPN1 and SPN2.

1 1/2 circuit breakerThe line one IED in a 1 ½ breakerarrangement handles voltage selection for twocircuit breakers, one bus CB and the tie CB. The IED requires one or two analog inputmodules AIM1 (TRM+ADM) and AIM2 (TRM+ADM) and two function blocks



375

SPN1 and SPN2. All voltages for the whole diameter should be connected to bothIEDs in the diameter respectively.

Bus 1 CB

Tie CB

UREF1

UREF2

UL1/UL2/UL3

FuseVTbus1Voltage

FuseVTbus2Voltage

QA1 QA1

FuseVT

FuseVT

line1Voltage1/2/3

line2Voltage

QA1

QB9QB9

Line 1 Line 2

QB1

QB2

QB1

QB2

QB61 QB62

UREF3

Bus 1Bus 2 SESRSYN_25

SYN1-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





SESRSYN_25SYN2-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





en07000097.vsd

Figure 141: Voltage connections in a1 ½ breaker arrangement for the line 1 IED



REG 670

Bus 2 CB

UREF1

UREF2

UL1/UL2/UL3

FuseVTbus1Voltage

FuseVTbus2Voltage

QA1 QA1

FuseVT

FuseVT

line1Voltage

line2Voltage1/2/3

QA1

QB9QB9

Line 1 Line 2

QB1

QB2

QB1

QB2

QB61 QB62

UREF3

Bus 1Bus 2

Tie CBen07000098.vsd

SESRSYN_25SYN1-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





SESRSYN_25SYN2-



MANSYOKMANENOK


TSTENOKUSELFAIL

B1SELB2SEL

LN1SELLN2SEL





Figure 142: Voltage connections in a 1 ½ breaker arrangement for the line 2 IED

The example shows the use of the Synchrocheck function for the TieCircuit breaker in both Line IEDs. This depends on the arrangementof Auto-reclose and manual closing and might often not be required.

Connecting and configuring is done according to figure 141 and figure 142. Theconnections are similar in both IEDs, apart from the line voltages and the bus voltages,which are crossed. This means that the three-phase line voltages UL1, UL2 andUL3 for line 1and F3 for line 2 in the line 1 IED are crossed in the line 2 IED. Also,the bus voltage connections to both the IEDs are crossed. The physical analogconnections of voltages and the connection to the SYN1 and SYN2 function blocksmust be carefully checked in the PCM. In both IEDs the connections andconfigurations must abide by the following rules: Normally apparatus position isconnected with contacts showing both open (b-type) and closed positions (a-type).

Bus CB:



377

• B1QOPEN/CLD = Position of the tie CB and disconnectors• B2QOEN/CLD = Position of opposite bus CB and disconnectors• LN1QOPEN/CLD = Position of own line disconnector• LN2QOPEN/CLD = Position of opposite line disconnector• UB1OK/FF = Supervision of bus VT fuse connected to own bus CB• UB2OK/FF = Supervision of bus VT fuse connected to opposite bus CB• ULN1OK/FF = Supervision of line VT fuse connected to own line• ULN2OK/FF = Supervision of line VT fuse connected to opposite line• Setting CBConfig = 1 1/2 Bus CB

Tie CB:

• B1QOPEN/CLD = Position of own bus CB and disconnectors• B2QOPEN/CLD = Position of opposite bus CB and disconnectors• LN1QOPEN/CLD = Position of own line disconnector• LN2QOPEN/CLD = Position of opposite line disconnector• UB1OK/FF = Supervision of bus VT fuse connected to own bus CB• UB2OK/FF = Supervision of bus VT fuse connected to opposite bus CB• ULN1OK/FF = Supervision of line VT fuse connected to own line• ULN2OK/FF = Supervision of line VT fuse connected to opposite line• CBConfig = Tie CB

If three SPN modules are provided in the same IED, or if preferred for other reason,the system can be set-up without “mirroring” and second bus CB set to 1½ Busalternatively CB. Above standard is so because normally two SPN with the sameconfiguration and settings are provided in a station for each bay.


The setting parameters for the synchronizing, synchrocheck and energizing checkfunction (SYN) are set via the local HMI, or Protection and Control IED Manager(PCM 600) in the PCM. Refer to the Setting parameters table in the next section ofthis chapter.

Operation

The operation mode can be set On/Off from the PST. The setting OFF disables thewhole function.

SelPhaseBus1 and SelPhaseBus2

Configuration parameters for selection of measuring phase of the voltage for busbar1 and 2 respectively, which can be a single-phase (phase-neutral) or two-phase (phase-phase) voltage.

SelPhaseLine1 and SelPhaseLine2



REG 670

Configuration parameters for selection of measuring phase of the voltage for line 1and 2 respectively, which can be a single-phase (phase-neutral) or two-phase (phase-phase) voltage.

CBConfig

This configuration setting is used to define type of voltage selection. Type of voltageselection can be selected as:

• no voltage selection• single circuit breaker with double bus• 1 1/2 circuit breaker arrangement with the breaker connected to busbar 1• 1 1/2 circuit breaker arrangement with the breaker connected to busbar 2• 1 1/2 circuit breaker arrangement with the breaker connected to line 1 and 2 (tie

breaker)

UBase

This is a configuration setting for the base voltage.

PhaseShift

This setting is used to compensate for a phase shift caused by a line transformerbetween the two measurement points for bus voltage and line voltage. The set valueis added to the measured line phase angle. The bus voltage is reference voltage.

URatio

The URatio is defined as URatio=bus voltage/line voltage. A typical use of the settingis to compensate for the voltage difference caused if one wishes to connect the busvoltage phase-phase and line voltage phase-neutral. The SelPhaseBusx setting shouldthen be set to phase-phase and the URatio setting to sqr3=1.73. This setting scalesup the line voltage to equal level with the bus voltage.

OperationSynch

The setting Off disables the Synchronizing function. With the setting On, the functionis in service and the output signal depends on the input conditions.

UHighBusSynch and UHighLineSynch

The voltage level settings shall be chosen in relation to the bus/line network voltage.The threshold voltages UHighBusSynch and UHighLineSynch have to be set smallerthan the value where the network is expected to be synchronized. A typical value is80 % of the rated voltage.

UDiffSynch

Setting of the voltage difference between the line voltage and the bus voltage. Thedifference is set depending on the network configuration and expected voltages in thetwo networks running asynchronous. A normal setting is 10-15% of the rated voltage.



379

FreqDiffMax

The setting FreqDiffMax is the maximum slip frequency at which synchronizing isaccepted. 1/FreqDiffMax shows the time for the vector to move 360 degrees, one turnon the synchronoscope and is called the Beat time A typical value for the FreqDiffMaxis 200-250 mHz which gives beat times on 4-5 seconds. Higher values should beavoided as the two networks normally are regulated to nominal frequencyindependent of each other so the frequency difference shall be small.

FreqDiffMin

The setting FreqDiffMin is the minimum frequency difference where the system aredefined to be asynchronous. For frequency difference lower than this value thesystems are considered to be in parallel. A typical value for the FreqDiffMin is 10mHz. Generally the value should be low if both synchronizing and synchrocheckfunction is provided as it is better to let synchronizing function close as it will closeat the exact right instance if the networks runs with a frequency difference. Thesyncrocheck function will at such a case close to the set phase angle difference valuewhich can be 35 degrees from the correct angle.

Note! The FreqDiffMin shall be set to the same value as FreqDiffM respFreqDiffAfor the Synchrocheck function dependent of whether the functions are used for manualoperation, auto-reclosing or both.

tBreaker

The tBreaker shall be set to match the closing time for the circuit breaker and shouldalso include the possible auxiliary relays in the closing circuit. It is important to checkthat no slow logic components are used in the configuration of the IED as there thencan be big variations in closing time due to those components. Typical setting is80-150 ms depending on the breaker closing time.

tMinSynch

The tMinSynch is set to limit the minimum time at which synchronizing closingattempt is given. The setting will not give a closing should a condition fulfilled occurwithin this time from the synchronizing function is started. Typical setting is 200 ms.

tMaxSynch

The tMaxSynch is set to reset the operation of the synchronizing function if theoperation does not take place within this time. The setting must allow for the settingof FreqDiffMin which will decide how long it will take maximum to reach phaseequality. At a setting of 10ms the beat time is 100 seconds and the setting would thusneed to be at least tMinSynch plus 100 seconds. If the network frequencies areexpected to be outside the limits from start a margin needs to be added. Typical setting300 seconds.

OperationSC



REG 670

The OperationSC setting OFF disables the synchrocheck function and sets the outputsAUTOSYOK, MANSYOK, TSTAUTSY and TSTMANSY to low.

With the setting ON, the function is in service and the output signal depends on theinput conditions.

UHighBusSC and UHighLineSC

The voltage level settings shall be chosen in relation to the bus/line network voltage.The threshold voltages UHighBusSC and UHighLineSC have to be set lower than thevalue at which the breaker is expected to be closed with synchronism check. A typicalvalue may be 80% of the base voltage.

UDiff

Setting for voltage difference between line and bus.

FreqDiffM and FreqDiffA

The frequency difference level settings, FreqDiffM and FreqDiffA, shall be chosendepending on the condition in the network. At steady conditions a low frequencydifference setting is needed, where the FreqDiffM setting is used. Four auto-reclosinga bigger frequency difference setting is preferable, where the FreqDiffA setting isused. A typical value for the FreqDiffM can 10 mHz and a typical value for theFreqDiffA can be 100-200 mHz.

PhaseDiffM and PhaseDiffA

The phase angle difference level settings, PhaseDiffM and PhaseDiffA, shall also bechosen depending on conditions in the network. The phase angle setting must bechosen to allow closing under maximum load condition. A typical maximum valuein heavy loaded networks can be 45 degrees whereas in most networks the maximumoccurring angle is below 25 degrees.

tSCM and tSCA

The purpose of the timer delay settings, tSCM and tSCA, is to ensure that thesynchrocheck conditions remains constant and that the situation is not due to atemporary interference. Should the conditions not persist for the specified time, thedelay timer is reset and the procedure is restarted when the conditions are fulfilledagain. Circuit breaker closing is thus not permitted until the synchrocheck situationhas remained constant throughout the set delay setting time. Under stable conditionsa longer operation time delay setting is needed, where the tSCM setting is used. Duringauto-reclosing a shorter operation time delay setting is preferable, where the tSCAsetting is used. A typical value for the tSCM may be 1 second and a typical value forthe tSCA may be 0.1 second.

AutoEnerg and ManEnerg

Two different settings can be used for automatic and manual closing of the circuitbreaker. The settings for each of them are:



381

• Off, the energizing function is disabled.• DLLB, Dead Line Live Bus, the line voltage is below set value of

ULowLineEnerg and the bus voltage is above set value of UHighBusEnerg.• DBLL, Dead Bus Live Line, the bus voltage is below set value of

ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.• Both, energizing can be done in both directions, DLLB or DBLL.

UHighBusEnerg and UHighLineEnerg

The voltage level settings shall be chosen in relation to the bus/line network voltage.The threshold voltages UHighBusEnerg and UHighLineEnerg, have to be set lowerthan the value at which the network is considered to be energized. A typical valuemay be 80 % of the base voltage.

ULowBusEnerg and ULowLineEnerg

In the same way, the threshold voltages ULowBusEnerg and ULowLineEnerg, haveto be set greater than the value where the network is considered not to be energized.A typical value may be 30% of the base voltage. Note that a disconnected line canhave a considerable potential due to, for instance, induction from a line running inparallel, or by being fed via the extinguishing capacitors in the circuit breakers. Thisvoltage can be as high as 30% or more of the base line voltage.

Because the setting ranges of the threshold voltages UHighBusEnerg/UHighLineEnerg and ULowBusEnerg/ULowLineEnerg partly overlap each other, thesetting conditions may be such that the setting of the non-energized threshold valueis higher than that of the energized threshold value. The parameters should thereforebe set carefully by the user to avoid the setting conditions mentioned above.

tAutoEnerg and tManEnerg

The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure thatthe dead side remains de-energized and that the condition is not due to a temporaryinterference. Should the conditions not persist for the specified time, the delay timeris reset and the procedure is restarted when the conditions are fulfilled again. Circuitbreaker closing is thus not permitted until the energizing condition has remainedconstant throughout the set delay setting time.

ManEnergDBDL

If the parameter is set to On, manual closing is enabled when both line voltage andbus voltage are below ULowLineEnerg and ULowBusEnerg respectively andManEnerg is set to DLLB, DBLL or Both.

UMaxEnerg

This setting is used to block the closing when the voltage on the live side is abovethe set value of UMaxEnerg.

Note that the setting for the preprocessing block connected to synchrocheck functionshall be typically done in the usual way as described in the IED 670 Application



REG 670

Manual under section "Application/Analogue Inputs". However, the only exceptionis when a single phase-to-phase voltage is connected from the bus side to one VTinput of the IED 670, while simultaneously three phase-to-ground voltages areconnected from the line side to another three VT inputs of the IED 670. Under suchcircumstances the following connections and settings are required for thepreprocessing block used for the bus voltage (note that the connection and the settingsfor the preprocessing block used for the line side VT are done in the usual way) inorder to get the proper operation of the synchrocheck function:

1. When voltage UL1L2 is connected from the bus side do the following:• use a dedicated preprocessing block for the bus voltage for the

synchrocheck function (i.e. do not use this preprocessing block for othervoltage functions)

• connect this bus voltage (i.e. UL1L2 ) as the first analogue input of thispreprocessing block in the Signal Matrix Tool

• leave all other analogue inputs into this preprocessing block not connectedin the Signal Matrix Tool

• set this preprocessing block parameter to "ConnectionType=Ph-N" (onlydeviation from standard preprocessing block settings!)

• set all relevant voltage selection settings for synchrocheck function as"phase1-phase2"



• connect this bus voltage (i.e. UL2L3 ) as the second analogue input ofthis preprocessing block in the Signal Matrix Tool






• connect this bus voltage (i.e. UL3L1) as thethird analogue input of thispreprocessing block in the Signal Matrix Tool






383


Table 114: Basic parameter group settings for the SESRSYN_25 (SYN1-) function



SelPhaseBus1 phase1phase2phase3phase1-phase2phase2-phase3phase3-phase1

- phase2 - Select phase for bus1

SelPhaseBus2 phase1phase2phase3phase1-phase2phase2-phase3phase3-phase1

- phase2 - Select phase for bus2

SelPhaseLine1 phase1phase2phase3phase1-phase2phase2-phase3phase3-phase1

- phase2 - Select phase for line1

SelPhaseLine2 phase1phase2phase3phase1-phase2phase2-phase3phase3-phase1

- phase2 - Select phase for line2

CBConfig No voltage sel.Double bus1 1/2 bus CB1 1/2 bus alt. CBTie CB

- No voltage sel. - Select CBconfiguration

UBase 0.001 - 9999.999 0.001 400.000 kV Base voltage in kV

PhaseShift -180 - 180 5 0 Deg Phase shift

URatio 1.000 0.001 0.040 - 25.000 - Voltage ratio

OperationSynch OffOn

- Off - Operation forsynchronizingfunction Off/On

UHighBusSynch 50.0 - 120.0 1.0 80.0 %UB Voltage high limit busfor synchronizing in %of UBase

UHighLineSynch 50.0 - 120.0 1.0 80.0 %UB Voltage high limit linefor synchronizing in %of UBase

UDiffSynch 2.0 - 50.0 1.0 10.0 %UB Voltage differencelimit for synchronizingin % of UBase

FreqDiffMin 0.003 - 0.250 0.001 0.010 Hz Minimum frequencydifference limit forsynchronizing




REG 670

Parameter Range Step Default Unit DescriptionFreqDiffMax 0.050 - 0.250 0.001 0.200 Hz Maximum frequency

difference limit forsynchronizing

FreqRateChange 0.000 - 0.500 0.001 0.300 Hz/s Maximum allowedfrequency rate ofchange

tBreaker 0.000 - 60.000 0.001 0.080 s Closing time of thebreaker

tClosePulse 0.050 - 60.000 0.001 0.200 s Breaker closing pulseduration

tMaxSynch 0.00 - 6000.00 0.01 600.00 s Resets synch if noclose has been madebefore set time

tMinSynch 0.000 - 60.000 0.001 2.000 s Minimum time toaccept synchronizingconditions

OperationSC OffOn

- On - Operation forsynchronism checkfunction Off/On

UHighBusSC 50.0 - 120.0 1.0 80.0 %UB Voltage high limit busfor synchrocheck in %of UBase

UHighLineSC 50.0 - 120.0 1.0 80.0 %UB Voltage high limit linefor synchrocheck in %of UBase

UDiffSC 2.0 - 50.0 1.0 15.0 %UB Voltage differencelimit in % of UBase

FreqDiffA 0.003 - 1.000 0.001 0.010 Hz Frequency differencelimit between bus andline Auto

FreqDiffM 0.003 - 1.000 0.001 0.010 Hz Frequency differencelimit between bus andline Manual

PhaseDiffA 5.0 - 90.0 1.0 25.0 Deg Phase angledifference limitbetween bus and lineAuto

PhaseDiffM 5.0 - 90.0 1.0 25.0 Deg Phase angledifference limitbetween bus and lineManual

tSCA 0.000 - 60.000 0.001 0.100 s Time delay output forsynchrocheck Auto

tSCM 0.000 - 60.000 0.001 0.100 s Time delay output forsynchrocheck Manual

AutoEnerg OffDLLBDBLLBoth

- DBLL - Automatic energizingcheck mode

ManEnerg OffDLLBDBLLBoth

- Both - Manual energizingcheck mode




385

Parameter Range Step Default Unit DescriptionManEnergDBDL Off

On- Off - Manual dead bus,

dead line energizing

UHighBusEnerg 50.0 - 120.0 1.0 80.0 %UB Voltage high limit busfor energizing checkin % of UBase

UHighLineEnerg 50.0 - 120.0 1.0 80.0 %UB Voltage high limit linefor energizing checkin % of UBase

ULowBusEnerg 10.0 - 80.0 1.0 40.0 %UB Voltage low limit busfor energizing checkin % of UBase

ULowLineEnerg 10.0 - 80.0 1.0 40.0 %UB Voltage low limit linefor energizing checkin % of UBase

UMaxEnerg 50.0 - 180.0 1.0 115.0 %UB Maximum voltage forenergizing in % ofUBase

tAutoEnerg 0.000 - 60.000 0.001 0.100 s Time delay forautomatic energizingcheck

tManEnerg 0.000 - 60.000 0.001 0.100 s Time delay for manualenergizing check

4.12.2 Apparatus control (APC)


The apparatus control is a function for control and supervising of circuit breakers,disconnectors, and earthing switches within a bay. Permission to operate is given afterevaluation of conditions from other functions such as interlocking, synchrocheck,operator place selection and external or internal blockings.

Figure 143 gives an overview from what places the apparatus control function receivecommands. Commands to an apparatus can be initiated from the Control Center (CC),the station HMI or the local HMI on the IED front.



REG 670

Station HMI

GW

cc

Station bus

breakers disconnectors earthing switchesen05000115.vsd

ApparatusControl

REC670

I/O

LocalHMI

ApparatusControl

REC670

I/O

ApparatusControl

REC670

I/O

LocalHMI

LocalHMI

Figure 143: Overview of the apparatus control functions.

Features in the apparatus control function:

• Operation of primary apparatuses• Select-Execute principle to give high reliability• Selection and reservation function to prevent simultaneous operation• Selection and supervision of operator place• Command supervision• Block/deblock of operation• Block/deblock of updating of position indications• Substitution of position indications• Overriding of interlocking functions• Overriding of synchrocheck• Pole discordance supervision• Operation counter• Suppression of Mid position

The apparatus control function is realized by means of a number of function blocksdesignated:

• Bay control QCBAY• Switch controller SCSWI• Circuit breaker SXCBR• Circuit switch SXSWI



387

• Local remote• Local remote control• Position Evaluation

The three latter functions are logical nodes according to IEC 61850. The signal flowbetween these function blocks appears in figure 144. To realize the reservationfunction, the function blocks Reservation input (RESIN) and Bay reserve (QCRSV)also are included in the apparatus control function. The application description forall these functions can be found below. The function SCILO in the figure below isthe logical node for interlocking.

Control operation can be performed from the LHMI. Ithe administrator has definedusers with the UM tool, then the local/remote switch is under authority control. If not,the default (factory) user is the SuperUser, that can perform control operations fromthe LHMI without LogOn. The default position of the local/remote switch is onremote.

Information how to log on from LHMI is available in “Operator's manual”.

en05000116.vsd

SXCBRSCSWI

SCILO

SXCBRSXCBR

SCSWI

SCILO

SXSWI

-QA1

-QB1

-QB9

IEC 61850

QCBAY

Figure 144: Signal flow between apparatus control function blocks



REG 670

Bay control (QCBAY)This function is used to handle the selection of the operator place per bay. The functiongives permission to operate from two types of locations either from Remote (e.g.control center or station HMI) or from Local (local HMI on the IED). The Local/Remote switch position can also be set to Off, which means no operator place selectedi.e. operation is not possible neither from local nor from remote.

The bay control function also provides blocking functions that can be distributed todifferent apparatuses within the bay. There are four different blocking alternatives:

• Total block of the function• Blocking of update of positions• Blocking of commands

The function does not have a corresponding functionality defined in the IEC 61850standard, which means that this function is included as a vendor specific logical node.

Switch controller (SCSWI)The Switch controller SCSWI initializes and supervises all functions to properlyselect and operate switching primary apparatuses. The Switch controller may handleand operate on one three-phase device or three one-phase switching devices.

After the selection of an apparatus and before the execution, the switch controllerperforms the following checks and actions:

• A request initiates to reserve other bays to prevent simultaneous operation.• Actual position inputs for interlocking information are read and evaluated if the

operation is permitted.• The synchrocheck/synchronizing conditions are read and checked, and performs

operation upon positive response.• The blocking conditions are evaluated• The position indications are evaluated according to given command and its

requested direction (open or closed).

The command sequence is supervised regarding the time between:

• Select and execute.• Select and until the reservation is granted.• Execute and the final end position of the apparatus.• Execute and valid close conditions from the synchrocheck.

At error the command sequence is canceled.

In the case when there are three one-phase switches (SXCBR) connected to the switchcontroller function, the switch controller will "merge" the position of the threeswitches to the resulting three-phase position. In case of a pole discordance situation,i.e. the positions of the one-phase switches are not equal for a time longer than asettable time; an error signal will be given. The mid position of apparatuses can be



389

suppressed at the (SCSWI) by setting the tIntermediate at (SXCBR/SXSWI) to anappropriate value.

The switch controller is not dependent on the type of switching device SXCBR orSXSWI. The switch controller represents the content of the CSWI logical node(according to IEC 61850) with mandatory functionality.

Switch (SXCBR/SXSWI)The Switch is a function used to close and interrupt an ac power circuit under normalconditions or to interrupt the circuit under fault or emergency conditions. Theintention with this function is to represent the lowest level of a power-switchingdevice with or without short circuit breaking capability, e.g. circuit breakers,disconnectors, earthing switches etc.

The purpose of this function is to provide the actual status of positions and to performthe control operations, i.e. pass all the commands to the primary apparatus via outputboards and to supervise the switching operation and position.

The Switch has this functionality:

• Local/Remote switch intended for the switchyard• Block/deblock for open/close command respectively• Update block/deblock of position indication• Substitution of position indication• Supervision timer that the primary device starts moving after a command• Supervision of allowed time for intermediate position• Definition of pulse duration for open/close command respectively

The realization of this function is performed with SXCBR representing a circuitbreaker and with SXSWI representing a circuit switch i.e. a disconnector or anearthing switch. The SXCBR can be realized either as three one-phase switches or asone three-phase switch.

The content of this function is represented by the IEC 61850 definitions for the logicalnodes XCBR and XSWI with mandatory functionality.

Reservation function (QCRSV/RESIN)The purpose of the reservation function is primarily to transfer interlockinginformation between IEDs in a safe way and to prevent double operation in a bay,switchyard part, or complete substation.

For interlocking evaluation in a substation, the position information from switchingdevices, such as circuit breakers, disconnectors and earthing switches can be requiredfrom the same bay or from several other bays. When information is needed from otherbays, it is exchanged over the serial station bus between the distributed IEDs. Theproblem that arises, even at a high speed of communication, is a space of time duringwhich the information about the position of the switching devices are uncertain. Theinterlocking function uses this information for evaluation, which means that also theinterlocking conditions will be uncertain.



REG 670

To ensure that the interlocking information is correct at the time of operation, a uniquereservation method is available in the IEDs. With this reservation method theoperation will temporarily be blocked for all switching devices in other bays, whichswitching states are used for evaluation of permission to operate. Actual positionindications from these bays are then transferred over the serial bus for evaluation inthe IED. After the evaluation the operation can be executed with high security.

This functionality is realized over the station bus by means of the function blocksQCRSV and RESIN. The application principle appears from figure 145.

The function block QCRSV handles the reservation. It sends out either the reservationrequest to other bays or the acknowledgement if the bay has received a request fromanother bay.

The other function block RESIN receives the reservation information from other bays.The number of instances is the same as the number of involved bays (up to 60instances are available). The received signals are either the request for reservationfrom another bay or the acknowledgment from each bay respectively, which havereceived a request from this bay. Also the information of valid transmission over thestation bus must be received.

en05000117.vsd

REx670REx670

From otherSCSWI inthe bay To other

SCSWIin thebay

3

Station bus

. . .

. . .

. . .

3

RESIN

EXCH_OUTEXCH_IN

RESIN

EXCH_OUTEXCH_IN

..

SCSWI

RES_RQRES_GRT

RES_DATA

QCRSV

RES_RQ1

RES_RQ8

RES_GRT1

RES_GRT8

..

2

Figure 145: Application principles for reservation over the station bus

The reservation can also be realized with external wiring according to the applicationexample in figure 146. This solution is realized with external auxiliary relays andextra binary inputs and outputs in each IED, but without use of function blocksQCRSV and RESIN.



391

SCSWI

SELECTEDRES_EXT

+

REx670

BI BO

REx670

BI BO

OROther SCSWI in the bay

en05000118.vsd

Figure 146: Application principles for reservation with external wiring

The solution in figure 146 can also be realized over the station bus according to theapplication example in figure 147. The solutions in figure 146 and figure 147 do nothave the same high security compared to the solution in figure 145, but have insteada higher availability. This because no acknowledgment is required.

SCSWI

SELECTED

RES_EXT

REx670REx670

OROther SCWI inthe bay

Station bus. . .

SPGGIOIN

RESGRANT

IntlReceive

. . .

. . .

RESGRANT

IntlReceive

en05000178.vsd

Figure 147: Application principle for an alternative reservation solution

4.12.2.2 Interaction between modules

A typical bay with apparatus control function consists of a combination of logicalnodes or functions that are described here:



REG 670

• The Switch controller, SCSWI, initializes all operations for one apparatus andperforms the actual switching and is more or less the interface to the drive of oneapparatus. It includes the position handling as well as the control of the position.

• The Circuit breaker, SXCBR, is the process interface to the circuit breaker forthe apparatus control function.

• The Circuit switch, SXSWI, is the process interface to the disconnector or theearthing switch for the apparatus control function.

• The Bay Control, QCBAY, fulfils the bay-level functions for the apparatuses,such as operator place selection and blockings for the complete bay.

• The Reservation, QCRSV, deals with the reservation function.• The Residual overcurrent protection, EF4PTOC, trips the breaker in case of

ZMQPIDS.• The Protection trip conditioning, SMPPTRC, connects the "operate" outputs of

one or more protection functions to a common "trip" to be transmitted to SXCBR.• The Autoreclosing, SMBRREC, consists of the facilities to automatically close

a tripped breaker with respect to a number of configurable conditions.• The logical node Interlocking, SCILO, provides the information to the switching

controller SCSWI whether it is permitted to operate due to the switchyardtopology. The interlocking conditions are evaluated with separate logic andconnected to SCILO.

• The Synchronism-check, SESRSYN calculates and compares the voltage phasordifference from both sides of an open breaker with predefined switchingconditions (synchrocheck). Also the case that one side is dead (energizing-check)is included.

• The logical node Generic Automatic Process Control, GAPC, is an automaticfunction that reduces the interaction between the operator and the system. Withone command, the operator can start a sequence that will end with a connectionof a process object (e.g. line) to one of the possible busbars.

The overview of the interaction between these functions is shown in figure 148 below.



393

en05000120.vsd

ZMQPDIS(Distance)

SXCBR(Circuit breaker)

Interlockingfunctionblock

(Not a LN)

SCSWI(Switching control)

QCBAY(Bay control)

SMBRREC

(Auto-reclosure)

I/O

Trip

Close rel.

Res. req.

Star

t AR

Close CB

Position

Res. granted

Operator placeselection

SCSWI(Switching control)

SXSWI(Disconnector)

Open cmd

Close cmd

Position

SECRSYN(Synchrocheck)

SCILO

SCILO

SynchrocheckOK

QCRSV(Reservation) Res. req.

Res.granted

GAPC

(GenericAutomaticProcessControl) Open/Close

Open/Close

Enableclose

Enableopen

Open rel.

Close rel.Open rel.

SMPPTRC(Trip logic)

Position

Enab

leop

en

Enab

lecl

ose

Pos.

from

othe

r bay

s

I/O

Open cmdClose cmd

(Interlocking)

(Interlocking)

Figure 148: Example overview of the interactions between functions in a typicalbay


The setting parameters for the apparatus control function are set via the local HMI orProtection and Control IED Manager (PCM 600). Refer to the setting parametertables.



REG 670

Bay control (QCBAY)If the parameter AllPSTOValid is set to No priority, all originators from local andremote are accepted without any priority.

Switch controller (SCSWI)The parameter CtlModel specifies the type of control model according to IEC 61850.For normal control of circuit breakers, disconnectors and earthing switches the controlmodel is set to SBO Enh (select-before-operate) with enhanced security.

When the operation shall be performed in one step, the model direct control withnormal security is used.

At control with enhanced security there is an additional supervision of the status valueby the control object, which means that each command sequence must be terminatedby a termination command.

The parameter PosDependent gives permission to operate depending on the positionindication, i.e. at Always permitted it is always permitted to operate independent ofthe value of the position. At Not perm at 00/11 it is not permitted to operate if theposition is in bad or intermediate state.

tSelect is the maximum time between the select and the execute command signal, i.e.the time the operator has to perform the command execution after the selection of theobject to operate. When the time has expired, the selected output signal is set to falseand a cause-code is given over IEC 61850.

The time parameter tResResponse is the allowed time from reservation request to thefeedback reservation granted from all bays involved in the reservation function. Whenthe time has expired, the control function is reset.

tSynchrocheck is the allowed time for the synchrocheck function to fulfil the closeconditions. When the time has expired, the control function is reset.

The timer tSynchronizing supervises that the signal synchronizing in progress isobtained in SCSWI after start of the synchronizing function. The start signal for thesynchronizing is obtained if the synchrocheck conditions are not fulfilled. When thetime has expired, the control function is reset. If no synchronizing function isincluded, the time is set to 0, which means no start of the synchronizing function.

tExecutionFB is the maximum time between the execute command signal and thecommand termination. When the time has expired, the control function is reset.

tPoleDiscord is the allowed time to have discrepancy between the poles at control ofthree one-phase breakers. At discrepancy an output signal is activated to be used fortrip or alarm.

Switch (SXCBR/SXSWI)tStartMove is the supervision time for the apparatus to start moving after a commandexecution. When the time has expired, the switch function is reset.



395

During the tIntermediate time the position indication is allowed to be in anintermediate (00) state. When the time has expired, the switch function is reset. Theindication of the mid-position at SCSWI is suppressed during this time period whenthe position changes from open to close or vice-versa.

If the parameter AdaptivePulse is set to Adaptive the command output pulse resetswhen a new correct end position is reached. If the parameter is set to Not adaptivethe command output pulse remains active until the timer tClose(Open)Pulse haselapsed.

tOpenPulse is the output pulse length for an open command. The default length is setto 200 ms for a circuit breaker (SXCBR) and 500 ms for a disconnector (SXSWI).

tClosePulse is the output pulse length for a close command. The default length is setto 200 ms for a circuit breaker (SXCBR) and 500 ms for a disconnector (SXSWI).

Bay Reserve (QCRSV)The timer tCancelRes defines the supervision time for canceling the reservation, whenthis cannot be done by requesting bay due to for example communication failure.

When the parameter ParamRequestx (x=1-8) is set to Only own bay res. individuallyfor each apparatus (x) in the bay, only the own bay is reserved, i.e. the output forreservation request of other bays (RES_BAYS) will not be activated at selection ofapparatus x.

Reservation input (RESIN)With the FutureUse parameter set to Bay future use the function can handle bays notyet installed in the SA system.


Table 115: General settings for the QCBAY (CB01-) function

Parameter Range Step Default Unit DescriptionAllPSTOValid Priority

No priority- Priority - The priority of

originators

Table 116: Basic general settings for the LocalRemote (LR01-) function

Parameter Range Step Default Unit DescriptionControlMode Internal LR-switch

External LR-switch

- Internal LR-switch - Control mode forinternal/external LR-switch



REG 670

Table 117: Basic general settings for the SCSWI (CS01-) function

Parameter Range Step Default Unit DescriptionCtlModel Dir Norm

SBO Enh (ABB)Dir Norm (ABB)SBO Enh

- SBO Enh - Specifies the type forcontrol modelaccording to IEC61850

PosDependent Always permittedNot perm at 00/11

- Always permitted - Permission to operatedepending on theposition

tSelect 0.000 - 60.000 0.001 30.000 s Max time betweenselect and executesignals

tResResponse 0.000 - 60.000 0.001 5.000 s Allowed time fromreservation request toreservation granted

tSynchrocheck 0.00 - 6000.00 0.01 10.00 s Allowed time forsynchrocheck to fulfilclose conditions

tSynchronizing 0.000 - 60.000 0.001 0.000 s Supervision time toget the signalsynchronizing inprogress

tExecutionFB 0.000 - 60.000 0.001 30.000 s Max time fromcommand executionto termination

tPoleDiscord 0.000 - 60.000 0.001 2.000 s Allowed time to havediscrepancy betweenthe poles

Table 118: Basic general settings for the SXCBR (XC01-) function

Parameter Range Step Default Unit DescriptiontStartMove 0.000 - 60.000 0.001 0.100 s Supervision time for

the apparatus tomove after acommand

tIntermediate 0.000 - 60.000 0.001 0.150 s Allowed time forintermediate position

AdaptivePulse Not adaptiveAdaptive

- Not adaptive - The output resetswhen a new correctend position isreached

tOpenPulse 0.000 - 60.000 0.001 0.200 s Output pulse lengthfor open command

tClosePulse 0.000 - 60.000 0.001 0.200 s Output pulse lengthfor close command



397

Table 119: Basic general settings for the SXSWI (XS01-) function

Parameter Range Step Default Unit DescriptiontStartMove 0.000 - 60.000 0.001 3.000 s Supervision time for

the apparatus tomove after acommand

tIntermediate 0.000 - 60.000 0.001 15.000 s Allowed time forintermediate position

AdaptivePulse Not adaptiveAdaptive

- Not adaptive - The output resetswhen a new correctend position isreached

tOpenPulse 0.000 - 60.000 0.001 0.200 s Output pulse lengthfor open command

tClosePulse 0.000 - 60.000 0.001 0.200 s Output pulse lengthfor close command

SwitchType Load BreakDisconnectorEarthing SwitchHS EarthingSwitch

- Disconnector - Switch Type

Table 120: General settings for the QCRSV (CR01-) function

Parameter Range Step Default Unit DescriptiontCancelRes 0.000 - 60.000 0.001 10.000 s Supervision time for

canceling thereservation

ParamRequest1 Other bays res.Only own bay res.

- Only own bay res. - Reservation of theown bay only, atselection of apparatus1












REG 670

Parameter Range Step Default Unit DescriptionParamRequest6 Other bays res.

Only own bay res.- Only own bay res. - Reservation of the

own bay only, atselection of apparatus6





Table 121: Basic general settings for the RESIN (RE01-) function

Parameter Range Step Default Unit DescriptionFutureUse Bay in use

Bay future use- Bay in use - The bay for this ResIn

block is for future use

4.12.3 InterlockingThe main purpose of switchgear interlocking is:

• To avoid the dangerous or damaging operation of switchgear• To enforce restrictions on the operation of the substation for other reasons e.g.

load configuration. Examples of the latter are to limit the number of paralleltransformers to a maximum of two or to ensure that energizing is always fromone side, for example, the high voltage side of a transformer.

This document only deals with the first point, and only with restrictions caused byswitching devices other than the one to be controlled. This means that switchinterlock, because of device alarms, is not included in this document.

Disconnectors and earthing switches have a limited switching capacity.Disconnectors may therefore only operate:

• With basically zero current. The circuit is open on one side and has a smallextension. The capacitive current is small (for example < 5A) and powertransformers with inrush current are not allowed.

• To connect or disconnect a parallel circuit carrying load current. The switchingvoltage across the open contacts is thus virtually zero, thanks to the parallel circuit(for example < 1% of rated voltage). Paralleling of power transformers is notallowed.

Earthing switches are allowed to connect and disconnect earthing of isolated points.Due to capacitive or inductive coupling there may be some voltage (for example <



399

40% of rated voltage) before earthing and some current (for example < 100A) afterearthing of a line.

Circuit breakers are usually not interlocked. Closing is only interlocked againstrunning disconnectors in the same bay, and the bus-coupler opening is interlockedduring a busbar transfer.

The positions of all switching devices in a bay and from some other bays determinethe conditions for operational interlocking. Conditions from other stations are usuallynot available. Therefore, a line earthing switch is usually not fully interlocked. Theoperator must be convinced that the line is not energized from the other side beforeclosing the earthing switch. As an option, a voltage indication can be used forinterlocking. Take care to avoid a dangerous enable condition at the loss of a VTsecondary voltage, for example, because of a blown fuse.

The switch positions used by the operational interlocking logic are obtained fromauxiliary contacts or position sensors. For each end position (open or closed) a trueindication is needed - thus forming a double indication. The apparatus control functioncontinuously checks its consistency. If neither condition is high (1 or TRUE), theswitch may be in an intermediate position, for example, moving. This dynamic statemay continue for some time, which in the case of disconnectors may be up to 10seconds. Should both indications stay low for a longer period, the position indicationwill be interpreted as unknown. If both indications stay high, something is wrong, andthe state is again treated as unknown. In both cases an alarm is sent to the operator.Indications from position sensors shall be self-checked and system faults indicatedby a fault signal. In the interlocking logic, the signals are used to avoid dangerousenable or release conditions. When the switching state of a switching device cannotbe determined operation is not permitted.

For switches with an individual operation gear per phase, the evaluation must considerpossible phase discrepancies. This is done with the aid of an AND-function for allthree phases in each apparatus for both open and close indications. Phasediscrepancies will result in an unknown double indication state.

4.12.3.1 Configuration guidelines

The following sections describe how the interlocking for a certain switchgearconfiguration can be realized in the IED by using standard interlocking modules andtheir interconnections. They also describe the configuration settings. The inputs fordelivery specific conditions (Qx_EXy) are set to 1=TRUE if they are not used, exceptin the following cases:

• QB9_EX2 and QB9_EX4 in modules BH_LINE_A and BH_LINE_B• QA1_EX3 in module AB_TRAFO

when they are set to 0=FALSE.

4.12.3.2 Interlocking for line bay (ABC_LINE)



REG 670

The interlocking module ABC_LINE is used for a line connected to a double busbararrangement with a transfer busbar according to figure 149. The module can also beused for a double busbar arrangement without transfer busbar or a single busbararrangement with/without transfer busbar.

QB1 QB2QC1

QA1

QC2

QB9QC9

WA1 (A)

WA2 (B)

WA7 (C)

QB7

en04000478.vsd

Figure 149: Switchyard layout ABC_LINE

The signals from other bays connected to the module ABC_LINE are describedbelow.

Signals from bypass busbarTo derive the signals:

Signal BB7_D_OP All line disconnectors on bypass WA7 except in the own bay are open.

VP_BB7_D The switch status of disconnectors on bypass busbar WA7 are valid.

EXDU_BPB No transmission error from any bay containing disconnectors on bypass busbar WA7

These signals from each line bay (ABC_LINE) except that of the own bay are needed:

Signal QB7OPTR Q7 is open

VPQB7TR The switch status for QB7 is valid.

EXDU_BPB No transmission error from the bay that contains the above information.

For bay n, these conditions are valid:



401

QB7OPTR (bay 1)QB7OPTR (bay 2)

. . .

. . .QB7OPTR (bay n-1)

& BB7_D_OP

VPQB7TR (bay 1)VPQB7TR (bay 2)

. . .

. . .VPQB7TR (bay n-1)

& VP_BB7_D

EXDU_BPB (bay 1)EXDU_BPB (bay 2)

. . .

. . .EXDU_BPB (bay n-1)

& EXDU_BPB

en04000477.vsd

Figure 150: Signals from bypass busbar in line bay n.

Signals from bus-couplerIf the busbar is divided by bus-section disconnectors into bus sections, the busbar-busbar connection could exist via the bus-section disconnector and bus-coupler withinthe other bus section.

Section 1 Section 2

A1A2_DC(BS)B1B2_DC(BS)

ABC_LINE ABC_BCABC_LINE ABC_BC

(WA1)A1(WA2)B1(WA7)C C

B2A2

en04000479.vsd

Figure 151: Busbars divided by bus-section disconnectors (circuit breakers)

To derive the signals:

Signal BC_12_CL A bus-coupler connection exists between busbar WA1 and WA2.

BC_17_OP No bus-coupler connection between busbar WA1 and WA7.

BC_17_CL A bus-coupler connection exists between busbar WA1and WA7.

BC_27_OP No bus-coupler connection between busbar WA2 and WA7.

BC_27_CL A bus-coupler connection exists between busbar WA2 and WA7.

VP_BC_12 The switch status of BC_12 is valid.



EXDU_BC No transmission error from any bus-coupler bay (BC).



REG 670

These signals from each bus-coupler bay (ABC_BC) are needed:

Signal BC12CLTR A bus-coupler connection through the own bus-coupler exists between busbar WA1

and WA2.

BC17OPTR No bus-coupler connection through the own bus-coupler between busbar WA1 andWA7.

BC17CLTR A bus-coupler connection through the own bus-coupler exists between busbar WA1and WA7.

BC27OPTR No bus-coupler connection through the own bus-coupler between busbar WA2 andWA7.

BC27CLTR A bus-coupler connection through the own bus-coupler exists between busbar WA2and WA7.

VPBC12TR The switch status of BC_12 is valid.



EXDU_BC No transmission error from the bay that contains the above information.

These signals from each bus-section disconnector bay (A1A2_DC) are also needed.For B1B2_DC, corresponding signals from busbar B are used. The same type ofmodule (A1A2_DC) is used for different busbars, that is, for both bus-sectiondisconnector A1A2_DC and B1B2_DC.

Signal DCOPTR The bus-section disconnector is open.

DCCLTR The bus-section disconnector is closed.

VPDCTR The switch status of bus-section disconnector DC is valid.

EXDU_DC No transmission error from the bay that contains the above information.

If the busbar is divided by bus-section circuit breakers, the signals from the bus-section coupler bay (A1A2_BS), rather than the bus-section disconnector bay(A1A2_DC) must be used. For B1B2_BS, corresponding signals from busbar B areused. The same type of module (A1A2_BS) is used for different busbars, that is, forboth bus-section circuit breakers A1A2_BS and B1B2_BS.

Signal S1S2OPTR No bus-section coupler connection between bus-sections 1 and 2.

S1S2CLTR A bus-section coupler connection exists between bus-sections 1 and 2.

VPS1S2TR The switch status of bus-section coupler BS is valid.

EXDU_BS No transmission error from the bay that contains the above information.

For a line bay in section 1, these conditions are valid:



403

BC12CLTR (sect.1)

DCCLTR (A1A2)DCCLTR (B1B2)

>1&

BC12CLTR (sect.2)

&VPBC12TR (sect.1)

VPDCTR (A1A2)VPDCTR (B1B2)

VPBC12TR (sect.2)

>1&

BC17OPTR (sect.1)

DCOPTR (A1A2)BC17OPTR (sect.2)

>1&

BC17CLTR (sect.1)

DCCLTR (A1A2)BC17CLTR (sect.2)

&VPBC17TR (sect.1)

VPDCTR (A1A2)VPBC17TR (sect.2)

>1&

>1&

&

&

BC27OPTR (sect.1)

DCOPTR (B1B2)BC27OPTR (sect.2)

BC27CLTR (sect.1)

DCCLTR (B1B2)BC27CLTR (sect.2)

VPBC27TR (sect.1)VPDCTR (B1B2)

VPBC27TR (sect.2)

EXDU_BC (sect.1)EXDU_DC (A1A2)EXDU_DC (B1B2)EXDU_BC (sect.2)

BC_12_CL

VP_BC_12

BC_17_OP

BC_17_CL

VP_BC_17

BC_27_OP

BC_27_CL

VP_BC_27

EXDU_BC

en04000480.vsd

Figure 152: Signals to a line bay in section 1 from the bus-coupler bays in eachsection

For a line bay in section 2, the same conditions as above are valid by changing section1 to section 2 and vice versa.

Configuration settingIf there is no bypass busbar and therefore no QB7 disconnector, then the interlockingfor QB7 is not used. The states for QB7, QC71, BB7_D, BC_17, BC_27 are set toopen by setting the appropriate module inputs as follows. In the functional blockdiagram, 0 and 1 are designated 0=FALSE and 1=TRUE:



REG 670

• QB7_OP = 1• QB7_CL = 0

• QC71_OP = 1• QC71_CL = 0

• BB7_D_OP = 1

• BC_17_OP = 1• BC_17_CL = 0• BC_27_OP = 1• BC_27_CL = 0

• EXDU_BPB = 1

• VP_BB7_D = 1• VP_BC_17 = 1• VP_BC_27 = 1

If there is no second busbar WA2 and therefore no QB2 disconnector, then theinterlocking for QB2 is not used. The state for QB2, QC21, BC_12, BC_27 are setto open by setting the appropriate module inputs as follows. In the functional blockdiagram, 0 and 1 are designated 0=FALSE and 1=TRUE:

• QB2_OP = 1• QB2_CL = 0

• QC21_OP = 1• QC21_CL = 0

• BC_12_CL = 0• BC_27_OP = 1• BC_27_CL = 0

• VP_BC_12 = 1

4.12.3.3 Interlocking for bus-coupler bay (ABC_BC)

The interlocking module ABC_BC is used for a bus-coupler bay connected to a doublebusbar arrangement according to figure 153. The module can also be used for a singlebusbar arrangement with transfer busbar or double busbar arrangement withouttransfer busbar.



405

QB1 QB2

QC1

QA1

WA1 (A)

WA2 (B)

WA7 (C)

QB7QB20

QC2

en04000514.vsd

Figure 153: Switchyard layout ABC_BC

ConfigurationThe signals from the other bays connected to the bus-coupler module ABC_BC aredescribed below.

Signals from all feedersTo derive the signals:

Signal BBTR_OP No busbar transfer is in progress concerning this bus-coupler.

VP_BBTR The switch status is valid for all apparatuses involved in the busbar transfer.

EXDU_12 No transmission error from any bay connected to the WA1/WA2 busbars.

These signals from each line bay (ABC_LINE), each transformer bay (AB_TRAFO),and bus-coupler bay (ABC_BC), except the own bus-coupler bay are needed:

Signal QQB12OPTR QB1 or QB2 or both are open.

VPQB12TR The switch status of QB1 and QB2 are valid.

EXDU_12 No transmission error from the bay that contains the above information.

For bus-coupler bay n, these conditions are valid:



REG 670

QB12OPTR (bay 1)QB12OPTR (bay 2)

. . .

. . .QB12OPTR (bay n-1)

& BBTR_OP

VPQB12TR (bay 1)VPQB12TR (bay 2)

. . .

. . .VPQB12TR (bay n-1)

& VP_BBTR

EXDU_12 (bay 1)EXDU_12 (bay 2)

. . .

. . .EXDU_12 (bay n-1)

& EXDU_12

en04000481.vsd

Figure 154: Signals from any bays in bus-coupler bay n

If the busbar is divided by bus-section disconnectors into bus-sections, the signalsBBTR are connected in parallel - if both bus-section disconnectors are closed. So forthe basic project-specific logic for BBTR above, add this logic:

Section 1 Section 2


ABC_LINEABC_BC

ABC_LINE ABC_BC


B2A2

en04000482.vsd

AB_TRAFO


The following signals from each bus-section disconnector bay (A1A2_DC) areneeded. For B1B2_DC, corresponding signals from busbar B are used. The same typeof module (A1A2_DC) is used for different busbars, that is, for both bus-sectiondisconnector A1A2_DC and B1B2_DC.




If the busbar is divided by bus-section circuit breakers, the signals from the bus-section coupler bay (A1A2_BS), rather than the bus-section disconnector bay(A1A2_DC), have to be used. For B1B2_BS, corresponding signals from busbar Bare used. The same type of module (A1A2_BS) is used for different busbars, that is,for both bus-section circuit breakers A1A2_BS and B1B2_BS.



407




For a bus-coupler bay in section 1, these conditions are valid:

BBTR_OP (sect.1)

DCOPTR (A1A2)DCOPTR (B1B2)

BBTR_OP (sect.2)

&VP_BBTR (sect.1)


VP_BBTR (sect.2)

EXDU_12 (sect.1)

EXDU_DC (B1B2)EXDU_12 (sect.2)

VP_BBTR

EXDU_12

en04000483.vsd

&EXDU_DC (A1A2)

BBTR_OP

>1&

Figure 156: Signals to a bus-coupler bay in section 1 from any bays in eachsection

For a bus-coupler bay in section 2, the same conditions as above are valid by changingsection 1 to section 2 and vice versa.

Signals from bus-couplerIf the busbar is divided by bus-section disconnectors into bus-sections, the signalsBC_12 from the busbar coupler of the other busbar section must be transmitted to theown busbar coupler if both disconnectors are closed.

Section 1 Section 2


ABC_BCABC_BC


B2A2

en04000484.vsd



Signal BC_12_CL Another bus-coupler connection exists between busbar WA1 and WA2.


EXDU_BC No transmission error from any bus-coupler bay (BC).



REG 670

These signals from each bus-coupler bay (ABC_BC), except the own bay are needed:

Signal BC12CLTR A bus-coupler connection through the own bus-coupler exists between busbar WA1

and WA2.



These signals from each bus-section disconnector bay (A1A2_DC) are also needed.For B1B2_DC, corresponding signals from busbar B are used. The same type ofmodule (A1A2_DC) is used for different busbars, that is, for both bus-sectiondisconnector A1A2_DC and B1B2_DC.

Signal DCCLTR The bus-section disconnector is closed.



If the busbar is divided by bus-section circuit breakers, the signals from the bus-section coupler bay (A1A2_BS), rather than the bus-section disconnector bay(A1A2_DC), must be used. For B1B2_BS, corresponding signals from busbar B areused. The same type of module (A1A2_BS) is used for different busbars, that is, forboth bus-section circuit breakers A1A2_BS and B1B2_BS.

Signal S1S2CLTR A bus-section coupler connection exists between bus sections 1 and 2.


EXDU_BS No transmission error from the bay containing the above information.

For a bus-coupler bay in section 1, these conditions are valid:

DCCLTR (A1A2)DCCLTR (B1B2)

BC12CLTR (sect.2)


VPBC12TR (sect.2)

EXDU_DC (A1A2)EXDU_DC (B1B2)EXDU_BC (sect.2)

& BC_12_CL

VP_BC_12

EXDU_BC

en04000485.vsd

&

&

Figure 158: Signals to a bus-coupler bay in section 1 from a bus-coupler bay inan other section



409

For a bus-coupler bay in section 2, the same conditions as above are valid by changingsection 1 to section 2 and vice versa.

Configuration settingIf there is no bypass busbar and therefore no QB2 and QB7 disconnectors, then theinterlocking for QB2 and QB7 is not used. The states for QB2, QB7, QC71 are set toopen by setting the appropriate module inputs as follows. In the functional blockdiagram, 0 and 1 are designated 0=FALSE and 1=TRUE:

• QB2_OP = 1• QB2_CL = 0

• QB7_OP = 1• QB7_CL = 0

• QC71_OP = 1• QC71_CL = 0

If there is no second busbar B and therefore no QB2 and QB20 disconnectors, thenthe interlocking for QB2 and QB20 are not used. The states for QB2, QB20, QC21,BC_12, BBTR are set to open by setting the appropriate module inputs as follows.In the functional block diagram, 0 and 1 are designated 0=FALSE and 1=TRUE:

• QB2_OP = 1• QB2_CL = 0

• QB20_OP = 1• QB20_CL = 0

• QC21_OP = 1• QC21_CL = 0

• BC_12_CL = 0• VP_BC_12 = 1

• BBTR_OP = 1• VP_BBTR = 1

4.12.3.4 Interlocking for transformer bay (AB_TRAFO)

The interlocking module AB_TRAFO is used for a transformer bay connected to adouble busbar arrangement according to figure 159. The module is used when thereis no disconnector between circuit breaker and transformer. Otherwise, the moduleABC_LINE can be used. This module can also be used in single busbar arrangements.



REG 670

QB1 QB2QC1

QA1

QC2

WA1 (A)

WA2 (B)

QA2

QC3

T

QC4

QB4QB3

QA2 and QC4 are notused in this interlocking

AB_TRAFO

en04000515.vsd

Figure 159: Switchyard layout AB_TRAFO

The signals from other bays connected to the module AB_TRAFO are describedbelow.

Signals from bus-couplerIf the busbar is divided by bus-section disconnectors into bus-sections, the busbar-busbar connection could exist via the bus-section disconnector and bus-coupler withinthe other bus-section.

Section 1 Section 2


AB_TRAFO ABC_BCAB_TRAFO ABC_BC


B2A2

en04000487.vsd


The project-specific logic for input signals concerning bus-coupler are the same asthe specific logic for the line bay (ABC_LINE):

Signal BC_12_CL A bus-coupler connection exists between busbar WA1 and WA2.


EXDU_BC No transmission error from bus-coupler bay (BC).



411

The logic is identical to the double busbar configuration “Signals from bus-coupler“.

Configuration settingIf there is no second busbar B and therefore no QB2 disconnector, then theinterlocking for QB2 is not used. The state for QB2, QC21, BC_12 are set to openby setting the appropriate module inputs as follows. In the functional block diagram,0 and 1 are designated 0=FALSE and 1=TRUE:

• QB2_OP = 1• QB2QB2_CL = 0

• QC21_OP = 1• QC21_CL = 0

• BC_12_CL = 0• VP_BC_12 = 1

If there is no second busbar B at the other side of the transformer and therefore noQB4 disconnector, then the state for QB4 is set to open by setting the appropriatemodule inputs as follows:

• QB4_OP = 1• QB4_CL = 0

4.12.3.5 Interlocking for bus-section breaker (A1A2_BS)

Signals from all feedersIf the busbar is divided by bus-section circuit breakers into bus-sections and bothcircuit breakers are closed, the opening of the circuit breaker must be blocked if abus-coupler connection exists between busbars on one bus-section side and if on theother bus-section side a busbar transfer is in progress:

Section 1 Section 2

A1A2_BSB1B2_BS

ABC_LINEABC_BC

ABC_LINEABC_BC


B2A2

en04000489.vsd

AB_TRAFOAB_TRAFO

Figure 161: Busbars divided by bus-section circuit breakers




REG 670

Signal BBTR_OP No busbar transfer is in progress concerning this bus-section.

VP_BBTR The switch status of BBTR is valid.

EXDU_12 No transmission error from any bay connected to busbar 1(A) and 2(B).

These signals from each line bay (ABC_LINE), each transformer bay (AB_TRAFO),and bus-coupler bay (ABC_BC) are needed:

Signal QB12OPTR QB1 or QB2 or both are open.

VPQB12TR The switch status of QB1 and QB2 are valid.

EXDU_12 No transmission error from the bay that contains the above information.

These signals from each bus-coupler bay (ABC_BC) are needed:

Signal BC12OPTR No bus-coupler connection through the own bus-coupler between busbar WA1 and

WA2.



These signals from the bus-section circuit breaker bay (A1A2_BS, B1B2_BS) areneeded.




For a bus-section circuit breaker between A1 and A2 section busbars, these conditionsare valid:



413

S1S2OPTR (B1B2)BC12OPTR (sect.1)

QB12OPTR (bay 1/sect.2)

QB12OPTR (bay n/sect.2)

S1S2OPTR (B1B2)BC12OPTR (sect.2)


QB12OPTR (bay n /sect.1)

BBTR_OP

VP_BBTR

EXDU_12

en04000490.vsd

>1&

>1&

. . .

. . .

. . .

. . .

&

&

VPS1S2TR (B1B2)VPBC12TR (sect.1)

VPQB12TR (bay 1/sect.2)

VPQB12TR (bay n/sect.1). . .. . .

VPBC12TR (sect.2)VPQB12TR (bay 1/sect.1)

VPQB12TR (bay n/sect.1)

. . .

. . .

&

EXDU_12 (bay 1/sect.2)

EXDU_12 (bay n /sect.2)

EXDU_12(bay 1/sect.1)


EXDU_BS (B1B2)EXDU_BC (sect.1)

EXDU_BC (sect.2)

. . .

. . .

. . .

. . .

Figure 162: Signals from any bays for a bus-section circuit breaker betweensections A1 and A2

For a bus-section circuit breaker between B1 and B2 section busbars, these conditionsare valid:



REG 670

S1S2OPTR (A1A2)BC12OPTR (sect.1)


QB12OPTR (bay n/sect.2)

S1S2OPTR (A1A2)BC12OPTR (sect.2)


QB12OPTR (bay n /sect.1)

BBTR_OP

VP_BBTR

EXDU_12

en04000491.vsd

>1&

>1&

. . .

. . .

. . .

. . .

&

&

VPS1S2TR (A1A2)VPBC12TR (sect.1)

VPQB12TR (bay 1/sect.2)

VPQB12TR (bay n/sect.1). . .. . .

VPBC12TR (sect.2)VPQB12TR (bay 1/sect.1)

VPQB12TR (bay n/sect.1)

. . .

. . .

&

EXDU_12(bay 1/sect.2)


EXDU_12 (bay 1/sect.1)


EXDU_BS (A1A2)EXDU_BC (sect.1)

EXDU_BC (sect.2)

. . .

. . .

. . .

. . .

Figure 163: Signals from any bays for a bus-section circuit breaker betweensections B1 and B2

Configuration settingIf there is no other busbar via the busbar loops that are possible, then either theinterlocking for the QA1 open circuit breaker is not used or the state for BBTR is setto open. That is, no busbar transfer is in progress in this bus-section:

• BBTR_OP = 1• VP_BBTR = 1

4.12.3.6 Interlocking for bus-section disconnector (A1A2_DC)



415

The interlocking module A1A2_DC is used for one bus-section disconnector betweensection 1 and 2 according to figure 164. The module can be used for different busbars,which includes a bus-section disconnector.

WA1 (A1) WA2 (A2)

QB

QC1 QC2

A1A2_DC en04000492.vsd

Figure 164: Switchyard layout A1A2_DC

The signals from other bays connected to the module A1A2_DC are described below.

Signals in single breaker arrangementIf the busbar is divided by bus-section disconnectors, the condition no otherdisconnector connected to the bus-section must be made by a project-specific logic.

The same type of module (A1A2_DC) is used for different busbars, that is, for bothbus-section disconnector A1A2_DC and B1B2_DC. But for B1B2_DC,corresponding signals from busbar B are used.

Section 1 Section 2


ABC_LINEABC_BC

ABC_LINE


B3A3

en04000493.vsd

AB_TRAFOAB_TRAFO

A2B2



Signal S1DC_OP All disconnectors on bus-section 1 are open.

S2DC_OP All disconnectors on bus-section 2 are open.

VPS1_DC The switch status of disconnectors on bus-section 1 are valid.


EXDU_BB No transmission error from any bay that contains the above information.

These signals from each line bay (ABC_LINE), each transformer bay (AB_TRAFO),and each bus-coupler bay (ABC_BC) are needed:



REG 670

Signal QB1OPTR QB1 is open.

QB2OPTR QB2 is open (AB_TRAFO, ABC_LINE).

QB220OTR QB2 and QB20 are open (ABC_BC).

VPQB1TR The switch status of QB1 is valid.


VQB220TR The switch status of QB2 and QB20 are valid.

EXDU_BB No transmission error from the bay that contains the above information.

If there is an additional bus-section disconnector, the signal from the bus-sectiondisconnector bay (A1A2_DC) must be used:




If there is an additional bus-section circuit breaker rather than an additional bus-section disconnector the signals from the bus-section, circuit-breaker bay (A1A2_BS)rather than the bus-section disconnector bay (A1A2_DC) must be used:


QB2OPTR QB2 is open.



EXDU_BS No transmission error from the bay BS (bus-section coupler bay) that contains theabove information.

For a bus-section disconnector, these conditions from the A1 busbar section are valid:



417

QB1OPTR (bay 1/sect.A1) S1DC_OP

VPS1_DC

EXDU_BB

en04000494.vsd

&

&

&

QB1OPTR (bay n/sect.A1)

. . .

. . .

. . .

VPQB1TR (bay 1/sect.A1)

VPQB1TR (bay n/sect.A1)

EXDU_BB (bay 1/sect.A1)

EXDU_BB (bay n/sect.A1)

. . .

. . .

. . .

. . .

. . .

. . .

Figure 166: Signals from any bays in section A1 to a bus-section disconnector



VPS2_DC

EXDU_BB

en04000495.vsd


. . .

. . .

. . .


VPQB1TR (bay n/sect.A2)VPDCTR (A2/A3)


. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

DCOPTR (A2/A3)


EXDU_DC (A2/A3)

Figure 167: Signals from any bays in section A2 to a bus-section disconnector

For a bus-section disconnector, these conditions from the B1 busbar section are valid:



REG 670

QB2OPTR (QB220OTR)(bay 1/sect.B1) S1DC_OP

VPS1_DC

EXDU_BB

en04000496.vsd

QB2OPTR (QB220OTR)(bay n/sect.B1)

. . .

. . .

. . .

VPQB2TR (VQB220TR)(bay 1/sect.B1)

VPQB2TR (VQB220TR)(bay n/sect.B1)

EXDU_BB (bay 1/sect.B1)

EXDU_BB (bay n/sect.B1)

. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

Figure 168: Signals from any bays in section B1 to a bus-section disconnector


QB2OPTR (QB220OTR)(bay 1/sect.B2) S2DC_OP

VPS2_DC

EXDU_BB

en04000497.vsd


. . .

. . .

. . .

VPQB2TR(VQB220TR) (bay 1/sect.B2)

VPQB2TR(VQB220TR) (bay n/sect.B2)VPDCTR (B2/B3)


. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

DCOPTR (B2/B3)


EXDU_DC (B2/B3)

Figure 169: Signals from any bays in section B2 to a bus-section disconnector

Signals in double-breaker arrangementIf the busbar is divided by bus-section disconnectors, the condition for the busbardisconnector bay no other disconnector connected to the bus-section must be madeby a project-specific logic.




419

Section 1 Section 2


DB_BUS DB_BUSDB_BUS DB_BUS

(WA1)A1(WA2)B1 B2

A2

en04000498.vsd





VPS1_DC The switch status of all disconnectors on bus-section 1 are valid.

VPS2_DC The switch status of all disconnectors on bus-section 2 are valid.

EXDU_BB No transmission error from double-breaker bay (DB) that contains the aboveinformation.

These signals from each double-breaker bay (DB_BUS) are needed:





EXDU_DB No transmission error from the bay that contains the above information.

The logic is identical to the double busbar configuration “Signals in single breakerarrangement”.




REG 670


VPS1_DC

EXDU_BB

en04000499.vsd

&

&

&


. . .

. . .

. . .



EXDU_DB (bay 1/sect.A1)

EXDU_DB (bay n/sect.A1)

. . .

. . .

. . .

. . .

. . .

. . .

Figure 171: Signals from double-breaker bays in section A1 to a bus-sectiondisconnector



VPS2_DC

EXDU_BB

en04000500.vsd

&

&

&


. . .

. . .

. . .



EXDU_DB (bay 1/sect.A2)

EXDU_DB (bay n/sect.A2)

. . .

. . .

. . .

. . .

. . .

. . .

Figure 172: Signals from double-breaker bays in section A2 to a bus-sectiondisconnector




421

QB2OPTR (bay 1/sect.B1) S1DC_OP

VPS1_DC

EXDU_BB

en04000501.vsd

&

&

&

QB2OPTR (bay n/sect.B1)

. . .

. . .

. . .

VPQB2TR (bay 1/sect.B1)

VPQB2TR (bay n/sect.B1)

EXDU_DB (bay 1/sect.B1)

EXDU_DB (bay n/sect.B1)

. . .

. . .

. . .

. . .

. . .

. . .

Figure 173: Signals from double-breaker bays in section B1 to a bus-sectiondisconnector


QB2OPTR (bay 1/sect.B2) S2DC_OP

VPS2_DC

EXDU_BB

en04000502.vsd

&

&

&

QB2OPTR (bay n/sect.B2)

. . .

. . .

. . .

VPQB2TR (bay 1/sect.B2)

VPQB2TR (bay n/sect.B2)

EXDU_DB (bay 1/sect.B2)

EXDU_DB (bay n/sect.B2)

. . .

. . .

. . .

. . .

. . .

. . .

Figure 174: Signals from double-breaker bays in section B2 to a bus-sectiondisconnector

Signals in breaker and a half arrangementIf the busbar is divided by bus-section disconnectors, the condition for the busbardisconnector bay no other disconnector connected to the bus-section must be madeby a project-specific logic.




REG 670

Section 1 Section 2


BH_LINE

(WA1)A1(WA2)B1 B2

A2

en04000503.vsd

BH_LINE BH_LINE BH_LINE


The project-specific logic are the same as for the logic for the double-breakerconfiguration.





EXDU_BB No transmission error from breaker and a half (BH) that contains the aboveinformation.

4.12.3.7 Interlocking for busbar earthinggrounding switch (BB_ES)

The interlocking module BB_ES is used for one busbar earthing switch on any busbarparts according to figure 176.

QC

en04000504.vsd

Figure 176: Switchyard layout BB_ES

The signals from other bays connected to the module BB_ES are described below.

Signals in single breaker arrangementThe busbar earthing switch is only allowed to operate if all disconnectors of the bus-section are open.



423

Section 1 Section 2


AB_TRAFO ABC_LINEBB_ES

ABC_LINE


B2A2

en04000505.vsd

BB_ESABC_BC



Signal BB_DC_OP All disconnectors on this part of the busbar are open.

VP_BB_DC The switch status of all disconnector on this part of the busbar are valid.

EXDU_BB No transmission error from any bay containing the above information.

These signals from each line bay (ABC_LINE), each transformer bay (AB_TRAFO),and each bus-coupler bay (ABC_BC) are needed:


QB2OPTR QB2 is open (AB_TRAFO, ABC_LINE)

QB220OTR QB2 and QB20 are open (ABC_BC)




VQB220TR The switch status of QB2and QB20 are valid.


EXDU_BB No transmission error from the bay that contains the above information.

These signals from each bus-section disconnector bay (A1A2_DC) are also needed.For B1B2_DC, corresponding signals from busbar B are used. The same type ofmodule (A1A2_DC) is used for different busbars, that is, for both bus-sectiondisconnectors A1A2_DC and B1B2_DC.




If no bus-section disconnector exists the signal DCOPTR, VPDCTR and EXDU_DCare set to 1 (TRUE).



REG 670

If the busbar is divided by bus-section circuit breakers, the signals from the bus-section coupler bay (A1A2_BS) rather than the bus-section disconnector bay(A1A2_DC) must be used. For B1B2_BS, corresponding signals from busbar B areused. The same type of module (A1A2_BS) is used for different busbars, that is, forboth bus-section circuit breakers A1A2_BS and B1B2_BS.





EXDU_BS No transmission error from the bay BS (bus-section coupler bay) that contains theabove information.

For a busbar earthing switch, these conditions from the A1 busbar section are valid:

QB1OPTR (bay 1/sect.A1) BB_DC_OP

VP_BB_DC

EXDU_BB

en04000506.vsd


. . .

. . .

. . .




. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

DCOPTR (A1/A2)


EXDU_DC (A1/A2)

Figure 178: Signals from any bays in section A1 to a busbar earthing switch inthe same section

For a busbar earthing switch, these conditions from the A2 busbar section are valid:



425

QB1OPTR (bay 1/sect.A2) BB_DC_OP

VP_BB_DC

EXDU_BB

en04000507.vsd


. . .

. . .

. . .




. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

DCOPTR (A1/A2)


EXDU_DC (A1/A2)

Figure 179: Signals from any bays in section A2 to a busbar earthing switch inthe same section

For a busbar earthing switch, these conditions from the B1 busbar section are valid:

QB2OPTR(QB220OTR)(bay 1/sect.B1) BB_DC_OP

VP_BB_DC

EXDU_BB

en04000508.vsd


. . .

. . .

. . .




. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

DCOPTR (B1/B2)


EXDU_DC (B1/B2)

Figure 180: Signals from any bays in section B1 to a busbar earthing switch inthe same section

For a busbar earthing switch, these conditions from the B2 busbar section are valid:



REG 670

QB2OPTR(QB220OTR) (bay 1/sect.B2) BB_DC_OP

VP_BB_DC

EXDU_BB

en04000509.vsd

QB2OPTR(QB220OTR) (bay n/sect.B2)

. . .

. . .

. . .




. . .

. . .

. . .

. . .

. . .

. . .

&

&

&

DCOPTR (B1/B2)


EXDU_DC (B1/B2)

Figure 181: Signals from any bays in section B2 to a busbar earthing switch inthe same section

For a busbar earthing switch on bypass busbar C, these conditions are valid:

QB7OPTR (bay 1) BB_DC_OP

VP_BB_DC

EXDU_BB

en04000510.vsd

&

&

&

QB7OPTR (bay n)

. . .

. . .

. . .

VPQB7TR (bay 1)

VPQB7TR (bay n)

EXDU_BB (bay 1)

EXDU_BB (bay n)

. . .

. . .

. . .

. . .

. . .

. . .

Figure 182: Signals from bypass busbar to busbar earthing switch

Signals in double-breaker arrangementThe busbar earthing switch is only allowed to operate if all disconnectors of the bussection are open.



427

Section 1 Section 2

A1A2_DC(BS)B1B2_DC(BS) BB_ESBB_ES

DB_BUS

(WA1)A1(WA2)B1 B2

A2

en04000511.vsd

DB_BUS



Signal BB_DC_OP All disconnectors of this part of the busbar are open.

VP_BB_DC The switch status of all disconnectors on this part of the busbar are valid.


These signals from each double-breaker bay (DB_BUS) are needed:





EXDU_DB No transmission error from the bay that contains the above information.

These signals from each bus-section disconnector bay (A1A2_DC) are also needed.For B1B2_DC, corresponding signals from busbar B are used. The same type ofmodule (A1A2_DC) is used for different busbars, that is, for both bus-sectiondisconnectors A1A2_DC and B1B2_DC.




The logic is identical to the double busbar configuration described in section “Signalsin single breaker arrangement”.

Signals in breaker and a half arrangementThe busbar earthing switch is only allowed to operate if all disconnectors of the bus-section are open.



REG 670

Section 1 Section 2

A1A2_DC(BS)B1B2_DC(BS) BB_ESBB_ES

BH_LINE

(WA1)A1(WA2)B1 B2

A2

en04000512.vsdBH_LINE


The project-specific logic are the same as for the logic for the double busbarconfiguration described in section “Signals in single breaker arrangement”.

Signal BB_DC_OP All disconnectors on this part of the busbar are open.

VP_BB_DC The switch status of all disconnectors on this part of the busbar is valid.


4.12.3.8 Interlocking for double CB bay (DB)

The interlocking modules DB_BUS_A, DB_LINE and DB_BUS_B are used for aline connected to a double circuit breaker arrangement according to figure 185.

WA1 (A)

WA2 (B)

QB1QC1

QA1

QC2

QC9

QB61

QB9

QB2QC4

QA2

QC5

QC3

QB62

DB_BUS_B

DB_LINE

DB_BUS_A

en04000518.vsd

Figure 185: Switchyard layout double circuit breaker.

Three types of interlocking modules per double circuit breaker bay are defined.DB_LINE is the connection from the line to the circuit breaker parts that are connected



429

to the busbars. DB_BUS_A and DB_BUS_B are the connections from the line to thebusbars.

For a double circuit-breaker bay, the modules DB_BUS_A, DB_LINE andDB_BUS_B must be used.

Configuration settingFor application without QB9 and QC9, just set the appropriate inputs to open stateand disregard the outputs. In the functional block diagram, 0 and 1 are designated0=FALSE and 1=TRUE:

• QB9_OP = 1• QB9_CL = 0

• QC9_OP = 1• QC9_CL = 0

If, in this case, a line voltage supervision is added, then rather than setting QB9 toopen state, specify the state of the voltage supervision:

• QB9_OP = VOLT_OFF• QB9_CL = VOLT_ON

If there is no voltage supervision, then set the corresponding inputs as follows:

• VOLT_OFF = 1• VOLT_ON = 0

4.12.3.9 Interlocking for 1 1/2 CB (BH)

The interlocking modules BH_LINE_A, BH_CONN and BH_LINE_B are used forlines connected to a breaker-and-a-half diameter according to figure 186.



REG 670

WA1 (A)

WA2 (B)

QB1QC1

QA1

QC2

QC9

QB6

QB9

QB2QC1

QA1

QC2

QC3

QB6

QC3

QB62QB61 QA1

QC1 QC2QC9

QB9

BH_LINE_A BH_LINE_B

BH_CONNen04000513.vsd

Figure 186: Switchyard layout breaker-and-a-half

Three types of interlocking modules per diameter are defined. BH_LINE_A andBH_LINE_B are the connections from a line to a busbar. BH_CONN is theconnection between the two lines of the diameter in the breaker and a half switchyardlayout.

For a breaker-and-a-half arrangement, the modules BH_LINE_A, BH_CONN andBH_LINE_B must be used.

Configuration settingFor application without QB9 and QC9, just set the appropriate inputs to open stateand disregard the outputs. In the functional block diagram, 0 and 1 are designated0=FALSE and 1=TRUE:

• QB9_OP = 1• QB9_CL = 0

• QC9_OP = 1• QC9_CL = 0

If, in this case, a line voltage supervision is added, then rather than setting QB9 toopen state, specify the state of the voltage supervision:



431

• QB9_OP = VOLT_OFF• QB9_CL = VOLT_ON

If there is no voltage supervision, then set the corresponding inputs as follows:

• VOLT_OFF = 1• VOLT_ON = 0

4.12.3.10 Horizontal communication via GOOSE for interlocking

Table 122: Basic general settings for the IntlReceive (GR01-) function



4.12.4 Logic rotating switch for function selection and LHMIpresentation (SLGGIO)

Function block name: SLxx IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:SLGGIO


The SLGGIO function block (or the selector switch function block, as it is alsoknown) is used within the CAP configuration tool in order to get a selector switchfunctionality similar with the one provided by a hardware selector switch. Hardwareselector switches are used extensively by utilities, in order to have different functionsoperating on pre-set values. Hardware switches are however sources for maintenanceissues, lower system reliability and extended purchase portfolio. The virtual selectorswitches eliminate all these problems.

The SLGGIO function block has two operating inputs (UP and DOWN), one blockinginput (BLOCK) and one operator position input (PSTO). The normal way a selectorswitch is connected would be in accordance with fig.:

This is a minimal configuration, allowing for selector switch operation both from theLHMI and from external sources (switches), via the IED binary inputs. It also allowsthe operation from remote (like the station computer). The POS_NUM is an integervalue output, giving the actual output number. In this particular example, this is aselector switch with 10 positions. Since the number of positions of the switch can beestablished by settings (see below), one must be careful in coordinating the settings



REG 670

with the configuration (if one sets the number of positions to x in settings – forexample, there will be only the first x outputs available from the block in theconfiguration). Also the frequency of the (UP or DOWN) pulses should be lower thanthe setting tPulse.

From the LHMI, there are two modes of operating the switch: from the menu andfrom the SLD. An example of these two types of operation is given in this document:


The following settings are available for the Logic rotating switch for functionselection and LHMI presentation function:

Operation: Sets the operation of the function On or Off;

noOfPositions: Sets the number of positions in the switch (max. 32)- this settinginfluence the behaviour of the switch when changes from the last to the first position;

outputType: Steady or Pulsed;

operatePulseLenght: In case of a pulsed output, it gives the length of the pulse (inseconds);

timeDelay: The delay between the UP or DOWN activation signal positive front andthe output activation;

stopAtExtreme: Sets the behavior of the switch at the end positions – if set to 0, whenpressing UP while on first position, the switch will jump to the last position; whenpressing DOWN at the last position, the switch will jump to the first position; whenset to 1, no jump will be allowed;


Table 123: Basic general settings for the SLGGIO (SL01-) function



NrPos 32 1 2 - 32 - Number of positionsin the switch

OutType PulsedSteady

- Steady - Output type, steady orpulse

tPulse 0.000 - 60.000 0.001 0.200 s Operate pulseduration, in [s]

tDelay 0.000 - 60000.000 0.010 0.000 s Time delay on theoutput, in [s]

StopAtExtremes DisabledEnabled

- Disabled - Stop when min or maxposition is reached



433

4.12.5 Selector mini switch (VSGGIO)

Function block name: VS IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:VSGGIO


The VS function block (or the versatile switch function block) is a multipurposefunction used within the CAP tool for a variety of applications, as a general – purposeswitch. This function can be used for both acquiring an external switch position(through the IPOS1 and the IPOS2 inputs) and represent it through the single linediagram symbols (or use it in the configuration through the outputs POS1 and POS2)as well as a command function (controlled by the PSTO input), giving switchingcommands through the CMD_POS12 and CMD_POS21 outputs.

The output POSITION is an integer output, showing the actual position (POS1, POS2,INTERMEDIATE or BAD STATE) through an integer number (0–3).

An example where the VS switch is configured to switch auto reclose on–off from abutton symbol on the HMI is shown in figure 187. The I and OClose and Open buttonson LHMI are used for on–off operations.

en07000112.vsd

PSTO

CMDPOS12

IPOS1

NAM_POS1NAM_POS2

IPOS2

CMDPOS21OFFON

VS01(180,100)VSGGIO

AR01(2401,8)SMBRREC_79

ONOFF

SETON

INTONE

I140INVOUT INPUT

Figure 187: Control of auto reclose from LHMI through versatile switch

The switch is also provided with IEC 61850 communication so it can be controlledfrom SA system as well.

An output can not be used to process the function.



REG 670


The VS function can generate pulsed or steady commands (by setting the Modeparameter one can change this). When pulsed commands are generated, the length ofthe pulse can be set using the tPulse parameter. Also, being accessible on the singleline diagram (SLD), this function block has two control modes (settable throughCtlModel): Direct (called DirNorm) and Select-Before-Execute (called SBOEnh).


Table 124: Basic general settings for the VSGGIO (VS01-) function



CtlModel Dir NormSBO Enh

- Dir Norm - Specifies the type forcontrol modelaccording to IEC61850

Mode SteadyPulsed

- Pulsed - Operation mode

tSelect 0.000 - 60.000 0.001 30.000 s Max time betweenselect and executesignals

tPulse 0.000 - 60.000 0.001 0.200 s Command pulselenght

4.12.6 Generic double point function block (DPGGIO)

Function block name: DPx-- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:DPGGIO


The DPGGIO function block is used to send three logical outputs to other systems orequipment in the substation. The three outputs are named “OPEN”, “CLOSE” and“VALID”, since this function block is intended to be used as a position indicatorblock in interlocking and reservation station-wide logics. For additional informationsee also "".



435


There are no settings available for the user for DPGGIO. However, to get the signalssent by DPGGIO one must use the engineering tools described in chapter "Engineering of the IED".



4.12.7 Single point generic control 8 signals (SPC8GGIO)

Function block name: SCx-- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:SPC8GGIO


The SC function block is a collection of 8 single point commands, designed to bringin commands from REMOTE (SCADA) or LOCAL (HMI) to those parts of the logicconfiguration that do not need complicated function blocks that have the capabilityto receive commands (for example SCSWI). In this way, simple commands can besent directly to the IED outputs, without confirmation. Confirmation (status) of theresult of the commands is supposed to be achieved by other means, such as binaryinputs and SPGGIO function blocks, see figure 188.

SPC8GGIOSC01-

BLOCKPSTO

OUT1OUT2OUT3OUT4OUT5OUT6OUT7OUT8

en07000143.vsd

Figure 188: SC function block


The SC function block has the setting Operation, turning the function operation On/Off. There are two settings for every command output (totally 8):

Latchedx: deciding if the command signal for output x is latched (“steady”) or pulsed.



REG 670

tPulsex: if the previous setting was set on “pulsed”, then timePulsex will set the lengthof the pulse (in seconds).


Table 125: Basic general settings for the SPC8GGIO (SC01-) function



Latched1 PulsedLatched

- Pulsed - Setting for pulsed/latched mode foroutput 1

tPulse1 0.01 - 6000.00 0.01 0.10 s Output1 Pulse Time





















tPulse8 0.01 - 6000.00 0.01 0.10 s Output8 pulse time

4.13 Logic

4.13.1 Tripping logic (PTRC, 94)



437

Function block name: TRPx- IEC 60617 graphical symbol:

I->O

ANSI number: 94

IEC 61850 logical node name:SMPPTRC


All trip signals from the different protection functions shall be routed through the triplogic. In its simplest alternative the logic will only link the trip signal and make surethat it is long enough.

The tripping logic in IED 670 protection, control and monitoring IEDs offers threedifferent operating modes:

• Three-phase tripping for all fault types (3ph operating mode)• Single-phase tripping for single-phase faults and three-phase tripping for multi-

phase and evolving faults (1ph/3ph operating mode). The logic also issues athree-phase tripping command when phase selection within the operatingprotection functions is not possible, or when external conditions request three-phase tripping.

• Two phase phase for two phase faults.

The three phase trip for all faults offers a simple solution and is often sufficient inwell meshed transmission systems and in sub-transmission systems. Since mostfaults, especially at the highest voltage levels, are single phase to earth faults, singlephase tripping can be of great value. If only the faulty phase is tripped, power canstill be transferred on the line during the dead time that arises before reclosing. Singlephase tripping during single phase faults must be combined with single pole reclosing.

To meet the different double, one- and a half and other multiple circuit breakerarrangements, two identical TR function blocks may be provided within the IED.

One TR function block should be used for each breaker, if the line is connected tothe substation via more than one breaker. Assume that single pole tripping and auto-reclosing is used on the line. Both breakers are then normally set up for 1/3 phasetripping and 1/3 phase auto-reclosing. As an alternative the breaker chosen as mastercan have single pole tripping, while the slave breaker could have three pole trippingand auto-reclosing. In the case of a permanent fault, only one of the breakers has tobe operated when the fault is energized a second time. In the event of a transient faultthe slave breaker performs a three pole reclosing onto the non-faulted line.

The same philosophy can be used for two-pole tripping and auto-reclosing.

To prevent closing of a circuit breaker after a trip the function can block the closing.The two instances of the TR function are identical except for the name of the function



REG 670

block (TRP1 and TRP2). References will therefore only be made to TRP1 in thefollowing description, but they also apply to TRP2.

The trip function logic is illustrated below in figure 189.

BLOCK

BLKLKOUT

TRIN

TRINL1

TRINL2

TRINL3

PSL1

PSL2

PSL3

1PTRZ

1PTREF

P3PTR

SETLKOUT

RSTLKOUT

TRIP LOGICTRP1

TRIP

TRL1

TRL2

TRL3

TR1P

TR2P

TR3P

CLLKOUT

en05000543.vsd

Figure 189: The trip logic function block.

Three phasepole trippingA simple application with three phase tripping from the logic block utilizes a part ofthe function block. Connect the inputs from the protection function blocks to the inputTRIN. If necessary (normally the case) use a logic OR block to combine the differentfunction outputs to this input. Connect the output TRIP to the digital Output/s on theIO board.

This signal can also be used for other purposes internally in the IED. An examplecould be the starting of Breaker failure protection. The three outputs TRL1, TRL2,TRL3 will always be activated at every trip and can be utilized on individual tripoutputs if single pole operating devices are available on the circuit breaker even whena Three phase tripping scheme is selected.

Set the function block to Program=3Ph and set the required length of the trip pulseto e.g. tTripMin=150ms.

For special applications such as Lock-out refer to the separate section below. Thetypical connection is shown below in figure 190. Signals that are not used are dimmed.



439

BLOCK

BLKLKOUT

TRIN

TRINL1

TRINL2

TRINL3

PSL1

PSL2

PSL3

1PTRZ

1PTREF

P3PTR

SETLKOUT

RSTLKOUT

SMPPTRC_94TRP1-

TRIP

TRL1

TRL2

TRL3

TR1P

TR2P

TR3P

CLLKOUT

³1

ZM1 TRIP

ZM2 TRIP

ZM3 TRIP

DEF TRIP

en05000544.vsd

Figure 190: The trip logic function TR is used for a simple three phase trippingapplication.

Single and/or three phasepole trippingThe Single/Three phase tripping will give single phase tripping for single phase faultsand three phase tripping for multi-phase fault. The operating mode is always usedtogether with a single phase Auto-Reclosing scheme.

The single phase tripping can include different options and the use of the differentinputs in the function block.

The inputs 1PTRZ and 1PTREF are used for single phase tripping for Distanceprotection and Directional Earth fault protection function as required.

The inputs are combined with the phase selection logic and the start signals from thephase selector must be connected to the inputs PSL1, PSL2 and PSL3 to achieve thetripping on the respective single phase trip outputs TRL1, TRL2 and TRL3. TheOutput TRIP is a General Trip and activated independent of which phase is involved.Depending on which phases are involved the outputs TR1P,TR2P and TR3P will beactivated as well.

When single phase tripping schemes are used a single phase Auto Reclosing attemptis expected to follow. For cases where the Auto-Reclosing is not in service or willnot follow for some reason, the input Prepare Three phase Trip P3PTR must beactivated. This is normally connected to the respective output on the Auto-Recloserbut can also be connected to other signals, e.g. an external logic signal.If two breakersare involved, one TR block instance and one Auto-Recloser instance is used for eachbreaker. This will ensure correct operation and behavior of each breaker.



REG 670

The output Trip 3 Phase TR3P must be connected to the respective input in the Auto-Recloser to switch the Auto-Recloser to three phase Reclosing. If this signal is notactivated the Auto-Recloser will use single-phase Reclosing dead time. Note also thatif a second Line protection is utilizing the same Auto-Recloser the 3 phase Trip signalmust be generated e.g. by using the three trip relays contacts in series and connectingthem in parallel to the TR3P output from the trip block.

The Trip Logic also has inputs TRINL1, TRINL2 and TRINL3 where phase selectedtrip signals can be connected. Examples can be individual phase inter-trips fromremote end or internal/external phase selected trip signals which are routed throughthe IED to achieve e.g. Auto-Reclose, Breaker failure etc.Other back-up functionsare connected to the input TRIN as described above. A typical connection for a singlephase tripping scheme is shown below in figure 191.

BLOCK

BLKLKOUT

TRIN

TRINL1

TRINL2

TRINL3

PSL1

PSL2

PSL3

1PTRZ

1PTREF

P3PTR

SETLKOUT

RSTLKOUT

SMPPTRC_94TRP1-

TRIP

TRL1

TRL2

TRL3

TR1P

TR2P

TR3P

CLLKOUT

TR3P

Auto-RecloserAR01

PREP3P

³1

TR3P

Phase SelectionGFC or PSL

PSL1

PSL2

PSL3

Distance Function

ZM01

TRIP

ZM2 TRIP

ZM3 TRIP

DEF TRIP

en05000545.vsd

Figure 191: The trip logic function TR used for Single phase tripping application.

Single-, two or three phasepole trippingThe Single/Two/Three phase tripping mode provides single phase tripping for singlephase faults, two phase phase tripping for two phase faults and three phase trippingfor multi-phase faults. The operating mode is always used together with an Auto-Reclosing scheme with setting Program=1/2/3Ph or Program=1/3Ph attempt.

The functionality is very similar to the single phase scheme described above. Howeverthe Auto-Reclose must in addition to the connections for single phase above beinformed that the trip is two phase by connecting the Trip Logic output TR2P to therespective input in the Auto-Recloser.



441

Lock-outThis function block is provided with possibilities to initiate lock-out. The lock-outcan be set to only activate the block closing output CLLKOUT or initiate the blockclosing output and also maintain the trip signal (latched trip).

The Lock-out can then be manually reset after checking the primary fault by activatingthe input reset Lock-Out RSTLKOUT.

If external conditions are required to initiate Lock-out but not initiate trip this can beachieved by activating input SETLKOUT. The setting Auto-Lock = OFF will meanthat the internal trip is not activating lock-out so only initiation of the inputSETLKOUT will result in lock-out. This is normally the case for overhead lineprotection where most faults are transient. Unsuccessful auto-reclose and back-upzone tripping can in such cases be connected to initiate Lock-out by activating theinput.

Blocking of the function blockThe function block can be blocked in two different ways. Its use is dependent on theapplication. Blocking can be initiated internally by logic, or by the operator using acommunication channel. Total blockage of the trip function is done by activating theinput BLOCK and can be used to block the output of the trip logic in the event ofinternal failures. Blockage of lock-out output by activating input BLKLKOUT canbe used for operator control of the lock-out function.


The paramters for tripping logic are set via the local HMI or Protection and ControlIED Manager (PCM 600).

The following trip parameters can be set to regulate tripping.

Operation: On or Off

Sets the mode of operation. Off switches the tripping off. The normal selection is:Operation=On

Program: 3Ph,1/3Ph,1/2/3Ph

Set the required tripping scheme. Normally 3Ph or 1/2Ph are used.

TripLockout: On or Off

Set the scheme for lock-out. Off only activates lock-out output. On activates the lock-out output and latching output contacts. The normal selection is: TripLockout=Off.

AutoLock: On or Off

Setting the scheme for lock-out. Off only activates lock-out through the input SET-LOCKOUT. On also allows activation from trip function itself. The normal selectionis: AutoLock=Off.



REG 670

tTripMin

Set the required minimum duration of the trip pulse. It should be set to ensure thatthe breaker is tripped and if a signal is used to start the breaker failure protection(BFP) function longer than the back-up trip timer in the BFP. Normal setting is:tTripMin=0.150s


Table 126: Basic parameter group settings for the SMPPTRC_94 (TRP1-) function


On- On - Operation Off / On

Program 3 phase1ph/3ph1Ph/2Ph/3Ph

- 1ph/3ph - Three ph; single orthree ph; single, twoor three ph trip

tTripMin 0.000 - 60.000 0.001 0.150 s Minimum duration oftrip output signal

Table 127: Advanced parameter group settings for the SMPPTRC_94 (TRP1-) function

Parameter Range Step Default Unit DescriptionTripLockout Off

On- Off - On: activate output

(CLLKOUT) and triplatch, Off: only outp

AutoLock OffOn

- Off - On: lockout from input(SETLKOUT) andtrip, Off: only inp

4.13.2 Trip matrix logic (GGIO)

Function block name: TRxx- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:TRMGGIO


Twelve trip matrix logic blocks are included in the IED. The function blocks are usedin the configuration of the IED to route trip signals and/or other logical output signalsto the different output relays.

The matrix and the physical outputs will be seen in the PCM 600 engineering tooland this allows the user to adapt the signals to the physical tripping outputs accordingto the specific application needs.



443


The parameters for the instantaneous non-directional phase overcurrent protectionfunctions are set via the local HMI or Protection and Control IED Manager (PCM600l).


Table 128: Basic parameter group settings for the TMAGGIO (TR01-) function


ON- ON - Operation Off / On

PulseTime 0.000 - 60.000 0.001 0.000 s Output pulse time

OnDelay 0.000 - 60.000 0.001 0.000 s Output on delay time

OffDelay 0.000 - 60.000 0.001 0.000 s Output off delay time

ModeOutput1 SteadyPulsed

- Steady - Mode for output ,1steady or pulsed


- Steady - Mode for output 2,steady or pulsed


- Steady - Mode for output 3,steady or pulsed

4.13.3 Configurable logic blocks (LLD)


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


There are no settings for AND gates, OR gates, inverters or XOR gates.

For normal On/Off delay and pulse timers the time delays and pulse lengths are setfrom the CAP configuration tool.

Both timers in the same logic block (the one delayed on pick-up and the one delayedon drop-out) always have a common setting value. Pulse length settings areindependent of one another for all pulse circuits.

For controllable gates, settable timers and SR flip-flops with memory, the settingparameters are accessible via the local HMI or Protection and Control IED Manager(PCM 600).

ConfigurationLogic is configured using the CAP configuration tool.



REG 670

Execution of functions as defined by the configurable logic blocks runs according toa fixed sequence with different cycle times.

For each cycle time, the function block is given an serial execution number. This isshown when using the CAP configuration tool with the designation of the functionblock and the cycle time, for example, TMnn-(1044, 6). TMnn is the designation ofthe function block, 1044 is the serial execution number and 6 is the cycle time.

The execution of different function blocks within the same cycle is determined bythe order of their serial execution numbers. Always remember this when connectingtwo or more logical function blocks in series.

Always be careful when connecting function blocks with a fast cycletime to function blocks with a slow cycle time.Remember to design the logic circuits carefully and always check theexecution sequence for different functions. In other cases, additionaltime delays must be introduced into the logic schemes to preventerrors, for example, race between functions.


Table 129: General settings for the Timer (TM01-) function

Parameter Range Step Default Unit DescriptionT 0.000 - 90000.000 0.001 0.000 s Time delay of function

Table 130: General settings for the Pulse (TP01-) function

Parameter Range Step Default Unit DescriptionT 0.000 - 90000.000 0.001 0.010 s Time delay of function

Table 131: Parameter group settings for the SRM (SM01-) function

Parameter Range Step Default Unit DescriptionMemory Off

On- Off - Operating mode of

the memory function

Table 132: Parameter group settings for the GT (GT01-) function





445

Table 133: Parameter group settings for the TimerSet (TS01-) function



t 0.000 - 90000.000 0.001 0.000 s Delay for settabletimer n

4.13.4 Fixed signal function block (FIXD)

Function block name: FIXD- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:FixedSignals


The fixed signals function block generates a number of pre-set (fixed) signals thatcan be used in the configuration of an IED, either for forcing the unused inputs in theother function blocks to a certain level/value, or for creating a certain logic.



4.13.5 Boolean 16 to Integer conversion B16I

Function block name: BB-- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:–


The B16I function block (or the Boolean 16 to integer conversion block) is used withinthe CAP tool to transform a set of 16 binary (logical) signals into an integer. It canbe used – for example, to connect logical output signals from a function (like distanceprotection) to integer inputs from another function (like line differential protection).The B16I does not have a logical node mapping.



REG 670



4.13.6 Boolean 16 to Integer conversion with logic noderepresentation (B16IGGIO)

Function block name: BA-- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:B16IGGIO


The B16IGGIO function block (or the Boolean 16 to integer conversion with logicnode representation block) is used within the CAP tool to transform an integer into aset of 16 binary (logical) signals. The B16IGGIO can receive an integer from a stationcomputer – for example, over IEC61850. These functions are very useful when youwant to generate logical commands (for selector switches or voltage controllers) byinputting an integer number. The B16IGGIO has a Logical Node mapping in theIEC61850.



4.13.7 Integer to Boolean 16 conversion (IB16)

Function block name: IY- - IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:–


The IB16 function block (or the integer to Boolean 16 conversion block) is used withinthe CAP tool to transform a set of 16 binary (logical) signals into an integer. It canbe used – for example, to connect logical output signals from a function (like distanceprotection) to integer inputs from another function (like line differential protection).The IB16 does not have a logical node mapping.



447



4.13.8 Integer to Boolean 16 conversion with logic noderepresentation (IB16GGIO)

Function block name: IX-- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:IB16GGIO


The IB16GGIO function block (or the integer to Boolean 16 conversion with logicnode representation block) is used within the CAP tool to transform an integer into aset of 16 binary (logical) signals. The IB16GGIO can receive an integer from a stationcomputer – for example, over IEC61850. These functions are very useful when youwant to generate logical commands (for selector switches or voltage controllers) byinputting an integer number. The IB16GGIO has a Logical Node mapping in theIEC61850.



4.14 Monitoring

4.14.1 Measurements (MMXU)

Function block name: SVRx- IEC 60617 graphical symbol:

P, Q, S, I, U, f

ANSI number:

IEC 61850 logical node name:CVMMXU



REG 670

Function block name: CPxx IEC 60617 graphical symbol:

I

ANSI number:

IEC 61850 logical node name:CMMXU

Function block name: VNx IEC 60617 graphical symbol:

U

ANSI number:

IEC 61850 logical node name:VNMMXU

Function block name: VPx- IEC 60617 graphical symbol:

U

ANSI number:

IEC 61850 logical node name:VMMXU

Function block name: CSQx IEC 60617 graphical symbol:

I1, I2, I0

ANSI number:

IEC 61850 logical node name:CMSQI

Function block name: VSQx IEC 60617 graphical symbol:

U1, U2, U0

ANSI number:

IEC 61850 logical node name:VMSQI



449


Measurement functions is used for power system measurement, supervision andreporting to the local HMI, monitoring tool within PCM 600 or to station level e.g.viaIEC61850). The possibility to continuously monitor measured values of active power,reactive power, currents, voltages, frequency, power factor etc. is vital for efficientproduction, transmission and distribution of electrical energy. It provides to thesystem operator fast and easy overview of the present status of the power system.Additionally it can be used during testing and commissioning of protection andcontrol IEDs in order to verify proper operation and connection of instrumenttransformers (i.e. CTs & VTs). During normal service by periodic comparison of themeasured value from the IED with other independent meters the proper operation ofthe IED analog measurement chain can be verified. Finally it can be used to verifyproper direction orientation for distance or directional overcurrent protectionfunction.

The available measured values of an IED are depending on the actualhardware (TRM) and the logic configuration made in PCM 600.

All measured values can be supervised with four settable limits, i.e. low-low limit,low limit, high limit and high-high limit. A zero clamping reduction is also supported,i.e the measured value below a settable limit is forced to zero which reduces the impactof noise in the inputs.

Dead-band supervision can be used to report measured signal value to station levelwhen change in measured value is above set threshold limit or time integral of allchanges since the last time value updating exceeds the threshold limit. Measure valuecan also be based on periodic reporting.

The measuring function, SVR (CVMMXU), provides the following power systemquantities:

• P, Q and S: three phase active, reactive and apparent power• PF: power factor• U: phase-to-phase voltage magnitude• I: phase current magnitude• F: power system frequency

The measuring functions CP (CMMXU), VN (VNMMWU) and VP (VMMXU)provides physical quantities:

• I: phase currents (magnitude and angle) (CMMXU)• U: voltages (phase and phase-phase voltage, magnitude and angle) (VMMXU,

VNMMXU)

It is possible to calibrate the measuring function above to get better then class 0.5presentation. This is accomplished by angle and amplitude compensation at 5, 30 and100% of rated current and at 100% of rated voltage.



REG 670

The power system quantities provided, depends on the actualhardware, (TRM) and the logic configuration made in PCM 600.

The measuring functions CSQ (CMSQI) and VSQ (VMSQI) provides sequentialquantities:

• I: sequence currents (positive, zero, negative sequence, magnitude and angle)• U: sequence voltages (positive, zero and negative sequence, magnitude and

angle).

The SVR function calculates three-phase power quantities by using fundamentalfrequency phasors (i.e. DFT values) of the measured current respectively voltagesignals. The measured power quantities are available either as instantaneouslycalculated quantities or averaged values over a period of time (i.e. low pass filtered)depending on the selected settings.


The available setting parameters of the measurement function (MMXU, MSQI) aredepending on the actual hardware (TRM) and the logic configuration made in PCM600.

The parameters for the Measurement function (MMXU, MSQI) are set via the localHMI or Protection and Control IED Manager (PCM 600).

Operation: Off/On. Every function instance (SVRx, CPxx, VNxx, VP0x, CSQxx,VSQx) can be taken in operation (On) or out of operation (Off). Default setting isOff.

The following general settings can be set for the Service Value functions (SVR).

PowAmpFact: Amplitude factor to scale power calculations. The setting range is0.000-6.000. Default setting is 1.000, which also is a typical setting.

PowAngComp: Angle compensation for phase shift between measured I & U. Thesetting range is ±180 degrees. Default setting is 0 degree, which also is a typicalsetting.

Mode: Selection of measured current and voltage. There are 9 different ways ofcalculating monitored three-phase values depending on the available VT inputsconnected to the IED. See parameter group setting table. Default setting expectscomplete VT information (L1,L2,L3).

k: Low pass filter coefficient for power measurement, U and I. The setting range is0.0-1.0. Default setting is 0.0 i.e. no filtering, which also is a typical setting.

UGenZeroDb: Minimum level of voltage in % of UBase used as indication of zerovoltage (zero point clamping). If measured value is below UGenZeroDb calculatedS, P, Q and PF will be zero. The setting range is 1-100%. Default setting is 5%.



451

IGenZeroDb: Minimum level of current in % of Ibase used as indication of zerocurrent (zero point clamping). If measured value is below IGenZeroDb calculated S,P, Q and PF will be zero. The setting range is 1-100%. Default setting is 5%.

UBase: Base voltage in primary kV. This voltage is used as reference for voltagesetting. It can be suitable to set this parameter to the rated primary voltage supervisedobject. The setting range is 0.05-2000 kV. Default setting is 400 kV.

IBase: Base current in primary A. This current is used as reference for current setting.It can be suitable to set this parameter to the rated primary current of the supervisedobject. The setting range is 1-99999 A. Default setting is 3000 A.

UAmpCompY: Amplitude compensation to calibrate voltage measurements at Y% ofUr, where Y is equal to 5, 30 or 100. The setting range is ± 10%. Default setting is 0.

IAmpCompY: Amplitude compensation to calibrate current measurements at Y% ofIr, where Y is equal to 5, 30 or 100. The setting range is ± 10%. Default setting is 0.

IAngCompY: Angle compensation to calibrate angle measurements at Y% of Ir, whereY is equal to 5, 30 or 100. The setting range is ± 10 degrees. Default setting is 0.

The following general settings can be set for the phase current monitoringfunctions (CP).

IAmpCompY: Amplitude compensation to calibrate current measurements at Y% ofIr, where Y is equal to 5, 30 or 100. The setting range is ± 10%. Default setting is 0.

IAngCompY: Angle compensation to calibrate angle measurements at Y% of Ir, whereY is equal to 5, 30 or 100. The setting range is ± 10 degrees. Default setting is 0.

The following general settings can be set for the phase-phase voltage monitoringfunctions (VP).

UAmpCompY: Amplitude compensation to calibrate voltage measurements at Y% ofUr, where Y is equal to 5, 30 or 100. The setting range is ± 10%. Default setting is 0.

UAngCompY: Angle compensation to calibrate angle measurements at Y% of Ur,where Y is equal to 5, 30 or 100. The setting range is ± 10 degrees. Default setting is0.

The following general settings can be set for all monitored quantities included inthe functions (SVR, CP, VN, VP, CSQ and VSQ).

Xmin: Minimum value for analog signal X (X equals S, P, Q, PF, U, I, F, IL1-3,UL1-3UL12-31, I1, I2, 3I0, U1, U2 or 3U0)) set directly in applicable measuring unit.

Xmax: Maximum value for analog signal X.

XZeroDb: Zero point clamping. A signal value less than XZeroDb is forced to zero.The setting range is 0-100000 in steps of 0.001% related to measuring range. Defaultsetting is 0. Observe the related zero point clamping settings in Setting group N forSVR (UGenZeroDb and IGenZeroDb). If measured value is below UGenZeroDb and/



REG 670

or IGenZeroDb calculated S, P, Q and PF will be zero and these settings will overrideXZeroDb.

XRepTyp: Reporting type. Cyclic (Cyclic), amplitude deadband (Dead band) orintegral deadband (Int deadband). The reporting interval is controlled by theparameter XDbRepInt. Default setting is Cyclic.

XDbRepInt: Reporting deadband setting. Cyclic reporting is the setting value and isreporting interval in seconds. Amplitude deadband is the setting value in % ofmeasuring range. Integral deadband setting is the integral area, i.e. measured valuein % of measuring range multiplied by the time between two measured values. Defaultsetting is 10.

XHiHiLim: High-high limit. Set in applicable measuring unit. The setting range is±10000000000 in steps of 0.001. Default setting is 900·106 (i.e 900 MW/MVar/MVA).

XHiLim: High limit. Default setting is 800·106 (i.e 800 MW/MVar/MVA).

XLowLim: Low limit. Default setting is -800·106.

XLowLowLim: Low-low limit. Default setting is -900·106.

XLimHyst: Hysteresis value in % of range and is common for all limits. The settingrange is 0-100 in steps of 0.001. Default setting is 5%.

All phase angles are presented in relation to defined reference channel. The parameterPhaseAngleRef defines the reference, see section "Analog inputs".

Calibration curves

It is possible to calibrate the functions (SVR, CP, VN and VP) to get class 0.5presentations of currents, voltages and powers. This is accomplished by amplitudeand angle compensation at 5, 30 and 100% of rated current and voltage. Thecompensation curve will have the characteristic for amplitude and anglecompensation of currents as shown in figure 192 (example). The first phase will beused as reference channel and compared with the curve for calculation of factors. Thefactors will then be used for all related channels.



453

100305

IAmpComp5

IAmpComp30

IAmpComp100

-10

-10

Amplitude compensation% of Ir

Measured current

% of Ir0-5%: Constant5-30-100%: Linear>100%: Constant

100305

IAngComp5IAngComp30

IAngComp100

-10

-10

Angle compensation

Degrees

Measured current

% of Ir

en05000652.vsd

Figure 192: Calibration curves

Setting examplesThree setting examples, in connection to service values (SVR), are provided:

• SVR measurement function application for a 400 kV OHL• SVR measurement function application on the secondary side of a transformer• SVR measurement function application for a generator

For each of them detail explanation and final list of selected setting parameters valueswill be provided.

The available measured values of an IED are depending on the actualhardware (TRM) and the logic configuration made in PCM 600.

Measurement function application for a 400 kV OHLSingle line diagram for this application is given in the figure 193:



REG 670

400kV Busbar

400kV OHL

P Q

800/1 A400 0,1/

3 3kV

en05000374.vsd

Figure 193: SLD for 400 kV OHL application

In order to monitor, supervise and calibrate the active and reactive power as indicatedin the above figure it is necessary to do the following:

1. Set correctly CT and VT data and phase angle reference channelPhaseAngleRef (see section "Analog inputs") using the Parameter Setting Tool(a part of PCM 600) for analog input channels

2. Connect in Application Configuration Tool ( a part of PCM 600) measurementfunction to three-phase CT and VT inputs

3. Set under General settings parameters for the Service Value Report function:• general settings as shown in table 134.• level supervision of active power as shown in table 135.• calibration parameters as shown in table 136.

Table 134: General settings parameters for the Service Value Report function

CAP & PST name Short Description (60 char) Selectedvalue

Comments

Operation Operation Off/On On Function must be "On"

PowAmpFact Amplitude factor to scale powercalculations

1.000 It can be used duringcommissioning to achieve highermeasurement accuracy. Typicallyno scaling is required

PowAngComp Angle compensation for phaseshift between measured I & U

0.0 It can be used duringcommissioning to achieve highermeasurement accuracy. Typicallyno angle compensation isrequired. As well here requireddirection of P & Q measurement istowards protected object (i.e. asper IED internal default direction)

Mode Selection of measured currentand voltage

L1, L2, L3 All three phase to ground VTinputs are available

k Low pass filter coefficient forpower measurement, U and I

0.00 Typically no additional filtering isrequired




455


Comments

UGenZeroDb Zero point clamping in % of Ubase 25 Set minimum voltage level to 25%.Voltage below 25% will force S, Pand Q to zero.

IGenZeroDb Zero point clamping in % of Ibase 3 Set minimum current level to 3%.Current below 3% will force S, Pand Q to zero.

UBase Base setting for voltage level in kV 400.00 Set rated OHL phase-to-phasevoltage

IBase Base setting for current level in A 800 Set rated primary CT current usedfor OHL

Table 135: Settings parameters for level supervision


Comments

PMin Minimum value -750 Minimum expected load

PMax Minimum value 750 Maximum expected load

PZeroDb Zero point clamping in 0.001% ofrange

3000 Set zero point clamping to 45 MWi.e. 3% of 1500 MW

PRepTyp Reporting type db Select amplitude deadbandsupervision

PDbRepInt Cycl: Report interval (s), Db: In %of range, Int Db: In %s

2 Set ±Δdb=30 MW i.e. 2% (largerchanges than 30 MW will bereported)

PHiHiLim High High limit (physical value) 600 High alarm limit i.e. extremeoverload alarm

PHiLim High limit (physical value) 500 High warning limit i.e. overloadwarning

PLowLim Low limit (physical value) -800 Low warning limit. Not active

PLowLowlLim Low Low limit (physical value) -800 Low alarm limit. Not active

PLimHyst Hysteresis value in % of range(common for all limits)

2 Set ±ΔHysteres=30 MW i.e. 2%

Table 136: Settings for calibration parameters


Comments

IAmpComp5 Amplitude factor to calibratecurrent at 5% of Ir

0.00


0.00


0.00

UAmpComp5 Amplitude factor to calibratevoltage at 5% of Ur

0.00


0.00




REG 670


Comments


0.00

IAngComp5 Angle calibration for current at 5%of Ir

0.00

IAngComp30 Angle pre-calibration for current at30% of Ir

0.00

IAngComp100 Angle pre-calibration for current at100% of Ir

0.00

Measurement function application for a power transformerSingle line diagram for this application is given in figure 194.

110kV Busbar

200/1

35 / 0,1kV

35kV Busbar

500/5

P Q

31,5 MVA110/36,75/(10,5) kV

Yy0(d5)

UL1L2

en05000375.vsd

Figure 194: SLD for transformer application

In order to measure the active and reactive power as indicated in the above figure, itis necessary to do the following:



457

1. Set correctly all CT and VT and phase angle reference channel PhaseAngleRef(see section "Analog inputs") data using the Parameter Setting Tool for analoginput channels

2. Connect in Application Configuration Tool measurement function to LV sideCT & VT inputs

3. Set the setting parameters for relevant Measurement function as shown in thefollowing table:

CAP & PST name Short description (60 char) Selectedvalue

Comment

Operation Operation Off/On On Function must be "On"


1.000 Typically no scaling is required


180.0 Typically no angle compensationis required. However here therequired direction of P & Qmeasurement is towards busbar(i.e. Not per IED internal defaultdirection). Therefore anglecompensation have to be used inorder to get measurements inaliment with the required direction.


L1L2 Only UL1L2 phase-to-phasevoltage is available



UGenZeroDb Zero point clamping in % of Ubase 25 Set minimum voltage level to 25%

IGenZeroDb Zero point clamping in % of Ibase 3 Set minimum current level to 3%

UBase Base setting for voltage level in kV 35.00 Set LV side rated phase-to-phasevoltage

IBase Base setting for current level in A 495 Set transformer LV winding ratedcurrent

Measurement function application for a generatorSingle line diagram fro this application is given in figure 195.



REG 670

220kV Busbar

300/1

15 / 0,1kV

4000/5

100 MVA242/15,65 kV

Yd5

UL1L2 , UL2L3

G

P Q

100MVA15,65kV

en05000376.vsd

Figure 195: SLD for generator application

In order to measure the active and reactive power as indicated in the above figure, itis necessary to do the following:

1. Set correctly all CT and VT data and phase angle reference channelPhaseAngleRef (see section "Analog inputs") using the Parameter Setting Toolfor analog input channels

2. Connect in Application Configuration Tool measurement function to thegenerator CT & VT inputs

3. Set the setting parameters for relevant Measurement function as shown in thefollowing table:


Comment

Operation Operation Off/On On Function must be “On"


1.000 Typically no scaling is required


0.0 Typically no angle compensationis required. As well here requireddirection of P & Q measurement istowards protected object (i.e. asper IED internal default direction)




459


Comment


Arone Generator VTs are connectedbetween phases (i.e. V-connected)



UGenZeroDb Zero point clamping in % of Ubase 25% Set minimum voltage level to 25%

IGenZeroDb Zero point clamping in % of Ibase 3 Set minimum current level to 3%

UBase Base setting for voltage level in kV 15,65 Set generator rated phase-to-phase voltage

IBase Base setting for current level in A 3690 Set generator rated current


The available setting parameters of the measurement function (MMXU, MSQI) aredepending on the actual hardware (TRM) and the logic configuration made in PCM600.

Table 137: Basic general settings for the CVMMXU (SVR1-) function

Parameter Range Step Default Unit DescriptionSLowLim 0.000 -

10000000000.0000.001 0.000 VA Low limit (physical

value)

SLowLowLim 0.000 -10000000000.000

0.001 0.000 VA Low Low limit(physical value)

SMin 0.000 -10000000000.000

0.001 0.000 VA Minimum value

SMax 0.000 -10000000000.000

0.001 1000000000.000 VA Maximum value

SRepTyp CyclicDead bandInt deadband

- Cyclic - Reporting type

PMin -10000000000.000 -10000000000.000

0.001 -1000000000.000 W Minimum value

PMax -10000000000.000 -10000000000.000

0.001 1000000000.000 W Maximum value

PRepTyp CyclicDead bandInt deadband


QMin -10000000000.000 -10000000000.000

0.001 -1000000000.000 VAr Minimum value

Operation OffOn

- Off - Operation Off / On

IBase 1 - 99999 1 3000 A Base setting forcurrent level in A




REG 670

Parameter Range Step Default Unit DescriptionQMax -10000000000.00

0 -10000000000.000

0.001 1000000000.000 VAr Maximum value

QRepTyp CyclicDead bandInt deadband


UBase 0.05 - 2000.00 0.05 400.00 kV Base setting forvoltage level in kV


- L1, L2, L3 - Selection ofmeasured current andvoltage

PowAmpFact 0.000 - 6.000 0.001 1.000 - Amplitude factor toscale powercalculations

PowAngComp -180.0 - 180.0 0.1 0.0 Deg Angle compensationfor phase shiftbetween measured I& U

k 0.00 - 1.00 0.01 0.00 - Low pass filtercoefficient for powermeasurement, U andI

PFMin -1.000 - 0.000 0.001 -1.000 - Minimum value

PFMax 0.000 - 1.000 0.001 1.000 - Maximum value

PFRepTyp CyclicDead bandInt deadband


UMin -10000000000.000 -10000000000.000

0.001 0.000 V Minimum value

UMax -10000000000.000 -10000000000.000

0.001 400000.000 V Maximum value

URepTyp CyclicDead bandInt deadband


IMin -10000000000.000 -10000000000.000

0.001 0.000 A Minimum value

IMax -10000000000.000 -10000000000.000

0.001 1000.000 A Maximum value

IRepTyp CyclicDead bandInt deadband





461

Parameter Range Step Default Unit DescriptionFrMin -10000000000.00

0 -10000000000.000

0.001 0.000 Hz Minimum value

FrMax -10000000000.000 -10000000000.000

0.001 70.000 Hz Maximum value

FrRepTyp CyclicDead bandInt deadband


Table 138: Advanced general settings for the CVMMXU (SVR1-) function

Parameter Range Step Default Unit DescriptionSDbRepInt 1 - 300 1 10 Type Cycl: Report interval

(s), Db: In % of range,Int Db: In %s

SZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

SHiHiLim 0.000 -10000000000.000

0.001 900000000.000 VA High High limit(physical value)

SHiLim 0.000 -10000000000.000

0.001 800000000.000 VA High limit (physicalvalue)

SLimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)

PDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

PZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

PHiHiLim -10000000000.000 -10000000000.000

0.001 900000000.000 W High High limit(physical value)

PHiLim -10000000000.000 -10000000000.000

0.001 800000000.000 W High limit (physicalvalue)

PLowLim -10000000000.000 -10000000000.000

0.001 -800000000.000 W Low limit (physicalvalue)

PLowLowLim -10000000000.000 -10000000000.000

0.001 -900000000.000 W Low Low limit(physical value)

PLimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)

QDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

QZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range




REG 670

Parameter Range Step Default Unit DescriptionQHiHiLim -10000000000.00

0 -10000000000.000

0.001 900000000.000 VAr High High limit(physical value)

QHiLim -10000000000.000 -10000000000.000

0.001 800000000.000 VAr High limit (physicalvalue)

QLowLim -10000000000.000 -10000000000.000

0.001 -800000000.000 VAr Low limit (physicalvalue)

QLowLowLim -10000000000.000 -10000000000.000

0.001 -900000000.000 VAr Low Low limit(physical value)

QLimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)

PFDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

PFZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

UGenZeroDb 1 - 100 1 5 % Zero point clamping in% of Ubase

PFHiHiLim -3.000 - 3.000 0.001 3.000 - High High limit(physical value)

IGenZeroDb 1 - 100 1 5 % Zero point clamping in% of Ibase

PFHiLim -3.000 - 3.000 0.001 2.000 - High limit (physicalvalue)

PFLowLim -3.000 - 3.000 0.001 -2.000 - Low limit (physicalvalue)

PFLowLowLim -3.000 - 3.000 0.001 -3.000 - Low Low limit(physical value)

PFLimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)

UDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

UZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

UHiHiLim -10000000000.000 -10000000000.000

0.001 460000.000 V High High limit(physical value)

UHiLim -10000000000.000 -10000000000.000

0.001 450000.000 V High limit (physicalvalue)

ULowLim -10000000000.000 -10000000000.000

0.001 380000.000 V Low limit (physicalvalue)

ULowLowLim -10000000000.000 -10000000000.000

0.001 350000.000 V Low Low limit(physical value)




463

Parameter Range Step Default Unit DescriptionULimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %

of range (common forall limits)

IDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

IZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

IHiHiLim -10000000000.000 -10000000000.000

0.001 900.000 A High High limit(physical value)

IHiLim -10000000000.000 -10000000000.000

0.001 800.000 A High limit (physicalvalue)

ILowLim -10000000000.000 -10000000000.000

0.001 -800.000 A Low limit (physicalvalue)

ILowLowLim -10000000000.000 -10000000000.000

0.001 -900.000 A Low Low limit(physical value)

ILimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)

FrDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

FrZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

FrHiHiLim -10000000000.000 -10000000000.000

0.001 65.000 Hz High High limit(physical value)

FrHiLim -10000000000.000 -10000000000.000

0.001 63.000 Hz High limit (physicalvalue)

FrLowLim -10000000000.000 -10000000000.000

0.001 47.000 Hz Low limit (physicalvalue)

FrLowLowLim -10000000000.000 -10000000000.000

0.001 45.000 Hz Low Low limit(physical value)

FrLimHyst 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)







REG 670

Parameter Range Step Default Unit DescriptionIAmpComp5 -10.000 - 10.000 0.001 0.000 % Amplitude factor to

calibrate current at5% of Ir






Table 139: Basic general settings for the CMMXU (CP01-) function

Parameter Range Step Default Unit DescriptionIL1DbRepInt 1 - 300 1 10 Type Cycl: Report interval


Operation OffOn

- Off - Operation Mode On /Off

IBase 1 - 99999 1 3000 A Base setting forcurrent level in A

IL1Max 0.000 -10000000000.000


IL1RepTyp CyclicDead bandInt deadband


IL1AngDbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

IL2DbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s

IL2Max 0.000 -10000000000.000





IL3DbRepInt 1 - 300 1 10 Type Cycl: Report interval(s), Db: In % of range,Int Db: In %s




465

Parameter Range Step Default Unit DescriptionIL3Max 0.000 -

10000000000.0000.001 1000.000 A Maximum value




Table 140: Advanced general settings for the CMMXU (CP01-) function

Parameter Range Step Default Unit DescriptionIL1ZeroDb 0 - 100000 1 0 m% Zero point clamping in

0,001% of range

IL1HiHiLim 0.000 -10000000000.000


IL1HiLim 0.000 -10000000000.000




IL1LowLim 0.000 -10000000000.000

0.001 0.000 A Low limit (physicalvalue)

IL1LowLowLim 0.000 -10000000000.000

0.001 0.000 A Low Low limit(physical value)



IL1Min 0.000 -10000000000.000




IL1LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

IL2ZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

IL2HiHiLim 0.000 -10000000000.000


IL2HiLim 0.000 -10000000000.000


IL2LowLim 0.000 -10000000000.000





REG 670

Parameter Range Step Default Unit DescriptionIL2LowLowLim 0.000 -

10000000000.0000.001 0.000 A Low Low limit

(physical value)

IL2Min 0.000 -10000000000.000



IL3ZeroDb 0 - 100000 1 0 m% Zero point clamping in0,001% of range

IL3HiHiLim 0.000 -10000000000.000


IL3HiLim 0.000 -10000000000.000


IL3LowLim 0.000 -10000000000.000


IL3LowLowLim 0.000 -10000000000.000

0.001 0.000 A Low Low limit(physical value)

IL3Min 0.000 -10000000000.000



Table 141: Basic general settings for the VMMXU (VP01-) function

Parameter Range Step Default Unit DescriptionUL12DbRepInt 1 - 300 1 10 s,%,

%sCycl: Report interval(s), Db: In % of range,Int Db: In %s

Operation OffOn

- On - Operation Mode On /Off

UL12ZeroDb 0 - 100000 1 0 1/1000%

Zero point clamping in0,001% of range

UBase 0.05 - 2000.00 0.05 400.00 kV Base setting forvoltage level in kV

UL12HiHiLim -10000000000.000 -10000000000.000


UL12HiLim -10000000000.000 -10000000000.000




UL12LowLim -10000000000.000 -10000000000.000





467

Parameter Range Step Default Unit DescriptionUL12LowLowLim -10000000000.00

0 -10000000000.000



UL12Min -10000000000.000 -10000000000.000


UL12Max -10000000000.000 -10000000000.000


UL12RepTyp CyclicDead bandInt deadband


UL12LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

UL12AnDbRepInt 1 - 300 1 10 s,%,%s

Cycl: Report interval(s), Db: In % of range,Int Db: In %s

UL12AngRepTyp CyclicDead bandInt deadband


UL23DbRepInt 1 - 300 1 10 s,%,%s


UL23ZeroDb 0 - 100000 1 0 1/1000%


UL23HiHiLim -10000000000.000 -10000000000.000


UL23HiLim -10000000000.000 -10000000000.000


UL23LowLim -10000000000.000 -10000000000.000


UL23LowLowLim -10000000000.000 -10000000000.000


UL23Min -10000000000.000 -10000000000.000


UL23Max -10000000000.000 -10000000000.000








REG 670

Parameter Range Step Default Unit DescriptionUL23AnDbRepInt 1 - 300 1 10 s,%,




UL31DbRepInt 1 - 300 1 10 s,%,%s


UL31ZeroDb 0 - 100000 1 0 1/1000%


UL31HiHiLim -10000000000.000 -10000000000.000


UL31HiLim -10000000000.000 -10000000000.000


UL31LowLim -10000000000.000 -10000000000.000


UL31LowLowLim -10000000000.000 -10000000000.000


UL31Min -10000000000.000 -10000000000.000


UL31Max -10000000000.000 -10000000000.000





UL31AnDbRepInt 1 - 300 1 10 s,%,%s






469

Table 142: Basic general settings for the CMSQI (CSQ1-) function

Parameter Range Step Default Unit Description3I0DbRepInt 1 - 300 1 10 s,%,


3I0ZeroDb 0 - 100000 1 0 1/1000%


3I0HiHiLim -10000000000.000 -10000000000.000


3I0HiLim -10000000000.000 -10000000000.000


3I0LowLim -10000000000.000 -10000000000.000


3I0LowLowLim -10000000000.000 -10000000000.000


3I0Min -10000000000.000 -10000000000.000


3I0Max -10000000000.000 -10000000000.000


3I0RepTyp CyclicDead bandInt deadband


3I0LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

3I0AngDbRepInt 1 - 300 1 10 s,%,%s


Operation OffOn


3I0AngRepTyp CyclicDead bandInt deadband


I1DbRepInt 1 - 300 1 10 s,%,%s


I1ZeroDb 0 - 100000 1 0 1/1000%


I1HiHiLim -10000000000.000 -10000000000.000


I1HiLim -10000000000.000 -10000000000.000


I1LowLim -10000000000.000 -10000000000.000





REG 670

Parameter Range Step Default Unit DescriptionI1LowLowLim -10000000000.00

0 -10000000000.000


I1Min -10000000000.000 -10000000000.000


I1Max -10000000000.000 -10000000000.000


I1RepTyp CyclicDead bandInt deadband


I1LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

I1AngDbRepInt 1 - 300 1 10 s,%,%s


I1AngRepTyp CyclicDead bandInt deadband


I2DbRepInt 1 - 300 1 10 s,%,%s


I2ZeroDb 0 - 100000 1 0 1/1000%


I2HiHiLim -10000000000.000 -10000000000.000


I2HiLim -10000000000.000 -10000000000.000


I2LowLim -10000000000.000 -10000000000.000


I2LowLowLim -10000000000.000 -10000000000.000


I2Min -10000000000.000 -10000000000.000


I2Max -10000000000.000 -10000000000.000


I2RepTyp CyclicDead bandInt deadband





471

Parameter Range Step Default Unit DescriptionI2LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %

of range and iscommon for all limits

I2AngDbRepInt 1 - 300 1 10 s,%,%s


I2AngRepTyp CyclicDead bandInt deadband


Table 143: Basic general settings for the VMSQI (VSQ1-) function

Parameter Range Step Default Unit Description3U0DbRepInt 1 - 300 1 10 s,%,


3U0ZeroDb 0 - 100000 1 0 1/1000%


3U0HiHiLim -10000000000.000 -10000000000.000


3U0HiLim -10000000000.000 -10000000000.000


3U0LowLim -10000000000.000 -10000000000.000


3U0LowLowLim -10000000000.000 -10000000000.000


3U0Min -10000000000.000 -10000000000.000


3U0Max -10000000000.000 -10000000000.000


3U0RepTyp CyclicDead bandInt deadband


3U0LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

3U0AngDbRepInt 1 - 300 1 10 s,%,%s


Operation OffOn


3U0AngRepTyp CyclicDead bandInt deadband





REG 670

Parameter Range Step Default Unit DescriptionU1DbRepInt 1 - 300 1 10 s,%,


U1ZeroDb 0 - 100000 1 0 1/1000%


U1HiHiLim -10000000000.000 -10000000000.000


U1HiLim -10000000000.000 -10000000000.000


U1LowLim -10000000000.000 -10000000000.000


U1LowLowLim -10000000000.000 -10000000000.000


U1Min -10000000000.000 -10000000000.000


U1Max -10000000000.000 -10000000000.000


U1RepTyp CyclicDead bandInt deadband


U1LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

U1AngDbRepInt 1 - 300 1 10 s,%,%s


U1AngRepTyp CyclicDead bandInt deadband


U2DbRepInt 1 - 300 1 10 s,%,%s


U2ZeroDb 0 - 100000 1 0 1/1000%


U2HiHiLim -10000000000.000 -10000000000.000


U2HiLim -10000000000.000 -10000000000.000


U2LowLim -10000000000.000 -10000000000.000


U2LowLowLim -10000000000.000 -10000000000.000





473

Parameter Range Step Default Unit DescriptionU2Min -10000000000.00

0 -10000000000.000


U2Max -10000000000.000 -10000000000.000


U2RepTyp CyclicDead bandInt deadband


U2LimHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range and iscommon for all limits

U2AngDbRepInt 1 - 300 1 10 s,%,%s


U2AngRepTyp CyclicDead bandInt deadband


4.14.2 Event counter (GGIO)

Function block name: CNTx- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:CNTGGIO


This function has six counters which are used for storing the number of times eachcounter has been activated. All six counters have a common blocking function used,for example, when testing. All sex counters has a common reset and a commonfunction.



4.14.3 Event function (EV)

Function block name: EVxx- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:Event



REG 670


When using a Substation Automation system with LON or SPA communication,time-tagged events can be sent at change or cyclically from the IED to the stationlevel. These events are created from any available signal in the IED that is connectedto the Event function block. The event function block is used for LON and SPAcommunication.

Analog and double indication values are also transferred through the event block.


The setting parameters for the event function are set from the PST parameter settingtool, part of PCM 600.

EventMaskCh_1 - 16The inputs can be set individually as:

• NoEvents• OnSet, at pick-up of the signal• OnReset, at drop-out of the signal• OnChange, at both pick-up and drop-out of the signal• AutoDetect

LONChannelMask/SPAChannelMaskDefinition of which part of the event function block that shall generate events:

• Off• Channel 1-8• Channel 9-16• Channel 1-16

MinInterval_1 - 16A time interval between cyclic events can be set individually for each input channel.This can be set between 0.0 s to 1000.0 s in steps of 0.1 s. It should normally be setto 0, i.e. no cyclic communication.

MaxEvPerSecThree times this setting value gives the maximum burst quota per input channel. Areasonable value as default should be 10 events/s which gives 30 events/s as amaximum sustained event rate per channel.

It is important to set the time interval for cyclic events in an optimizedway to minimize the load on the station bus.



475


Table 144: Basic general settings for the Event (EV01-) function

Parameter Range Step Default Unit DescriptionSPAChannelMask Off

Channel 1-8Channel 9-16Channel 1-16

- Off - SPA channel mask

LONChannelMask OffChannel 1-8Channel 9-16Channel 1-16

- Off - LON channel mask

EventMask1 NoEventsOnSetOnResetOnChangeAutoDetect

- AutoDetect - Reporting criteria forinput 1


















REG 670

Parameter Range Step Default Unit DescriptionEventMask9 NoEvents

OnSetOnResetOnChangeAutoDetect
















MinRepIntVal1 0 - 3600 1 2 s Minimum reportinginterval input 1










477

Parameter Range Step Default Unit DescriptionMinRepIntVal8 0 - 3600 1 2 s Minimum reporting

interval input 8









4.14.4 Measured value expander block

Function block name: XP IEC 60617 graphical symbol: ANSI number:

IEC 61850 logical node name:RANGE_XP


The functions MMXU (SVR, CP and VP), MSQI (CSQ and VSQ) and MVGGIO(MV) are provided with measurement supervision functionality. All measured valuescan be supervised with four settable limits, i.e. low-low limit, low limit, high limitand high-high limit. The measure value expander block (XP) has been introduced tobe able to translate the integer output signal from the measuring functions to 5 binarysignals i.e. below low-low limit, below low limit, normal, above high-high limit orabove high limit. The output signals can be used as conditions in the configurablelogic.


There are no settable parameters for the measured value expander block function.

4.14.5 Disturbance report (RDRE)



REG 670

Function block name: DRP--, DRA1- – DRA4-,DRB1- – DRB6-

IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:ABRDRE


To get fast, complete and reliable information about disturbances in the primary and/or in the secondary system it is very important to gather information on fault currents,voltages and events. It is also important having a continuous event-logging to be ableto monitor in an overview perspective. These tasks are accomplished by theDisturbance Report function and facilitate a better understanding of the power systembehavior and related primary and secondary equipment during and after a disturbance.An analysis of the recorded data provides valuable information that can be used toexplain a disturbance, basis for change of relay setting plan, improve existingequipment etc. This information can also be used in a longer perspective whenplanning for and designing new installations, i.e. a disturbance recording could be apart of Functional Analysis (FA).

The Disturbance Report (DRP), always included in the IED, acquires sampled dataof all selected analog input and binary signals connected to the function blocks i.e.maximum 30 external analog, 10 internal derived analog and 96 binary signals.

The Disturbance Report function is a common name for several functions i.e.Indications (IND), Event recorder (ER), Event List (EL), Trip Value recorder (TVR),Disturbance recorder (DR).

The function is characterized by great flexibility as far as configuration, startingconditions, recording times, and large storage capacity are concerned. Thus, thedisturbance report is not dependent on the operation of protective functions, and itcan record disturbances that were not discovered by protective functions for onereason or another. The function can be used as an advanced stand-alone disturbancerecorder since there is more functionality in the Disturbance Report function thenusual.

Every disturbance report recording is saved in the IED. The same applies to all events,which are continuously saved in a ring-buffer. The Local Human Machine Interface(LHMI) is used to get information about the recordings, and the disturbance reportfiles may be uploaded to the PCM 600 (Protection and Control IED Manager) andfurther analysis using the Disturbance Handling tool.

If the IED is connected to a station bus (IEC 61850-8-1), according to IEC 61850,disturbance recorder and fault location information will be available on the bus. Thesame information will be obtainable if IEC 60870-5-103 is used.




479

The setting parameters for the Disturbance Report function (DRP) are set via theLHMI or the tool included in PCM 600.

It is possible to handle up to 40 analog and 96 binary signals, either internal signalsor signals coming from external inputs. The binary signals are identical in all functionsi.e. Disturbance recorder (DR), Event Recorder (ER), Indication (IND), Trip ValueRecorder (TVR) and Event List function (EL).

User-defined names of binary and analog input signals can be set using theconfiguration and parameter setting tool. The analog and binary signals appear withtheir user-defined names. The name is used in all related functions (IND, EL, ER,TVR and DR).

Figure ""Figure 196 shows the relations among Disturbance Report, includedfunctions and function blocks. EL, ER and IND uses information from the binaryinput function blocks (DRB1- 6). TVR uses analog information from the analog inputfunction blocks (DRA1-3). The DR function acquires information from both DRAxand DRBx.

Trip Value Rec

Event List

Event Recorder

Indications

DisturbanceRecorder

DRP- -

DRA1-- 4-

DRB1-- 6-

Disturbance Report

Binary signals

Analog signalsA4RADR

B6RBDR

RDRE

en05000160.vsd

Figure 196: Disturbance report functions and related function blocks

For the Disturbance Report function there are a number of settings which alsoinfluences the sub-functions.

Three LED indications placed above the LCD screen makes it possible to get quickstatus information about the IED. The information:



REG 670

Green LED:

Steady light In Service

Flashing light Internal failure

Dark No power supply

Yellow LED:

Steady light A Disturbance Report is triggered

Flashing light The IED is in test mode

Red LED:

Steady light Triggered on binary signal N with SetLEDN=ON

OperationThe operation of the Disturbance Report function has to be set On or Off. If Off isselected, note that no disturbance report is registered, and none sub-function willoperate (the only general parameter that influences EL).

Operation=Off:

• Disturbance reports are not stored.• LED information (yellow - start, red - trip) is not stored or changed.

Operation=On:

• Disturbance report are stored, disturbance data can be read from the LHMI andfrom a PC using PCM 600.

• LED information (yellow - start, red - trip) is stored.

Every recording will get a number (0 to 999) which is used as identifier (LHMI,disturbance handling tool and IEC 61850). An alternative recording identification isdate, time and sequence number. The sequence number is automatically increased byone for each new recording and is reset to zero at midnight. The maximum numberof recordings stored in the IED is 100 and the oldest will be overwritten when a newone arrives (FIFO).

Recording timesThe different recording times for the disturbance report are set (the pre-fault time,post-fault time, and limit time). These recording times affect all sub-functions moreor less but not the EL function.

Prefault recording time (PreFaultRecT) is the recording time before the starting pointof the disturbance. The setting should be at least 0.1 s to ensure enough samples forthe estimation of pre-fault values in the Trip Value Recorder function.

Postfault recording time (PostFaultRecT) is the maximum recording time after thedisappearance of the trig-signal (does not influence the TVR-function).



481

Recording time limit (TimeLimit) is the maximum recording time after trig. Theparameter limits the recording time if some trigging condition (fault-time) is verylong or permanently set (does not influence the TVR-function).

Post retrigger (PostRetrig) can be set to On or Off. Makes it possible to chooseperformance of the Disturbance Report function if a new trig signal appears in thepost-fault window.

PostRetrig = Off

The function is insensitive for new trig signals during post fault time.

PostRetrig = On

The function completes current report and starts a new complete report i.e. the latterwill include:

• new pre-fault- and fault-time (which will overlap previous report)• events and indications might be saved in the previous report too, due to overlap• new TVR- and FL-calculations (if installed, in operation and started)

Operation in test modeIf the IED is in test mode and OpModeTest=Off. The Disturbance Report functiondoes not save any recordings and no LED information is displayed.

If the IED is in test mode and OpModeTest=On. The Disturbance Report functionworks in normal mode and the status is indicated in the saved recording.

Binary input signalsUp to 96 binary signals can be selected among internal logical and binary inputsignals. The configuration tool is used to configure the signals.

For each of the 96 signals, it is also possible to select if the signal is to be used as atrigger for the start of the disturbance report and if the trigger should be activated onpositive (1) or negative (0) slope.

OperationN Disturbance Report may trig for binary input N (On) or not (Off).

TrigLevelN: Trig on positive (Trig on 1) or negative (Trig on 0) slope for binary inputN.

Func103N: Function type number (0-255) for binary input N according toIEC-60870-5-103, i.e. 128: Distance protection, 160: overcurrent protection, 176:transformer differential protection and 192: line differential protection.

Info103N: Information number (0-255) for binary input N according toIEC-60870-5-103, i.e. 69-71: Trip L1-L3, 78-83: Zone 1-6.

See also description in the chapter IEC 60870-5-103.



REG 670

Analog signalsUp to 40 analog signals can be selected among internal analog and analog inputsignals. The configuration tool is used to configure the signals.

The analog trigger of the Disturbance report is not affected if analog input M is to beincluded in the disturbance recording or not (OperationM= On/Off).

NomValueM: Nominal value for input M

OverTrigOpM, UnderTrigOpM: Over or Under trig operation, Disturbance Reportmay trig for high/low level of analog input M (On) or not (Off).

OverTrigLevelM, UnderTrigLevelM: Over or under trig level, Trig high/low levelrelative nominal value for analog input M in percent of nominal value.

Sub-function parametersAll functions are in operation as long as the disturbance report is in operation.

IndicationsIndicationMaN: Indication mask for binary input N. If set (Show), a status change ofthat particular input, will be fetched and shown in the disturbance summary on theLHMI. If not set (Hide), status change will not be indicated.

SetLEDN: Set red “Trip” LED on LHMI in front of the IED if binary input N changesstatus.

Disturbance recorderOperationM: Analog channel M is to be recorded by the disturbance recorder (On)or not (Off).

Event recorderThe ER function has no dedicated parameters.

Trip Value recorderZeroAngleRef: The parameter defines which analog signal that will be used as phaseangle reference for all other analog input signals. It is suggested to point out a sampledvoltage input signal e.g. a line or busbar phase voltage (channel 1-30).

Event ListThe EL function has no dedicated parameters.

ConsiderationThe density of recording equipment in power systems is increasing, since the numberof modern IEDs, where recorders are included, is increasing. This leads to a vastnumber of recordings at every single disturbance and a lot of information has to behandled if the recording functions don"t have proper settings. The goal is to optimizethe settings in each IED to be able to capture just valuable disturbances and tomaximize the number that"s possible to save in the IED.

The recording time should not be longer than necessary (PostFaultrecT andTimeLimit).



483

• Should the function record faults only for the protected object or cover more?• How long is the longest expected fault clearing time?• Is it necessary to include reclosure in the recording or should a persistent fault

generate a second recording (PostRetrig)?

Minimize the number of recordings:

• Binary signals: Use only relevant signals to start the recording i.e. protection trip,carrier receive and/or start signals.

• Analog signals: The level triggering should be used with great care, sinceunfortunate settings will cause enormously number of recordings. If neverthelessanalog input triggering is used, chose settings by a sufficient margin from normaloperation values. Phase voltages are not recommended for trigging.

Remember that values of parameters set elsewhere are linked to the information ona report. Such parameters are, for example, station and object identifiers, CT and VTratios.


Table 145: Basic general settings for the RDRE (DRP--) function



PreFaultRecT 0.05 - 1.00 0.01 0.10 s Pre-fault recordingtime

PostFaultRecT 0.1 - 10.0 0.1 0.5 s Post-fault recordingtime

TimeLimit 0.5 - 10.0 0.1 1.0 s Fault recording timelimit

PostRetrig OffOn

- Off - Post-fault retrigenabled (On) or not(Off)

ZeroAngleRef 1 - 30 1 1 Ch Trip value recorder,phasor referencechannel

OpModeTest OffOn

- Off - Operation modeduring test mode



REG 670

Table 146: Basic general settings for the A1RADR (DRA1-) function

Parameter Range Step Default Unit DescriptionOperation01 Off

On- Off - Operation On/Off

NomValue01 0.0 - 999999.9 0.1 0.0 - Nominal value foranalogue channel 1

UnderTrigOp01 OffOn

- Off - Use under level trigfor analogue cha 1(on) or not (off)

UnderTrigLe01 0 - 200 1 50 % Under trigger level foranalogue cha 1 in %of signal

OverTrigOp01 OffOn

- Off - Use over level trig foranalogue cha 1 (on)or not (off)

OverTrigLe01 0 - 5000 1 200 % Over trigger level foranalogue cha 1 in %of signal

Operation02 OffOn

- Off - Operation On/Off


UnderTrigOp02 OffOn



OverTrigOp02 OffOn



Operation03 OffOn



UnderTrigOp03 OffOn



OverTrigOp03 OffOn


OverTrigLe03 0 - 5000 1 200 % Overtrigger level foranalogue cha 3 in %of signal

Operation04 OffOn





485

Parameter Range Step Default Unit DescriptionNomValue04 0.0 - 999999.9 0.1 0.0 - Nominal value for

analogue channel 4

UnderTrigOp04 OffOn



OverTrigOp04 OffOn



Operation05 OffOn



UnderTrigOp05 OffOn



OverTrigOp05 OffOn



Operation06 OffOn



UnderTrigOp06 OffOn



OverTrigOp06 OffOn



Operation07 OffOn






REG 670

Parameter Range Step Default Unit DescriptionUnderTrigOp07 Off

On- Off - Use under level trig

for analogue cha 7(on) or not (off)


OverTrigOp07 OffOn



Operation08 OffOn



UnderTrigOp08 OffOn



OverTrigOp08 OffOn



Operation09 OffOn



UnderTrigOp09 OffOn



OverTrigOp09 OffOn



Operation10 OffOn



UnderTrigOp10 OffOn





487

Parameter Range Step Default Unit DescriptionUnderTrigLe10 0 - 200 1 50 % Under trigger level for

analogue cha 10 in %of signal

OverTrigOp10 OffOn



Table 147: Basic general settings for the A4RADR (DRA4-) function


On- Off - Operation On/off


UnderTrigOp31 OffOn



OverTrigOp31 OffOn



Operation32 OffOn

- Off - Operation On/off


UnderTrigOp32 OffOn



OverTrigOp32 OffOn



Operation33 OffOn






REG 670

Parameter Range Step Default Unit DescriptionUnderTrigOp33 Off

On- Off - Use under level trig

for analogue cha 33(on) or not (off)


OverTrigOp33 OffOn


OverTrigLe33 0 - 5000 1 200 % Overtrigger level foranalogue cha 33 in %of signal

Operation34 OffOn



UnderTrigOp34 OffOn



OverTrigOp34 OffOn



Operation35 OffOn



UnderTrigOp35 OffOn



OverTrigOp35 OffOn



Operation36 OffOn



UnderTrigOp36 OffOn





489

Parameter Range Step Default Unit DescriptionUnderTrigLe36 0 - 200 1 50 % Under trigger level for

analogue cha 36 in %of signal

OverTrigOp36 OffOn



Operation37 OffOn



UnderTrigOp37 OffOn



OverTrigOp37 OffOn



Operation38 OffOn



UnderTrigOp38 OffOn



OverTrigOp38 OffOn



Operation39 OffOn



UnderTrigOp39 OffOn






REG 670

Parameter Range Step Default Unit DescriptionOverTrigOp39 Off

On- Off - Use over level trig for

analogue cha 39 (on)or not (off)


Operation40 OffOn



UnderTrigOp40 OffOn



OverTrigOp40 OffOn



Table 148: Basic general settings for the B1RBDR (DRB1-) function


On- Off - Trigger operation On/

Off

TrigLevel01 Trig on 0Trig on 1

- Trig on 1 - Trig on positiv (1) ornegative (0) slope forbinary inp 1

IndicationMa01 HideShow

- Hide - Indication mask forbinary channel 1

SetLED01 OffOn

- Off - Set red-LED on HMIfor binary channel 1

Operation02 OffOn

- Off - Trigger operation On/Off





SetLED02 OffOn


Operation03 OffOn







491

Parameter Range Step Default Unit DescriptionIndicationMa03 Hide

Show- Hide - Indication mask for

binary channel 3

SetLED03 OffOn


Operation04 OffOn






SetLED04 OffOn


Operation05 OffOn






SetLED05 OffOn


Operation06 OffOn






SetLED06 OffOn


Operation07 OffOn






SetLED07 OffOn


Operation08 OffOn






SetLED08 OffOn





REG 670


On- Off - Trigger operation On/

Off





SetLED09 OffOn


Operation10 OffOn






SetLED10 OffOn


Operation11 OffOn






SetLED11 OffOn


Operation12 OffOn






SetLED12 OffOn

- Off - Set red-LED on HMIfor binary input 12

Operation13 OffOn






SetLED13 OffOn


Operation14 OffOn







493

Parameter Range Step Default Unit DescriptionIndicationMa14 Hide

Show- Hide - Indication mask for

binary channel 14

SetLED14 OffOn


Operation15 OffOn






SetLED15 OffOn


Operation16 OffOn






SetLED16 OffOn


FUNT1 0 - 255 1 0 FunT Function type forbinary channel 1 (IEC-60870-5-103)









FUNT10 0 - 255 1 0 FunT Function type forbinary channel 10(IEC -60870-5-103)




REG 670

Parameter Range Step Default Unit DescriptionFUNT11 0 - 255 1 0 FunT Function type for

binary channel 11(IEC -60870-5-103)






INFNO1 0 - 255 1 0 INFNO

Information numberfor binary channel 1(IEC -60870-5-103)
























495

Parameter Range Step Default Unit DescriptionINFNO12 0 - 255 1 0 INFN

OInformation numberfor binary channel 12(IEC -60870-5-103)









4.14.6 Event list (RDRE)


From an overview perspective, continuous event-logging is a useful systemmonitoring instrument and is a complement to specific disturbance recorderfunctions.

The event list (EL), always included in the IED, logs all selected binary input signalsconnected to the Disturbance report function. The list may contain of up to 1000 time-tagged events stored in a ring-buffer where, if the buffer is full, the oldest event isoverwritten when a new event is logged.

The difference between the event list (EL) and the event recorder (ER) function isthat the list function continuously updates the log with time tagged events while therecorder function is an extract of events during the disturbance report time window.

The event list information is available in the IED and the user can use the LocalHuman Machine Interface (LHMI) to get the information. The list can also beuploaded from the PCM 600 tool.


The setting parameters for the Event list function (EL) are a part of the Disturbancereport settings.

It is possible to event handle up to 96 binary signals, either internal signals or signalsfrom binary input channels. These signals are identical with the binary signalsrecorded by the disturbance recorder.

There is no dedicated setting for the EL function.



REG 670

4.14.7 Indications (RDRE)


Fast, condensed and reliable information about disturbances in the primary and/or inthe secondary system is important. Binary signals that have changed status during adisturbance are an example of this. This information is used primarily in the shortterm (e.g. immediate disturbance analysis, corrective actions) to get information viathe LHMI in a straightforward way without any knowledge of how to handle the IED.

There are three LED"s on the LHMI (green, yellow and red) which will display statusinformation about the IED (in service, internal failure etc.) and the Disturbance Reportfunction (trigged).

The Indication function (IND), always included in the IED, shows all selected binaryinput signals connected to the Disturbance Report function that have been activatedduring a disturbance. The status changes are logged during the entire recording time,which depends on the set of recording times (pre-, post-fault and limit time) and theactual fault time. The indications are not time-tagged.

The indication information is available for each of the recorded disturbances in theIED and the user may use the Local Human Machine Interface (LHMI) to view theinformation.


The setting parameters for LED"s and the Indication function (IND) are a part of theDisturbance Report settings.

Available signals are identical with the binary signals recorded by the disturbancereport. It is possible to use all binary input signals for the Indication function on theLHMI, but it is not recommended since the general view will be lost. The intentionis to point out some important signals, not to many, to be shown. If a more thoroughanalysis is to be done information from the Event Recorder should be used.

To be able to control the red LED in the LHMI:

SetLEDN: Set red LED on LHMI in front of the IED if binary input N changes status.

For the IND function there are a number dedicated settings:

IndicationMaN: Indication mask for binary input N. If set (Show), a status change ofthat particular input, will be fetched and shown on the LHMI. If not set (Hide), statuschange will not be indicated.



497

4.14.8 Event recorder (RDRE)


Quick, complete and reliable information about disturbances in the primary and/or inthe secondary system is vital e.g. time tagged events logged during disturbances. Thisinformation is used for different purposes in the short term (e.g. disturbance analysis,corrective actions) and in the long term (e.g. disturbance analysis, statistics andmaintenance, i.e. Functional Analysis).

The event recorder (ER), always included in the IED, logs all selected binary inputsignals connected to the Disturbance Report function. Each recording can contain upto 150 time-tagged events. The events are logged during the total recording time,which depends on the set of recording times (pre-, post-fault and limit time) and theactual fault time. During this time, the first 150 events for all 96 binary signals arelogged and time-tagged.

The event recorder information is available for each of the recorded disturbances inthe IED and the user may use the Local Human Machine Interface (LHMI) to get theinformation. The information is included in the disturbance recorder file, which maybe uploaded to the PCM 600 (Protection and Control IED Manager) and furtheranalyzed using the Disturbance Handling tool.

The event recording information is an integrated part of the disturbance record(Comtrade file).


The setting parameters for the Event Recorder (ER) function are a part of theDisturbance Report settings.

It is possible to event handle up to 96 binary signals, either internal signals or signalsfrom binary input channels. These signals are identical to the binary signals recordedby the disturbance report.

For the ER function there is no dedicated setting.

4.14.9 Trip value recorder (RDRE)


Fast, complete and reliable information about disturbances such as fault currents andvoltage faults in the power system is vital. This information is used for differentpurposes in the short perspective (e.g. fault location, disturbance analysis, correctiveactions) and the long term (e.g. disturbance analysis, statistics and maintenance, i.e.Functional Analysis).



REG 670

The trip value recorder (TVR), always included in the IED, calculates the values ofall selected external analog input signals (channel 1-30) connected to the DisturbanceReport function. The estimation is performed immediately after finalizing eachrecording and available in the Disturbance Report. The result is magnitude and phaseangle before and during the fault for each analog input signal.

The information is used as input to the fault location function (FL), if included in theIED and in operation.

The trip value recorder information is available for each of the recorded disturbancesin the IED and the user may use the Local Human Machine Interface (LHMI) to getthe information. The information is included in the disturbance recorder file, whichcan be uploaded to the PCM 600 (Protection and Control IED Manager) and furtheranalyzed using the Disturbance Handling tool.


The trip value function (TVR) setting parameters are a part of the Disturbance Reportsettings.

For the TVR function there is one dedicated setting:

ZeroAngleRef: The parameter defines which analog signal to use as phase anglereference for all other input signals. It is suggested to point out a sampled voltageinput signal e.g. a line or busbar phase voltage (channel 1-30).

4.14.10 Disturbance recorder (RDRE)


To get fast, complete and reliable information about fault current, voltage, binarysignal and other disturbances in the power system is very important. This isaccomplished by the Disturbance Recorder function and facilitates a betterunderstanding of the behavior of the power system and related primary and secondaryequipment during and after a disturbance. An analysis of the recorded data providesvaluable information that can be used to explain a disturbance, basis for change ofIED setting plan, improvement of existing equipment etc. This information can alsobe used in a longer perspective when planning for and designing new installations,i.e. a disturbance recording could be a part of Functional Analysis (FA).

The Disturbance Recorder (DR), always included in the IED, acquires sampled datafrom all selected analog input and binary signals connected to the function blocks i.e.maximum 30 external analog, 10 internal (derived) analog and 96 binary signals.

The function is characterized by great flexibility as far as configuration, startingconditions, recording times, and large storage capacity are concerned. Thus, thedisturbance recorder is not dependent on the operation of protective functions, and itcan record disturbances that were not discovered by protective functions.



499

The disturbance recorder information is saved for each of the recorded disturbancesin the IED and the user may use the Local Human Machine Interface (LHMI) to getsome general information about the recordings. The disturbance recordinginformation is included in the disturbance recorder files, which may be uploaded tothe PCM 600 (Protection and Control IED Manager) for further analysis using theDisturbance Handling tool. The information is also available on a station busaccording to IEC 61850 and according to IEC 60870-5-103.


The setting parameters for the Disturbance Recorder function (DR) is a part of theDisturbance Report settings.

It is possible to handle up to 40 analog and 96 binary signals, either internal signalsor signals coming from external inputs. The binary signals are identical with thesignals recorded by the other functions in the Disturbance Report function i.e. EventRecorder (ER), Indication (IND) and Trip Value Recorder (TVR) function.

For the DR function there is one dedicated setting:

OperationM: Analog channel M is to be recorded by the disturbance recorder (On)or not (Off). Other disturbance report settings, such as Operation and TrigLevel forbinary signals, will also influence the disturbance recorder.

4.15 Metering

4.15.1 Pulse counter logic (GGIO)

Function block name: PCx-- IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:PCGGIO


The pulse counter logic function counts externally generated binary pulses, forinstance pulses coming from an external energy meter, for calculation of energyconsumption values. The pulses are captured by the binary input module (BIM), andread by the pulse counter function. The number of pulses in the counter is thenreported via the station bus to the substation automation system or read via the station



REG 670

monitoring system as a service value. When using IEC 61850, a scaled service valueis available over the station bus.

The normal use for this function is the counting of energy pulses from external energymeters. An optional number of inputs from an arbitrary input module in IED 670 canbe used for this purpose with a frequency of up to 40 Hz. The pulse counter can alsobe used as a general purpose counter.


From the Protection and Control IED Manager (PCM 600), these parameters can beset individually for each pulse counter:

• Operation: Off/On• tReporting: 0-3600s• Event Mask: No Events/Report Events

The configuration of the inputs and outputs of the pulse counter function block ismade with the PCM 600 tool.

On the Binary Input Module, the debounce filter time is fixed set to 5 ms, that is, thecounter suppresses pulses with a pulse length less than 5 ms. The input oscillationblocking frequency is preset to 40 Hz. That means that the counter finds the inputoscillating if the input frequency is greater than 40 Hz. The oscillation suppressionis released at 30 Hz. The values for blocking/release of the oscillation can be changedin the local HMI and PCM 600 under:

Settings/General settings/I/O-modules

The setting is common for all channels on a Binary Input Module,that is, if changes of the limits are made for inputs not connected tothe pulse counter, the setting also influences the inputs on the sameboard used for pulse counting.


Table 149: Basic general settings for the PCGGIO (PC01-) function



EventMask NoEventsReportEvents

- NoEvents - Report mask foranalog events frompulse counter

CountCriteria OffRisingEdgeFalling edgeOnChange

- RisingEdge - Pulse counter criteria




501

Parameter Range Step Default Unit DescriptionScale 1.000 - 90000.000 0.001 1.000 - Scaling value for

SCAL_VAL output tounit per counted value

Quantity CountActivePowerApparentPowerReactivePowerActiveEnergyApparentEnergyReactiveEnergy

- Count - Measured quantity forSCAL_VAL output

tReporting 0 - 3600 1 60 s Cycle time forreporting of countervalue

4.15.2 Energy metering and demand handling (MMTR)

Function block name: ETPx IEC 60617 graphical symbol:

ANSI number:

IEC 61850 logical node name:ETPMMTR


The Energy metering function is intended for statistics of the forward and reverseactive and reactive energy. It has a high accuracy basically given by the measuringfunction (CVMMXU). This function has also a site calibration possibility to furtherincrease the total accuracy.

The function is connected to the instantaneous outputs of the measuring function asshown in figure 197.

en07000121.vsd

PINSTQINST

SVR1CVMMXU

ETP1ETPMMTR

PQ

STACCRSTACCRSTDMD

TRUEFALSEFALSE

Figure 197: Connection of the energy metering function to the outputs of themeasuring function

The energy values can be read through communication in Ws and/or alternatively thevalues can be presented on the local HMI display. The graphical display is then setup with the Graphical display editor tool (GDE) with a measuring value which witha right click is selected to the active and reactive component as preferred. All four



REG 670

values can of course be presented. The values in Ws must be adjusted to normallyMWh for transmission networks which is done with a constant 278·1012.

Maximum demand values in can be presented in MWh or Mvarh in the same way.

Alternatively the values can be presented with use of the pulse counters available.The output values can then be scaled with the pulse output setting values PulseA ofthe energy metering function and then the pulse counter can be set-up to present thecorrect values by scaling in this function. Pulse counter values can then be presentedon the LHMI in the same way and/or sent to the SA system through communicationwhere the total energy then is calculated by summation of the pulses energy. Thisprinciple can be good for very high values of energy as the saturation of numbers elsewill limit energy integration to about one year with 50 kV and 3000 A. After that theaccumulation will start on zero again.


The parameters for the stub protection function (STB) are set via the local HMI orProtection and Control IED Manager (PCM 600).

The following settings can be done for the energy metering function.

Operation: Off/On

StartAcc: Off/On is used to switch the accumulation of energy on and off.

There is also an input on the configuration function block which inaddition to the setting on can start accumulation. It can e.g. be usewhen an external clock is used to switch two active energy measuringfunction blocks on and off to have indication of two tariffs.

tEnergyOnPls: tEnergyOnPls gives the pulse length of the pulse. It should be at least100 ms when connected to the Pulse counter function block. Typical value can be100 ms.

tEnergyOffPls:tEnergyOffPls gives the off time between pulses. Typical value canbe 100 ms.

EAFAccPlsQty and EARAccPlsQty: The settings EAFAccPlsQty andEARAccPlsQty gives the Ws value in each pulse. It should be selected together withthe setting of the Pulse counter settings to give the correct total pulse value.

ERFAccPlsQty and ERVAccPlsQty: The settings ERFAccPlsQty andERVAccPlsQty gives the Ws value in each pulse. It should be selected together withthe setting of the Pulse counter settings to give the correct total pulse value.

For the advanced user there are a number of settings for direction, zero clamping,max limit etc. Normally the default values are suitable for these parameters.



503


Table 150: Basic general settings for the ETPMMTR (ETP1-) function



StartAcc OffOn

- Off - Activate theaccumulation ofenergy values

tEnergy 1 Minute5 Minutes10 Minutes15 Minutes30 Minutes60 Minutes180 Minutes

- 1 Minute - Time interval forenergy calculation

tEnergyOnPls 0.000 - 60.000 0.001 1.000 s Energy accumulatedpulse ON time in secs

tEnergyOffPls 0.000 - 60.000 0.001 0.500 s Energy accumulatedpulse OFF time insecs

EAFAccPlsQty 0.001 - 10000.000 0.001 100.000 MWh Pulse quantity foractive forwardaccumulated energyvalue

EARAccPlsQty 0.001 - 10000.000 0.001 100.000 MWh Pulse quantity foractive reverseaccumulated energyvalue

ERFAccPlsQty 0.001 - 10000.000 0.001 100.000 MVArh

Pulse quantity forreactive forwardaccumulated energyvalue

ERVAccPlsQty 0.001 - 10000.000 0.001 100.000 MVArh

Pulse quantity forreactive reverseaccumulated energyvalue

Table 151: Advanced general settings for the ETPMMTR (ETP1-) function

Parameter Range Step Default Unit DescriptionEALim 0.001 -

10000000000.0000.001 1000000.000 MWh Active energy limit

ERLim 0.001 -10000000000.000

0.001 1000.000 MVArh

Reactive energy limit

DirEnergyAct ForwardReverse

- Forward - Direction of activeenergy flow Forward/Reverse

DirEnergyReac ForwardReverse

- Forward - Direction of reactiveenergy flow Forward/Reverse




REG 670

Parameter Range Step Default Unit DescriptionEnZeroClamp Off

On- On - Enable of zero point

clamping detectionfunction

LevZeroClampP 0.001 - 10000.000 0.001 10.000 MW Zero point clampinglevel at active Power

LevZeroClampQ 0.001 - 10000.000 0.001 10.000 MVAr Zero point clampinglevel at reactivePower

EAFPrestVal 0.000 - 10000.000 0.001 0.000 MWh Preset Initial value forforward active energy

EARPrestVal 0.000 - 10000.000 0.001 0.000 MWh Preset Initial value forreverse active energy

ERFPresetVal 0.000 - 10000.000 0.001 0.000 MVArh

Preset Initial value forforward reactiveenergy

ERVPresetVal 0.000 - 10000.000 0.001 0.000 MVArh

Preset Initial value forreverse reactiveenergy



505

Section 5 Station communication

About this chapterThis chapter describes the communication possibilities in a SA-system.

5.1 Overview

Each IED is provided with a communication interface, enabling it to connect to oneor many substation level systems or equipment, either on the Substation Automation(SA) bus or Substation Monitoring (SM) bus.

Following communication protocols are available:

• IEC 61850-8-1 communication protocol• LON communication protocol• SPA or IEC 60870-5-103 communication protocol• DNP3.0 communication protocol

Theoretically, several protocols can be combined in the same IED.

5.2 IEC 61850-8-1 communication protocol

5.2.1 Application IEC 61850-8-1IEC 61850–8–1 allows two or more intelligent electronic devices (IEDs) from oneor several vendors to exchange information and to use it in the performance of theirfunctions and for correct co-operation.

GOOSE (Generic Object Oriented Substation Event), which is a part of IEC 61850–8–1 standard, allows the IEDs to communicate state and control information amongstthemselves, using a publish-subscribe mechanism. That is, upon detecting an event,the IED(s) use a multi-cast transmission to notify those devices that have registeredto receive the data. An IED can, by publishing a GOOSE message, report it's status.It can also request a control action to be directed at any device in the network.

This example shows the topology of an IEC 61850–8–1 configuration. IEC 61850–8–1 specifies only the interface to the substation LAN. The LAN itself is left to thesystem integrator.

Section 5Station communication


507

KIOSK 2 KIOSK 3

Station HSIBase System

EngineeringWorkstation

SMSGateway

Printer

CC

en06000195.vsd

KIOSK 1

Figure 198: SA system with IEC 61850

This example shows the GOOSE peer-to-peer communication.

Control Protection Control ProtectionControl and protection

GOOSE

en05000734.vsd

Station HSIMicroSCADA

Gateway

IEDA

IEDA

IEDA

IEDA

IEDA

Figure 199: Example of a broadcasted GOOSE message



REG 670

5.2.2 Setting guidelinesThere are only two settings related to the IEC 61850–8–1 protocol, available to theuser in PST:

Operation User can set it to “On” or “Off”.

GOOSE has to be set to the Ethernet link where GOOSE traffic shall be send andreceived.

IEDName That specific IED name in the IEC 61850–8–1 system However, there arespecific settings for the network interface (Ethernet) that are directly related to theIEC 61850–8–1 (but not only) in case this protocol is used. The IEDName is notsettable through PST. The IEDName is given by the name of the IED in the PCMNavigation structure. The name shown as the "IEDName" parameter is a read-onlyfeedback of the current name of the IED on IEC61850.

IEC 61850–8–1 specific data (logical nodes etc.) per included function in an IED canbe found iin a separate document, refer to section "Related documents".

5.2.3 Generic single point function block (SPGGIO)

5.2.3.1 Application

The SPGGIO function block is used to send one single logical output to other systemsor equipment in the substation. It has one visible input, that should be connected inCAP.


There are no settings available for the user for SPGGIO. However, to get the signalssent by SPGGIO one must use the engineering tools described in chapter "Engineering of the IED".



5.2.4 Generic measured values function block (MVGGIO)

5.2.4.1 Application

The MVGGIO function block is used to send the instantaneous value of an analogoutput to other systems or equipment in the substation. It can also be used inside thesame IED, to attach a “RANGE” aspect to an analog value and to permit measurementsupervision on that value.



509


The settings available for the MVGGIO function allows the user to choose a deadbandand a zero deadband for the monitored signal. Values within the zero deadband areconsidered as zero.

The high and low limit settings provides limits for the high-high-, high, normal, lowand low-low ranges of the measured value. The actual range of the measured valueis shown on the range output of the MVGGIO function block. When a measured valueexpander block (RANGE_XP) is connected to the range output, the logical outputsof the RANGE_XP are changed accordingly.


Table 152: Basic general settings for the MVGGIO (MV01-) function

Parameter Range Step Default Unit DescriptionMV db 1 - 300 1 10 Type Cycl: Report interval


MV zeroDb 0 - 100000 1 500 m% Zero point clamping in0,001% of range

MV hhLim -10000000000.000 -10000000000.000

0.001 90.000 - High High limit

MV hLim -10000000000.000 -10000000000.000

0.001 80.000 - High limit

MV lLim -10000000000.000 -10000000000.000

0.001 -80.000 - Low limit

MV llLim -10000000000.000 -10000000000.000

0.001 -90.000 - Low Low limit

MV min -10000000000.000 -10000000000.000

0.001 -100.000 - Minimum value

MV max -10000000000.000 -10000000000.000

0.001 100.000 - Maximum value

MV dbType CyclicDead bandInt deadband

- Dead band - Reporting type

MV limHys 0.000 - 100.000 0.001 5.000 % Hysteresis value in %of range (common forall limits)




REG 670

Table 153: Basic general settings for the IEC61850-8-1 (IEC1-) function


ON- Off - Operation Off/On

GOOSE FrontOEM311_ABOEM311_CD

- OEM311_AB - Port for GOOSEcommunication

5.3 LON communication protocol

5.3.1 Application

Control Center

IED670 IED670IED670

Gateway

Star couplerRER 111

Station HSIMicroSCADA

en05000663.vsd

Figure 200: Example of LON communication structure for a substationautomation system.

An optical network can be used within the Substation Automation system. Thisenables communication with the IED 670s through the LON bus from the operator’sworkplace, from the control center and also from other IEDs via bay-to-bay horizontalcommunication.

The fiber optic LON bus is implemented using either glass core or plastic core fiberoptic cables.



511

Table 154: Specification of the fiber optic connectors

Glass fiber Plastic fiberCable connector ST-connector snap-in connector

Cable diameter 62.5/125 m 1 mm

Max. cable length 1000 m 10 m

Wavelength 820-900 nm 660 nm

Transmitted power -13 dBm (HFBR-1414) -13 dBm (HFBR-1521)

Receiver sensitivity -24 dBm (HFBR-2412) -20 dBm (HFBR-2521)

The LON ProtocolThe LON protocol is specified in the LonTalkProtocol Specification Version 3 fromEchelon Corporation. This protocol is designed for communication in controlnetworks and is a peer-to-peer protocol where all the devices connected to the networkcan communicate with each other directly. For more information of the bay-to-baycommunication, refer to the section Multiple command function

Hardware and software modulesThe hardware needed for applying LON communication depends on the application,but one very central unit needed is the LON Star Coupler and optical fibres connectingthe star coupler to the IEDs. To interface the IEDs from MicroSCADA, the applicationlibrary LIB 670 is required.

The HV Control 670 software module is included in the LIB 520 high-voltage processpackage, which is a part of the Application Software Library within MicroSCADAapplications.

The HV Control 670 software module is used for control functions in IED 670s. Thismodule contains the process picture, dialogues and a tool to generate the processdatabase for the control application in MicroSCADA.

Use the LNT, LON Network Tool to set the LON communication. This is a softwaretool applied as one node on the LON bus. In order to communicate via LON, the IEDsneed to know which node addresses the other connected IEDs have, and whichnetwork variable selectors should be used. This is organized by the LNT.

The node address is transferred to the LNT via the local HMI by setting the parameterServicePinMsg=YES. The node address is sent to the LNT via the LON bus, or theLNT can scan the network for new nodes.

The communication speed of the LON bus is set to the default of 1.25 Mbit/s.Thiscan be changed by the LNT.




REG 670

Table 155: General settings for the NVLON (NV---) function


On- Off - Operation

Table 156: General settings for the LON (ADE1-) function


On- Off - Operation

TimerClass SlowNormalFast

- Slow - Timer class

5.4 SPA communication protocol

5.4.1 ApplicationThe communication protocol SPA is available for the IED 670 products as an optionand as an alternative to IEC 60870-5-103. The same communication port as for IEC60870-5-103 is used.

SPA communication is applied when using the front communication port. For thispurpose, no serial communication module is required in the IED. Only the PCM 600software in the PC and a crossed-over Ethernet cable for front connection is required.

When communicating with a PC see figure 201, using the rear SPA port on the serialcommunication module (SLM), the only hardware required for a local monitoringsystem is:

• Optical fibres for the SPA bus loop• Optical/electrical converter for the PC• PC

A remote monitoring system for communication over the public telephone networkalso requires telephone modems and a remote PC.

The software required for a local monitoring system is PCM 600, and for a remotemonitoring system it is PCM 600 in the remote PC only.



513

Local monitoringsystem with

PCM600

IED670 IED670IED670

Optical to electricalconverter, e.g. SPA-ZC 22

or Fiberdata modem

Telephone

modem

Telephone

modem

Remote monitoringsystem with

PCM600

en05000672.vsd

Figure 201: SPA communication structure for a monitoring system. Themonitoring system can either be local, remote or a combination ofboth

When communicating with a PC connected to the utility substation LAN, via WANand the utility office LAN (see figure 2), and using the rear Ethernet port on the opticalEthernet module (OEM), the only hardware required for a station monitoring systemis:

• Optical fibers from the IED to the utility substation LAN.• PC connected to the utility office LAN.

The software required is PCM 600.

IED670 IED670IED670

Substation LAN

en05000715.vsd

Remotemonitoringsystem with

PCM600

Utility LAN

WAN

Figure 202: SPA communication structure for a remote monitoring system via asubstation LAN, WAN and utility LAN.

The SPA communication is mainly used for the Station Monitoring System. It caninclude different numerical relays/terminals/IEDs with remote communicationpossibilities. Connection to a personal computer (PC) can be made directly (if the PCis located in the substation) or by telephone modem through a telephone network withITU (former CCITT) characteristics or via a LAN/WAN connection.



REG 670

glass <1000 m according to optical budget

plastic <20 m (inside cubicle) according to optical budget

FunctionalityThe SPA protocol V2.5 is an ASCII-based protocol for serial communication. Thecommunication is based on a master-slave principle, where the IED is a slave and thePC is the master. Only one master can be applied on each fiber optic loop. A programis required in the master computer for interpretation of the SPA-bus codes and fortranslation of the data that should be sent to the IED.

The specification of the SPA protocol V2.5 is available as a separate document, SPA-bus Communication Protocol V2.5, 1MRS 750076-MTD EN

5.4.2 Setting guidelinesThe setting parameters for the SPA communication are set via the local HMI.

The SPA and the IEC use the same rear communication port. To define the protocolto be used, a setting is done on the local HMI. Refer to the ”Installation andcommissioning manual” for setting procedure.

When the communication protocol has been selected, the power to the IED must beswitched off and on.

The most important settings in the IED for SPA communication are the slave numberand baud rate (communication speed). These settings are absolutely essential for allcommunication contact to the IED.

These settings can only be done on the local HMI for rear channel communicationand for front channel communication.

The slave number can be set to any value from 1 to 899, as long as the slave numberis unique within the used SPA loop.

The baud rate, which is the communication speed, can be set to between 300 and38400 baud. The baud rate should be the same for the whole station, although differentbaud rates in a loop are possible. If different baud rates in the same fibre optical loopare used, consider this when making the communication setup in the communicationmaster, the PC.

For local fibre optic communication, 19200 or 38400 baud is the normal setting. Iftelephone communication is used, the communication speed depends on the qualityof the connection and on the type of modem used. But remember that the IED doesnot adapt its speed to the actual communication conditions, because the speed is seton the HMI of the IED.




515

Table 157: General settings for the SPA (SPA1-) function

Parameter Range Step Default Unit DescriptionSlaveAddress 1 - 899 1 30 - Slave address

BaudRate 300 Bd1200 Bd4800 Bd9600 Bd19200 Bd38400 Bd57600 Bd

- 9600 Bd - Baudrate onserial line

Table 158: General settings for the SPAviaSLM (SPA1-) function


BaudRate 300 Bd1200 Bd4800 Bd9600 Bd19200 Bd38400 Bd

- 9600 Bd - Baudrate onserial line

Table 159: General settings for the SPAviaLON (SPA4-) function


On- Off - Operation

SlaveAddress 1 - 899 1 30 - Slave address

5.5 IEC 60870-5-103 communication protocol

5.5.1 ApplicationThe communication protocol IEC 60870-5-103 is available for the IED 670 productsas an option.



REG 670

TCP/IP

Control Center

IED670 IED670IED670

Gateway

Star couplerRER 123

Station HSI

en05000660.vsd

Figure 203: Example of IEC 60870-5-103 communication structure for asubstation automation system.

The IEC 60870-5-103 communication protocol is mainly used when a protection IEDcommunicates with a third party control or monitoring system. This system must havesoftware that can interpret the IEC 60870-5-103 communication messages.

Table 160: Max distances between IED/nodes

glass < 1000 m according to optical budget

plastic < 20 m (inside cubicle) according to optical budget

FunctionalityThe IEC 60870-5-103 is an unbalanced (master-slave) protocol for coded-bit serialcommunication exchanging information with a control system. In IEC terminologya primary station is a master and a secondary station is a slave. The communicationis based on a point-to-point principle. The master must have software that can interpretthe IEC 60870-5-103 communication messages. For detailed information about IEC60870-5-103, refer to the “IEC60870 standard” part 5: “Transmission protocols”,and to the section 103: “Companion standard for the informative interface ofprotection equipment”.

Design

GeneralThe protocol implementation in IED 670 consists of the following functions:



517

• Event handling• Report of analog service values (measurands)• Fault location• Command handling

• Autorecloser ON/OFF• Teleprotection ON/OFF• Protection ON/OFF• LED reset• Characteristics 1 - 4 (Setting groups)

• File transfer (disturbance files)• Time synchronization

HardwareWhen communicating locally with a Personal Computer (PC) or a Remote TerminalUnit (RTU) in the station, using the SPA/IEC port, the only hardware needed is:·Optical fibres, glass/plastic· Opto/electrical converter for the PC/RTU· PC/RTU

CommandsThe commands defined in the IEC 60870-5-103 protocol are represented in adedicated function blocks. These blocks have output signals for all availablecommands according to the protocol.

• Terminal commands in control direction

Function block with defined IED functions in control direction, I103IEDCMD. Thisblock use PARAMETR as FUNCTION TYPE, and INFORMATION NUMBERparameter is defined for each output signal.

• Function commands in control direction

Function block with pre defined functions in control direction, I103CMD. This blockincludes the FUNCTION TYPE parameter, and the INFORMATION NUMBERparameter is defined for each output signal.

• Function commands in control direction

Function block with user defined functions in control direction, I103UserCMD. Thesefunction blocks include the FUNCTION TYPE parameter for each block in the privaterange, and the INFORMATION NUMBER parameter for each output signal.

StatusThe events created in the IED available for the IEC 60870-5-103 protocol are basedon the:



REG 670

• IED status indication in monitor direction

Function block with defined IED functions in monitor direction, I103IED. This blockuse PARAMETER as FUNCTION TYPE, and INFORMATION NUMBERparameter is defined for each input signal.

• Function status indication in monitor direction, user-defined

Function blocks with user defined input signals in monitor direction, I103UserDef.These function blocks include the FUNCTION TYPE parameter for each block inthe private range, and the INFORMATION NUMBER parameter for each inputsignal.

• Supervision indications in monitor direction

Function block with defined functions for supervision indications in monitordirection, I103Superv. This block includes the FUNCTION TYPE parameter, andthe INFORMATION NUMBER parameter is defined for each output signal.

• Earth fault indications in monitor direction

Function block with defined functions for earth fault indications in monitor direction,I103EF. This block includes the FUNCTION TYPE parameter, and theINFORMATION NUMBER parameter is defined for each output signal.

• Fault indications in monitor direction, type 1

Function block with defined functions for fault indications in monitor direction,I103FltDis. This block includes the FUNCTION TYPE parameter, and theINFORMATION NUMBER parameter is defined for each input signal. This blockis suitable for distance protection function.

• Fault indications in monitor direction, type 2

Function block with defined functions for fault indications in monitor direction,I103FltStd. This block includes the FUNCTION TYPE parameter, and theINFORMATION NUMBER parameter is defined for each input signal.

This block is suitable for line differential, transformer differential, over-current andearth-fault protection functions.

• Autorecloser indications in monitor direction

Function block with defined functions for autorecloser indications in monitordirection, I103AR. This block includes the FUNCTION TYPE parameter, and theINFORMATION NUMBER parameter is defined for each output signal.



519

MeasurandsThe measurands can be included as type 3.1, 3.2, 3.3, 3.4 and type 9 according to thestandard.

• Measurands in public range

Function block that reports all valid measuring types depending on connected signals,I103Meas.

• Measurands in private range

Function blocks with user defined input measurands in monitor direction,I103MeasUsr. These function blocks include the FUNCTION TYPE parameter foreach block in the private range, and the INFORMATION NUMBER parameter foreach block.

Fault locationThe fault location is expressed in reactive ohms. In relation to the line length inreactive ohms, it gives the distance to the fault in percent. The data is available andreported when the fault locator function is included in the IED.

Disturbance Recordings

• The transfer functionality is based on the Disturbance recorder function. Theanalog and binary signals recorded will be reported to the master by polling. Theeight last disturbances that are recorded are available for transfer to the master.A file that has been transferred and acknowledged by the master cannot betransferred again.

• The binary signals that are reported by polling are those that are connected to thedisturbance function blocks DRB1 – DRB6. These function blocks include thefunction type and the information number for each signal. See also the descriptionof the Disturbance report in the “Technical reference manua”l. The analogchannels, that are reported, are those connected to the disturbance function blocksDRA1 – DRA4. The eight first ones belong to the public range and the remainingones to the private range.

Settings

Settings from the local HMIThe SPA and the IEC communication use the same rear port. To define the protocolto be used, a setting is done on the local HMI under the menu:

Settings/General Settings/Communication/SLM Configuration/Rear optical SPA-IEC port/Protocol selection for SPA or IEC103

When the communication protocols have been selected, the IED is automaticallyrestarted.

The settings for IEC 60870-5-103 communication are the following:



REG 670

• Settings for slave number and baud rate (communication speed)• Setting for invert the light or not• Setting for reporting frequency of mesurands

The settings for communication parameters slave number and baud rate can be foundon the local HMI at:

Settings/General Settings/Communication/SLM Configuration/Rear optical SPA-IEC port/IEC60870-5-103

The slave number can be set to any value between 0 to 255.

The baud rate, the communication speed, can be set either to 9600 bits/s or 19200bits/s.

Settings from the PCM 600 toolEventFor each input of the Event function there is a setting for the information number ofthe connected signal. The information number can be set to any value between 0 and255. In order to get proper operation of the sequence of events the event masks in theevent function shall be set to ON_CHANGE. For single-command signals, the eventmask shall be set to ON_SET.

In addition there is a setting on each event block for function type. Refer to descriptionof the “Main Function type set on the local HMI”.

CommandsAs for the commands defined in the protocol there is a dedicated function block witheight output signals. Using the CAP 531 tool makes the configuration of these signals.To realize the BlockOfInformation command, which is operated from the local HMI,the output BLKINFO on the IEC command function block ICOM has to be connectedto an input on an event function block. This input shall have the information number20 (monitor direction blocked) according to the standard.

Disturbance RecordingsFor each input of the Disturbance recorder function there is a setting for theinformation number of the connected signal. The information number can be set toany value between 0 and 255.

Furthermore there is a setting on each input of the Disturbance recorder function forthe function type. Refer to description of ”Main Function type set on the local HMI”.

Function and information typesThe function type is defined as follows:

128 = distance protection

160 = overcurrent protection

176 = transformer differential protection



521

192 = line differential protection

Please see the tables in the “Technical reference manual /Station communication”,specifying the information types supported by the 670IED products with thecommunication protocol IEC 60870-5-103 implemented.

To support the information, corresponding functions must be included in theprotection IED.

There is no representation for the following parts:

• Generating events for test mode• Cause of transmission: Info no 11, Local operation

EIA RS-485 is not supported. Glass or plastic fiber should be used. BFOC/2.5 is therecommended interface to use (BFOC/2.5 is the same as ST connectors). STconnectors are used with the optical power as specified in standard.

For more information please see the “IEC standard IEC 60870-5-103”.


Table 161: General settings for the I103SLM (IECC-) function


BaudRate 9600 Bd19200 Bd

- 9600 Bd - Baudrate on serialline

RevPolarity OffOn

- On - Invert polarity

CycMeasRepTime

1.0 - 3600.0 0.1 5.0 - Cyclic reporting timeof measurments

Table 162: General settings for the I103IEDCMD (ICMA-) function

Parameter Range Step Default Unit DescriptionFUNTYPE 1 - 255 1 255 FunT Function type (1-255)

Table 163: General settings for the I103CMD (ICMD-) function




REG 670

Table 164: General settings for the I103IED (IEV1-) function


Table 165: General settings for the I103UserCMD (ICM1-) function

Parameter Range Step Default Unit DescriptionPULSEMOD 0 - 1 1 1 Mode Pulse mode

0=Steady, 1=Pulsed

T 0.200 - 60.000 0.001 0.400 s Pulse length

FUNTYPE 1 - 255 1 1 FunT Function type (1-255)

INFNO_1 1 - 255 1 1 InfNo Information numberfor output 1 (1-255)








Table 166: General settings for the I103UsrDef (IS01-) function


INFNO_1 1 - 255 1 1 InfNo Information numberfor binary input 1(1-255)








523

Parameter Range Step Default Unit DescriptionINFNO_6 1 - 255 1 6 InfNo Information number

for binary input 6(1-255)



Table 167: General settings for the I103Superv (ISU1-) function


Table 168: General settings for the I103EF (ISEF-) function


Table 169: General settings for the I103FltDis (IZ01-) function


Table 170: General settings for the I103FltStd (IFL1-) function


Table 171: General settings for the I103MeasUsr (IMU1-) function


INFNO 1 - 255 1 1 InfNo Information numberfor measurands(1-255)

RatedMeasur1 0.05 -10000000000.00

0.05 1000.00 - Rated value formeasurement oninput 1

RatedMeasur2 0.05 -10000000000.00





REG 670

Parameter Range Step Default Unit DescriptionRatedMeasur3 0.05 -

10000000000.000.05 1000.00 - Rated value for

measurement oninput 3

RatedMeasur4 0.05 -10000000000.00


RatedMeasur5 0.05 -10000000000.00


RatedMeasur6 0.05 -10000000000.00


RatedMeasur7 0.05 -10000000000.00


RatedMeasur8 0.05 -10000000000.00


RatedMeasur9 0.05 -10000000000.00


Table 172: Basic general settings for the I103Meas (IMM1-) function

Parameter Range Step Default Unit DescriptionRatedIL1 1 - 99999 1 3000 A Rated current phase

L1

RatedIL2 1 - 99999 1 3000 A Rated current phaseL2

RatedIL3 1 - 99999 1 3000 A Rated current phaseL3

RatedIN 1 - 99999 1 3000 A Rated residualcurrent IN

RatedUL1 0.05 - 2000.00 0.05 230.00 kV Rated voltage forphase L1



RatedUL1-UL2 0.05 - 2000.00 0.05 400.00 kV Rated voltage forphase-phase L1-L2

RatedUN 0.05 - 2000.00 0.05 230.00 kV Rated residualvoltage UN

RatedP 0.00 - 2000.00 0.05 1200.00 MW Rated value for activepower

RatedQ 0.00 - 2000.00 0.05 1200.00 MVA Rated value forreactive power

RatedF 50.0 - 60.0 10.0 50.0 Hz Rated systemfrequency

FUNTYPE 1 - 255 1 1 FunT Function type (1-255)



525

5.6 Automation bits (AUBI)

5.6.1 ApplicationThe AUBI function block (or the automation bits function block) is used within theCAP tool in order to get into the configuration the commands coming through theDNP3.0 protocol. In this respect, this function block plays the same role as theBinGOOSEReceive (for IEC61850) or MultiCmdReceive (for LON). The AUBIfunction block have 32 individual outputs which each can be mapped as a BinaryOutput point in DNP. The output is operated by a "Object 12" in DNP. This objectcontains parameters for control-code, count, on-time and off-time. To operate a AUBIoutput point you send a control-code of latch-On, latch-Off, pulse-On, pulse-Off, Tripor Close. The remaining parameters will be regarded were appropriate. ex: pulse-On,on-time=100, off-time=300, count=5 would give you 5 positive 100 ms pulses, 300ms apart.

5.6.2 Setting guidelinesThe AUBI function block has just one setting, (Operation: On/Off) enabling ordisabling the function. The name for each command signal can also be set under CAP.These names will be seen in the DNP communication configuration tool, in the PCM600.


Table 173: Basic general settings for the AutoBits (ABI1-) function



Table 174: Basic general settings for the DNP3 (DNP--) function


ON- Off - Operation mode Off /

On



REG 670

Table 175: Basic general settings for the DNP3Ch1RS485 (DNC1-) function


Serial-Mode- Off - Operation mode

BaudRate 300 Bd600 Bd1200 Bd2400 Bd4800 Bd9600 Bd19200 Bd

- 9600 Bd - Baud-rate for serialport

WireMode Four-wireTwo-wire

- Two-wire - RS485 wire mode

Table 176: Advanced general settings for the DNP3Ch1RS485 (DNC1-) function

Parameter Range Step Default Unit DescriptionDLinkConfirm Never

SometimesAlways

- Never - Data-link confirm

tDLinkTimeout 0.000 - 60.000 0.001 2.000 s Data-link confirmtimeout in s

DLinkRetries 0 - 255 1 3 - Data-link maximumretries

tRxToTxMinDel 0.000 - 60.000 0.001 0.000 s Rx to Tx minimumdelay in s

DataBits 5 - 8 1 8 - Data bits

StopBits 1 - 2 1 1 - Stop bits

Parity NoEvenOdd

- Even - Parity

RTSEnable NoYes

- No - RTS enable

tRTSWarmUp 0.000 - 60.000 0.001 0.000 s RTS warm-up in s

tRTSWarmDown 0.000 - 60.000 0.001 0.000 s RTS warm-down in s

tBackOffDelay 0.000 - 60.000 0.001 0.050 s RS485 back-off delayin s

tMaxRndDelBkOf 0.000 - 60.000 0.001 0.100 s RS485 maximumback-off randomdelay in s



527

Table 177: Basic general settings for the DNP3Ch2TCPIP (DNC2-) function


TCP/IPUDP-Only

- Off - Operation mode

TCPIPLisPort 1 - 65535 1 20000 - TCP/IP listen port

UDPPortAccData 1 - 65535 1 20000 - UDP port to acceptUDP datagrams frommaster

UDPPortInitNUL 1 - 65535 1 20000 - UDP portfor initialNULL response

UDPPortCliMast 0 - 65535 1 0 - UDP port to remoteclient/master



TCP/IPUDP-Only




UDPPortInitNUL 1 - 65535 1 20000 - UDP port for initialNULL response




TCP/IPUDP-Only








REG 670



TCP/IPUDP-Only






Table 181: Basic general settings for the DNP3Mast1RS485 (DNM1-) function




MasterAddres 0 - 65519 1 1 - Master address

Obj1DefVar 1:BISingleBit2:BIWithStatus

- 1:BISingleBit - Object 1, defaultvariation

Obj2DefVar 1:BIChWithoutTime2:BIChWithTime3:BIChWithRelTime

- 3:BIChWithRelTime

- Object 2, defaultvariation

Obj4DefVar 1:DIChWithoutTime2:DIChWithTime3:DIChWithRelTime

- 3:DIChWithRelTime


Obj10DefVar 1:BO2:BOStatus

- 2:BOStatus - Object 10, defaultvariation

Obj20DefVar 1:BinCnt322:BinCnt165:BinCnt32WoutF6:BinCnt16WoutF

- 5:BinCnt32WoutF - Object 20, defaultvariation




529

Parameter Range Step Default Unit DescriptionObj22DefVar 1:BinCnt32EvWou

tT2:BinCnt16EvWoutT5:BinCnt32EvWithT6:BinCnt16EvWithT

- 1:BinCnt32EvWoutT


Obj30DefVar 1:AI32Int2:AI16Int3:AI32IntWithoutF4:AI16IntWithoutF5:AI32FltWithF6:AI64FltWithF

- 3:AI32IntWithoutF - Object 30, defaultvariation

Obj32DefVar 1:AI32IntEvWoutF2:AI16IntEvWoutF3:AI32IntEvWithFT4:AI16IntEvWithFT5:AI32FltEvWithF6:AI64FltEvWithF7:AI32FltEvWithFT8:AI64FltEvWithFT

- 1:AI32IntEvWoutF - Object 32, defaultvariation

Table 182: Advanced general settings for the DNP3Mast1RS485 (DNM1-) function

Parameter Range Step Default Unit DescriptionValMasterAddr No

Yes- Yes - Validate source

(master) address

AddrQueryEnbl NoYes

- Yes - Address query enable

tApplConfTout 0.00 - 60.00 0.01 10.00 s Application layerconfim timeout

ApplMultFrgRes NoYes

- Yes - Enable application formultiple fragmentresponse

ConfMultFrag NoYes

- Yes - Confirm each multiplefragment

UREnable NoYes

- Yes - Unsolicited responseenabled

URSendOnline NoYes

- No - Unsolicited responsesends when on-line

UREvClassMask OffClass 1Class 2Class 1 and 2Class 3Class 1 and 3Class 2 and 3Class 1, 2 and 3

- Off - Unsolicited response,event class mask




REG 670

Parameter Range Step Default Unit DescriptionUROfflineRetry 0 - 10 1 5 - Unsolicited response

retries before off-lineretry mode

tURRetryDelay 0.00 - 60.00 0.01 5.00 s Unsolicited responseretry delay in s

tUROfflRtryDel 0.00 - 60.00 0.01 30.00 s Unsolicited responseoff-line retry delay in s

UREvCntThold1 1 - 100 1 5 - Unsolicited responseclass 1 event countreport treshold

tUREvBufTout1 0.00 - 60.00 0.01 5.00 s Unsolicited responseclass 1 event buffertimeout





DelOldBufFull NoYes

- No - Delete oldest eventwhen buffer is full

tSynchTimeout 1 - 3600 1 1800 s Time synch timeoutbefore error status isgenerated

TSyncReqAfTout NoYes

- Yes - Time synchronizationrequest after timeout

DNPToSetTime NoYes

- No - Allow DNP to set timein IED

Averag3TimeReq NoYes

- No - Use average of 3 timerequests

PairedPoint NoYes

- Yes - Enable paired point

tSelectTimeout 1.0 - 60.0 0.1 30.0 s Select timeout

Table 183: Basic general settings for the DNP3Mast2TCPIP (DNM2-) function





ValMasterAddr NoYes

- Yes - Validate source(master) address




531

Parameter Range Step Default Unit DescriptionMasterIP-Addr 0 - 18 1 0.0.0.0 - Master IP-address

MasterIPNetMsk 0 - 18 1 255.255.255.255 - Master IP net mask




- 3:BIChWithRelTime



- 3:DIChWithRelTime






Obj22DefVar 1:BinCnt32EvWoutT2:BinCnt16EvWoutT5:BinCnt32EvWithT6:BinCnt16EvWithT

- 1:BinCnt32EvWoutT








REG 670

Table 184: Advanced general settings for the DNP3Mast2TCPIP (DNM2-) function

Parameter Range Step Default Unit DescriptionAddrQueryEnbl No

Yes- Yes - Address query enable




ConfMultFrag NoYes


UREnable NoYes


URSendOnline NoYes




UROfflineRetry 0 - 10 1 5 - Unsolicited responseretries before off-lineretry mode









DelOldBufFull NoYes






533

Parameter Range Step Default Unit DescriptionTSyncReqAfTout No

Yes- Yes - Time synchronization

request after timeout

DNPToSetTime NoYes




PairedPoint NoYes



tBrokenConTout 0 - 3600 1 0 s Broken connectiontimeout

tKeepAliveT 0 - 3600 1 10 s Keep-Alive timer






ValMasterAddr NoYes


MasterIP-Addr 0 - 18 1 0.0.0.0 - Master IP-address





- 3:BIChWithRelTime



- 3:DIChWithRelTime









REG 670



- 1:BinCnt32EvWoutT












ConfMultFrag NoYes


UREnable NoYes


URSendOnline NoYes








535

Parameter Range Step Default Unit DescriptiontURRetryDelay 0.00 - 60.00 0.01 5.00 s Unsolicited response

retry delay in s








DelOldBufFull NoYes





DNPToSetTime NoYes




PairedPoint NoYes










ValMasterAddr NoYes





REG 670

Parameter Range Step Default Unit DescriptionMasterIP-Addr 0 - 18 1 0.0.0.0 - Master IP-address





- 3:BIChWithRelTime



- 3:DIChWithRelTime






Obj22DefVar 1:BinCnt32EvWoutT2:BinCnt16EvWoutT5:BinCnt32EvWithT6:BinCnt16EvWithT

- 1:BinCnt32EvWoutT








537







ConfMultFrag NoYes


UREnable NoYes


URSendOnline NoYes













DelOldBufFull NoYes






REG 670

Parameter Range Step Default Unit DescriptionTSyncReqAfTout No

Yes- Yes - Time synchronization

request after timeout

DNPToSetTime NoYes




PairedPoint NoYes










ValMasterAddr NoYes


MasterIP-Addr 0 - 18 1 0.0.0.0 - Master IP-address





- 3:BIChWithRelTime



- 3:DIChWithRelTime









539



- 1:BinCnt32EvWoutT












ConfMultFrag NoYes


UREnable NoYes


URSendOnline NoYes








REG 670

Parameter Range Step Default Unit DescriptiontURRetryDelay 0.00 - 60.00 0.01 5.00 s Unsolicited response

retry delay in s








DelOldBufFull NoYes





DNPToSetTime NoYes




PairedPoint NoYes





5.7 Single command, 16 signals (CD)

5.7.1 ApplicationThe single command, 16 signals (CD) is a common function and always included inthe IED.



541

The IEDs may be provided with a function to receive commands either from asubstation automation system or from the local human-machine interface, HMI. Thatreceiving function block has outputs that can be used, for example, to control highvoltage apparatuses in switchyards. For local control functions, the local HMI canalso be used. Together with the configuration logic circuits, the user can govern pulsesor steady output signals for control purposes within the IED or via binary outputs.

Figure 204 shows an application example of how the user can, in an easy way, connectthe command function via the configuration logic circuit to control a high-voltageapparatus. This type of command control is normally carried out by sending a pulseto the binary outputs of the IED. Figure 204 shows a close operation. An “openbreaker” operation is performed in a similar way but without the synchro-checkcondition.

SinglecommandfunctionCDxxSingleCmdFunc

CMDOUTy

OUTy

Close CB1

&User-definedconditionsSynchro-check

Configuration logic circuits

en04000206.vsd

Figure 204: Application example showing a logic diagram for control of a circuitbreaker via configuration logic circuits.

Figure 205 and figure 206 show other ways to control functions, which require steadyOn/Off signals. Here, the output is used to control built-in functions or externaldevices.



REG 670


CMDOUTy

OUTy

Function n

en04000207.vsd

Function n

Figure 205: Application example showing a logic diagram for control of built-infunctions.


CMDOUTy

OUTy

Device 1

User-definedconditions

Configuration logic circuits

en04000208.vsd

&

Figure 206: Application example showing a logic diagram for control of externaldevices via configuration logic circuits.

5.7.2 Setting guidelinesThe parameters for the single command, 16 signals, function (CD) are set via the localHMI or Protection and Control IED Manager (PCM 600).



543

Parameters to be set are MODE, common for the whole block, and CMDOUTy whichincludes the user defined name for each output signal. The MODE input sets theoutputs to be one of the types Off, Steady, or Pulse.

• Off, sets all outputs to 0, independent of the values sent from the station level,that is, the operator station or remote-control gateway.

• Steady, sets the outputs to a steady signal 0 or 1, depending on the values sentfrom the station level.

• Pulse, gives a pulse with 100 ms duration, if a value sent from the station levelis changed from 0 to 1. That means that the configured logic connected to thecommand function block may not have a cycle time longer than the cycle timefor the command function block.


Table 191: Basic general settings for the SingleCmd (CD01-) function

Parameter Range Step Default Unit DescriptionMode Off

SteadyPulsed


5.8 Multiple command (CM) and Multiple transmit(MT)

5.8.1 ApplicationThe IED may be provided with a function to send and receive signals to and fromother IEDs via the interbay bus. The send and receive function blocks has 16 outputs/inputs that can be used, together with the configuration logic circuits, for controlpurposes within the IED or via binary outputs. When it is used to communicate withother IEDs, these IEDs have a corresponding Multiple transmit function block with16 outputs to send the information received by the command block.

5.8.2 Setting guidelines

5.8.2.1 Settings

The parameters for the multiple command function are set via the Protection andControl IED Manager (PCM 600).

The MODE input sets the outputs to be one of the types Off, Steady, or Pulse.




REG 670

Table 192: General settings for the MultiCmd (CM01-) function

Parameter Range Step Default Unit DescriptiontMaxCycleTime 0.050 - 200.000 0.001 11.000 s Maximum cycle time

between receptions ofinput data

tMinCycleTime 0.000 - 200.000 0.001 0.000 s Minimum cycle timebetween receptions ofinput data

Mode SteadyPulsed

- Steady - Mode for outputsignals

tPulseTime 0.000 - 60.000 0.001 0.200 s Pulse length for multicommand outputs

Table 193: General settings for the MultiTransm (MT01-) function

Parameter Range Step Default Unit DescriptiontMaxCycleTime 0.000 - 200.000 0.001 5.000 s Maximum time

interval betweentransmission of outputdata

tMinCycleTime 0.000 - 200.000 0.001 0.000 s Minimum time intervalbetween transmissionof output data



545

Section 6 Remote communication

About this chapterThis chapter describes the remote end data communication possibilities throughbinary signal transferring.

6.1 Binary signal transfer to remote end

Function block name: BSR--, BST-- IEC 60617 graphical symbol: ANSI number:

IEC 61850 logical node name:BSDGGIO

Function block name: BRx--;BTx-- IEC 60617 graphical symbol: ANSI number:

IEC 61850 logical node name: BSTGGIO

6.1.1 ApplicationIED 670s can be equipped with communication devices for line differentialcommunication and/or communication of binary signals between IEDs. The samecommunication hardware is used for both purposes.

Communication between two IEDs geographically on different locations is afundamental part of the line differential function.

Sending of binary signals between two IEDs, one in each end of a power line is usedin teleprotection schemes and for direct transfer trips. In addition to this, there areapplication possibilities like e.g. blocking/enabling functionality in the remotesubstation, changing setting group in the remote IED depending on the switchingsituation in the local substation etc.

When equipped with an LDCM, a 64 kbit/s communication channel can be connectedto the IED, which will then have the capacity of 192 binary signals to becommunicated with a remote IED. For RED 670 the number of binary signals islimited to 8 because the line differential communication is included in the sametelegrams.

Section 6Remote communication


547

6.1.1.1 Communication hardware solutions

The LDCM (Line Data Communication Module) has an optical connection such thattwo IEDs can be connected over a direct fibre (multimode), as shown in figure 207 .The protocol used is IEEE/ANSI C37.94. The maximum distance with this solutionis approximately 150 km.

LDCM

LDCM

LDCM

LDCMLDCM

LDCMLDCMLDCM

LDCMLDCM

LDCM

LDCMLD

CMLD

CM

LDCMLDCM

Max 150 km with long-rangeLDCM and single mode fibre

en06000519.vsd

Figure 207: Direct fibre optical connection between two IEDs with LDCM.

The LDCM can also be used together with an external optical to galvanic G.703converter or with an alternative external optical to galvanic X.21 converter as shownin figure 208. These solutions are aimed for connections to a multiplexer, which inturn is connected to a telecommunications transmission network (e.g. SDH or PDH).

LDCM

LDCM

LDCM

LDCM

Telecom. Network

*) *)

Multiplexer Multiplexer

LDCM

LDCMLDCMLDCM

LDCMLDCM

LDCM

LDCMLD

CMLD

CM

LDCMLDCM

en05000527.vsd*) Converting optical to galvanic G.703 or X.21 alternatively

Figure 208: LDCM with an external optical to galvanic converter and amultiplexer.

When an external modem G.703 or X21 is used, the connection between LDCM andthe modem is made with a multimode fibre of max. 3 km length. The IEEE/ANSIC37.94 protocol is always used between LDCM and the modem.



REG 670

Alternatively, an LDCM with X.21 built-in converter and micro D-sub 15-poleconnector output can be used.

6.1.2 Setting guidelinesChannelMode: This parameter can be set On or Off. Besides this, it can be setOutOfService which signifies that the local LDCM is out of service. Thus, with thissetting, the communication channel is active and a message is sent to the remote IEDthat the local IED has its communication out of service.

TerminalNo: This setting assigns a number to the local IED. Up to 256 IEDs can beassigned unique numbers. For a line differential protection, maximum 6 IEDs can beincluded. The possibility to use the large number of IED designations is reserved forthe case where a high security against incorrect addressing in multiplexed systems isdesired.

RemoteTermNo: This setting assigns a number to the remote IED.

DiffSync: Here the method of time synchronization, PingPong or GPS, for the linedifferential function is selected.

GPSSyncErr: If GPS synchronization is lost, the synchronization of the linedifferential function will continue during 16 s. based on the stability in the local IEDclocks. Thereafter the setting Block will block the line differential function or thesetting PingPong will make it continue by using the PingPong synchronizationmethod. It shall be noticed that using PingPong in this situation is only safe as longas there is no risk of varying transmission asymmetry.

CommSync: This setting decides the Master/Slave relation in the communicationsystem and shall not be mistaken for the synchronization of line differential currentsamples. When direct fibre is used, one LDCM is set as Master and the other one asSlave. When a modem and multiplexer is used, the IED is always set as Slave, as thetelecommunication system will provide the clock master.

OptoPower: The setting LowPower is used for fibres 0 – 1 km and HighPower forfibres >1 km.

TransmCurr: This setting decides which of 2 possible local currents that shall betransmitted, or if and how the sum of 2 local currents shall be transmitted, or finallyif the channel shall be used as a redundant channel.

In a 1½ breaker arrangement, there will be 2 local currents, and the earthing on theCTs can be different for these. CT-SUM will transmit the sum of the 2 CT groups.CT-DIFF1 will transmit CT group 1 minus CT group 2 and CT-DIFF2 will transmitCT group 2 minus CT group 1.

CT-GRP1 or CT-GRP2 will transmit the respective CT group, and the settingRedundantChannel makes the channel be used as a backup channel.



549

ComFailAlrmDel: Time delay of communication failure alarm. In communicationsystems, route switching can sometimes cause interruptions with a duration up to 50ms. Thus, a too short time delay setting might cause nuisance alarms in thesesituations.

ComFailResDel: Time delay of communication failure alarm reset.

RedChSwTime: Time delay before switchover to a redundant channel in case ofprimary channel failure.

RedChRturnTime: Time delay before switchback to a the primary channel afterchannel failure.

AsymDelay: The asymmetry is defined as transmission delay minus receive delay. Ifa fixed asymmetry is known, the PingPong synchronization method can be used ifthe parameter AsymDelay is properly set. From the definition follows that theasymmetry will always be positive in one end, and negative in the other end.

MaxTransmDelay: Data for maximum 40 ms transmission delay can be buffered up.Delay times in the range of some ms are common. It shall be noticed that if data arrivein the wrong order, the oldest data will just be disregarded.

CompRange: The set value is the current peak value over which truncation will bemade. To set this value, knowledge of the fault current levels should be known. Thesetting is not overly critical as it considers very high current values for which correctoperation normally still can be achieved.


Table 194: Basic general settings for the LDCMRecBinStat (CRM1-) function

Parameter Range Step Default Unit DescriptionChannelMode Off

OnOutOfService

- On - Channel mode ofLDCM, 0=OFF,1=ON,2=OutOfService

TerminalNo 0 1 0 - 255 - Terminal numberused for linedifferentialcommunication

RemoteTermNo 0 1 0 - 255 - Terminal number onremote terminal

DiffSync EchoGPS

- Echo - Diff Synchronizationmode of LDCM,0=ECHO, 1=GPS

GPSSyncErr BlockEcho

- Block - Operation modewhen GPSsynchroniation signalis lost

CommSync SlaveMaster

- Slave - Com Synchronizationmode of LDCM,0=Slave, 1=Master




REG 670

Parameter Range Step Default Unit DescriptionOptoPower LowPower

HighPower- LowPower - Transmission power

for LDCM, 0=Low,1=High

TransmCurr CT-GRP1CT-GRP2CT-SUMCT-DIFF1CT-DIFF2

- CT-GRP1 - Summation mode fortransmitted currentvalues

ComFailAlrmDel 5 - 500 5 100 ms Time delay beforecommunication errorsignal is activated

ComFailResDel 5 - 500 5 100 ms Reset delay beforecommunication errorsignal is reset

RedChSwTime 5 - 500 5 5 ms Time delay beforeswitching inredundant channel

RedChRturnTime 5 - 500 5 100 ms Time delay beforeswitching back fromredundant channel

AsymDelay -20.00 - 20.00 0.01 0.00 ms Asymmetric delaywhen communicationuse echo synch.

MaxTransmDelay 0 - 40 1 20 ms Max allowedtransmission delay

CompRange 0-10kA0-25kA0-50kA0-150kA

- 0-25kA - Compression range

MaxtDiffLevel 200 - 2000 1 600 us Maximum time diff forECHO back-up

DeadbandtDiff 200 - 1000 1 300 us Deadband for t Diff

InvertPolX21 OffOn

- Off - Invert polarization forX21 communication

Table 195: Basic general settings for the LDCMRecBinStat (CRM2-) function


OnOutOfService


TerminalNo 0 1 0 - 255 - Terminal numberused for linedifferentialcommunication

RemoteTermNo 0 1 0 - 255 - Terminal number onremote terminal

DiffSync EchoGPS

- Echo - Diff Synchronizationmode of LDCM,0=ECHO, 1=GPS




551

Parameter Range Step Default Unit DescriptionGPSSyncErr Block

Echo- Block - Operation mode

when GPSsynchroniation signalis lost



OptoPower LowPowerHighPower

- LowPower - Transmission powerfor LDCM, 0=Low,1=High

TransmCurr CT-GRP1CT-GRP2CT-SUMCT-DIFF1CT-DIFF2RedundantChannel

- CT-GRP1 - Summation mode fortransmitted currentvalues



RedChSwTime 5 - 500 5 5 ms Time delay beforeswitching inredundant channel

RedChRturnTime 5 - 500 5 100 ms Time delay beforeswitching back fromredundant channel

AsymDelay -20.00 - 20.00 0.01 0.00 ms Asymmetric delaywhen communicationuse echo synch.

MaxTransmDelay 0 - 40 1 20 ms Max allowedtransmission delay

CompRange 0-10kA0-25kA0-50kA0-150kA

- 0-25kA - Compression range

MaxtDiffLevel 200 - 2000 1 600 us Maximum time diff forECHO back-up

DeadbandtDiff 200 - 1000 1 300 us Deadband for t Diff

InvertPolX21 OffOn




REG 670

Table 196: Basic general settings for the LDCMRecBinStat (CRB1-) function


OnOutOfService


TerminalNo 0 - 255 1 0 - Terminal numberused for linedifferentialcommunication

RemoteTermNo 0 - 255 1 0 - Terminal number onremote terminal



OptoPower LowPowerHighPower

- LowPower - Transmission powerfor LDCM, 0=Low,1=High



InvertPolX21 OffOn




553

Section 7 Configuration

About this chapterThis chapter describes the IED configurations.

7.1 Introduction

7.2 Description of REG 670

7.2.1 Introduction

7.2.1.1 Description of configuration A20

Configuration 1MRK004826–AA

This configuration is used in applications where only generator protection within oneIED is required. The REG 670-A20 is always delivered in 1/2 of 19" case size. Thusonly 12 analogue inputs are available. This configuration includes generator lowimpedance, differential protection and all other typically required generatorprotection functions. Note that 100% stator earth fault function and Pole Slipprotection function are optional. See figure 209, example of one possible applicationis shown.

Section 7Configuration


555

GI

U

OC4 PTOC

51/67 3I>

CV GAPC

64R Re<

ROV2 PTOV

59N UN>

STEF PHIZ

59THD U3d/N

GEN PDIF

87G 3Id/I

SA PTUF

81 f<

SA PTOF

81 f>

SDD RFUF

60FL

OEX PVPH

24 U/f>

UV2 PTUV

27 3U<

OV2 PTOV

59 3U>

CV MMXU

Meter.

Option

SDE PSDE

32N P0->

REG 670*1.1 – A20

Gen Diff + Back-up 12AI

ZMH PDIS

21 Z<

LEX PDIS

40 F <

GUP PDUP

37 P<

GOP PDOP

32 P

CV GAPC

46 I2>

CV GAPC

51/27 U

ROV2 PTOV

59N UN>

CC RBRF

50BF 3I> BF

TR PTTR

49 Ith

PSP PPAM

78 Ucos

SES RSYN

25

CV GAPC

51V I>/U

PH PIOC

50 3I>>

CV GAPC

50AE U/I>

CC RPLD

52PD PD

OC4 PTOC

51/67 3I>

Other functions available from the function library

+ RXTTE4

Please note that the use of function might require a different analog input!

en07000049.vsd

CC RDIF

87CT I2d/I

Function alternatives for 87G/GEN PDIF

T2W PDIF

87T 3Id/I

HZ PDIF

87 IdN

Figure 209: Typical generator protection application with generator differentialand back-up protection, including 12 analog input transformers andhalf 19” case size.

Note that inside the REG 670-A20 functional library additional functions areavailable, but not configured, such as additional Overcurrent protection, additionalMultipurpose protection functions, Synchrocheck function, etc as shown in figure209. It is as well possible to order optional 2-winding transformer differential or highimpedance differential protection functions which than can be used instead of basiclow-impedance generator differential protection. Note that REG 670-A20 must bere-configured if any additional or optional functions going to be used.



REG 670

7.2.1.2 Description of configuration B30

Configuration 1MRK004826–BA

This configuration is used in applications where generator protection and backupprotection for surrounding primary equipment within one IED is required. The REG670-B30 is always delivered in 1/1 of 19" case size. Thus 18 or 24 analogue inputsare available, depending on order type of TRMs. This configuration includesgenerator low impedance, differential protection and all other typically requiredgenerator protection functions. Note that 100% stator earth fault function is basicwhile the Pole Slip protection function is optional. In the figure 210, example of onepossible application is shown.

en07000050.vsd

GI

U

CV GAPC64R Re<

ROV2 PTOV59N UN>

GEN PDIF87G 3Id/I

SA PTUF81 f<

SA PTOF81 f>

SDD RFUF60FL

OEX PVPH24 U/f>

UV2 PTUV27 3U<

OV2 PTOV59 3U>

CV MMXUMeter.

Option

SDE PSDE32N P0->

REG 670*1.1 – B30

Gen Diff + Back-up 24AI

ZMH PDIS21 Z<

LEX PDIS40 F <

GUP PDUP37 P<

GOP PDOP32 Pß

CCS RDIF87CT I2d/I

CV GAPC51/27 U

ROV2 PTOV59N UN>

OC4 PTOC51/67 3I>

CC RBRF50BF 3I> BF

CV GAPC46 I2>

TR PTTR49 Ith

PSP PPAM78 Ucos

SES RSYN25

CV GAPC51V I>/U

PH PIOC50 3I>>

CV GAPC50AE U/I>

CC RPLD52PD PD

OC4 PTOC51/67 3I>


+ RXTTE4

STEF PHIZ59THD U3d/N

T2W PDIF87T 3Id/I

REF PDIF87N IdN/I

Auxiliary Bus

EF4 PTOC51N/67N IN->

OC4 PTOC51/67 3I>

OC4 PTOC51/67 3I>

CC RBRF50BF 3I> BF


OC4 PTOC51/67 3I>

Main Protection

Back-up Protection

ROV2 PTOV59N UN>

T3W PDIF87T 3Id/I

CT S

Figure 210: Block protection including generator and generator transformerprotection with 24 analog input transformers and full 19” rack. Theapplication is prepared to cover hydro as well as gas turbinearrangements.



557

Note that inside the REG 670-B30 functional library additional functions areavailable, but not configured, such as additional Multipurpose protection functions,Synchrocheck function, second generator differential protection function etc., asshown in figure 210. It is as well possible to order optional 2- or 3- windingtransformer differential protection function which than can be used as transformer orblock (i.e. overall) differential protection. Note that REG 670-B30 must be re-configured if any additional or optional functions going to be used.

7.2.1.3 Description of configuration C30

Configuration 1MRK004826–CA

This configuration is used in applications where generator-transformer blockprotection within one IED is required. The REG 670-B30 is always delivered in 1/1of 19" case size. Thus 18 or 24 analogue inputs are available, depending on order typeof TRMs. This configuration includes generator low impedance, differentialprotection, transformer differential protection and overall differential protectionfuctions. Note that Pole Slip protection function is optional. See figure 211, exampleof one possible application is shown.



REG 670

en07000051.vsd

GI

U

CV GAPC64R Re<

ROV2 PTOV59N UN>

STEF PHIZ59THD U3d/N

TR PTTR49 Ith

SA PTUF81 f<

CV MMXU

Meter.


REF PDIF87N IdN/I

OV2 PTOV59 3U>

T3W PDIF87T 3Id/I

REG 670*1.1 – C30

T2W PDIF87T 3Id/I

ROV2 PTOV59N UN>

Generator and block transformer protection 24AI

CV GAPC46 I2>

OC4 PTOC51/67 3I>

TR PTTR49 Ith

CC RBRF50BF 3I> BF

CT S

SDD RFUF

60FL

SDD RFUF

60FL

ZMH PDIS21 Z<

LEX PDIS40 F <

GUP PDUP37 P<

GOP PDOP32 Pß

PSP PPAM78 Ucos

Option

SA PTOF81 f>

OEX PVPH24 U/f>

UV2 PTUV27 3U<

OV2 PTOV59 3U>

SDE PSDE32N P0->

CV GAPC51/27 U

SES RSYN25

CV GAPC51V I>/U

PH PIOC50 3I>>

CC RPLD52PD PD

OC4 PTOC51/67 3I>


CV GAPC50AE U/I>

CCS RDIF87CT I2d/I

OC4 PTOC51/67 3I>

OC4 PTOC51/67 3I>

CC RBRF50BF 3I> BF

GEN PDIF87G 3Id/I+ RXTTE4

Figure 211: Block protection including generator and generator transformerprotection with 24 analog input transformers and full 19” rack. Theapplication is prepared to cover hydro as well as gas turbinearrangements.

Note that inside the REG 670-C30 functional library additional functions areavailable, but not configured, such as additional Multipurpose protection functions,Synchrocheck function, second generator differential protection function etc., asshown in figure 211. Note that REG 670-C30 must be re-configured if any additionalor optional functions going to be used.



559

Section 8 Setting examples

About this chapterIn this section different setting examples are described

8.1 Setting examples

The correct setting of the IED is of vital importance for the correct operation of theprotection function. The examples have been selected from an example power systemas per figure 212.

Note that all setting are based on primary values, either in per unit (percent) of primarybase values or as primary values direct, e.g. primary ohms. The setting examples aretypical and selected to show alternatives with communication schemes, single- andthree phase tripping and auto-reclosing, multi- and single breaker arrangements.

The settings of IED670 are shown in examples from a traditional power system. Thefollowing system structure has been defined for the examples.

Section 8Setting examples


561

G

G

G

Station A

Station B

Station C

Station D

Station A

Station CStation E

Station F

Station G

Station H

100 km

5km

102 km

300 km

150 km

100 km

70 km

30 km

12 km

35 km

25 km

80 km

15000MVAZ1=0,9+j10.6Z0=1.0+j12.0

400 kV Cable data0,028 +j 0,155 ohm/km

0,030 + j0,120 ohm/km

400 kV OHL data0,014 +j 0,3 ohm/km0,16 + j0,9 ohm/km0,09+ + j0,5 ohm/km

230 kV OHL data0,018 +j 0,34 ohm/km0,52 + j1,1 ohm/km

0,32+ + j0,62 ohm/km

132 kV OHL data0,024 +j 0,38 ohm/km

0,92 + j1,2 ohm/km

GeneratorSn=600MVA, 18kV

Xd"=0,18Xd'=0,22Xd=2.0

Transformer

Sn=600MVA, 410/18kVek=14%

Z0=40ohm (400 base)

Series Capacitor (mid line)-j 45 ohm-j 45 ohm

GeneratorsSn=800MVA, 18kV

Xd"=0,18Xd'=0,22Xd=2.0

Sn=1000MVA, 410/18kVek=12%

Z0=30ohm (400 base)

AutotransformerSn=1000MVA415/230+/-9*1,67%kVek=14%

Z0=42,5ohm (415 base) ABC-NZ0=20ohm (415 base) ABC-abc

Z0=5ohm (230 base) abc-N

TransformersSn=500MVA

415/230+/-9*1,67%kVek=12%

Z0=60ohm (415 base)

TransformerSn=175MVA

242/132+/-9*1,67%kVek=10%

Z0=20ohm (230 base)

TransformerSn=175MVA

132/11+/-92*2,5%kVek=12%

Z0=10ohm (132 base)

GeneratorSn=160MVA, 11kV

Xd"=0,18Xd'=0,24Xd=2.2

60 km

CTs 2000/1ACVT 400/0,11kV

CTs 2000/1ACVT 400/0,11kV

CTs 2000/1ACVT 400/0,11kV

CTs 1000/1A

CTs 2000/1ACTs 1200/1A

CVT 230/0,11kV

CTs 2000/1ACVT 400/0,11kV

CTs 1200/1ACVT 230/0,11kV

CTs 1200/1ACVT 230/0,11kV

CTs 600/1A

CTs 1600/1A

VT 132/0,11kV

CTs 600/1AVT 132/0,11kV

CTs 600/1AVT 132/0,11kV

CTs 2000/1

CTs 2500/1

CTs 1200/1ACVT 230/0,11kV

G G

400 kV OHL data0,014 +j 0,3 ohm/km0,16 + j0,9 ohm/km0,09+ + j0,5 ohm/km

cos f =0,85

cos f =0,85

Transformers

400 kV

230 kV

132 kV

cos f =0,85

Load

CTs 600/1A

en05000836.vsd

Figure 212: The typical power network with different objects are examples of howto set the IED670.

The setting has been performed for the 400 kV overhead power line between stationA and C (REL 670), for the short 400 kV Cable feeder between station A and B (RED670), for the Long 230 kV single power line between station A and E (REL 670), forthe series compensated line between station C and D (REL 670) and for the short 132kV power line between station F and G (REL 670).

Setting of Transformers in Station C (400/230 kV) and station F 132/20 kV are alsocalculated.



REG 670

The complete setting examples for all IEDs as per above are available in separatedocuments, refer to section "Related documents".

REL 670 Example 7 70 kV power line on a resonance earth system. Double bus,single breaker arrangement.

8.1.1 REG 670 Example 1REG 670 Example 1 describes setting principle for a typical generator-transformerblock.



563

Section 9 Glossary

About this chapterThis chapter contains a glossary with terms, acronyms and abbreviations used in ABBtechnical documentation.

9.1 Glossary

AC Alternating current

A/D converter Analog to digital converter

ADBS Amplitude dead -band supervision

ADM Analog digital conversion module, with time synchronization

ANSI American National Standards Institute

AR Autoreclosing

ArgNegRes Setting parameter/ZD/

ArgDir Setting parameter/ZD/

ASCT Auxiliary summation current transformer

ASD Adaptive signal detection

AWG American Wire Gauge standard

BBP Busbar protection

BFP Breaker failure protection

BIM Binary input module

BOM Binary output module

BR External bi-stable relay

BS British standard

BSR Binary signal transfer function, receiver blocks

BST Binary signal transfer function, transmit blocks

C37.94 IEEE/ANSI protocol used when sending binary signalsbetween IEDs

CAN Controller Area Network. ISO standard (ISO 11898) for serialcommunication

CAP 531 Configuration and programming tool

Section 9Glossary


565

CB Circuit breaker

CBM Combined backplane module

CCITT Consultative Committee for International Telegraph andTelephony. A United Nations sponsored standards bodywithin the International Telecommunications Union.

CCM CAN carrier module

CCVT Capacitive Coupled Voltage Transformer

Class C Protection Current Transformer class as per IEEE/ ANSI

CMPPS Combined mega pulses per second

CO cycle Close-open cycle

Co-directional Way of transmitting G.703 over a balanced line. Involves twotwisted pairs making it possible to transmit information in bothdirections

COMTRADE Standard format according to IEC 60255-24

Contra-directional Way of transmitting G.703 over a balanced line. Involves fourtwisted pairs of with two are used for transmitting data in bothdirections, and two pairs for transmitting clock signals

CPU Central processor unit

CR Carrier receive

CRC Cyclic redundancy check

CS Carrier send

CT Current transformer

CVT Capacitive voltage transformer

DAR Delayed auto-reclosing

DARPA Defense Advanced Research Projects Agency (The USdeveloper of the TCP/IP protocol etc.)

DBDL Dead bus dead line

DBLL Dead bus live line

DC Direct current

DFT Discrete Fourier transform

DIP-switch Small switch mounted on a printed circuit board

DLLB Dead line live bus

DNP Distributed Network Protocol as per IEEE/ANSI Std.1379-2000

DR Disturbance recorder

DRAM Dynamic random access memory

DRH Disturbance report handler

Section 9Glossary


REG 670

DSP Digital signal processor

DTT Direct transfer trip scheme

EHV network Extra high voltage network

EIA Electronic Industries Association

EMC Electro magnetic compatibility

EMF Electro motive force

EMI Electro magnetic interference

EnFP End fault protection

ESD Electrostatic discharge

FOX 20 Modular 20 channel telecommunication system for speech,data and protection signals

FOX 512/515 Access multiplexer

FOX 6Plus Compact, time-division multiplexer for the transmission of upto seven duplex channels of digital data over optical fibers

G.703 Electrical and functional description for digital lines used bylocal telephone companies. Can be transported over balancedand unbalanced lines

GCM Communication interface module with carrier of GPS receivermodule

GI General interrogation command

GIS Gas insulated switchgear

GOOSE Generic object oriented substation event

GPS Global positioning system

GSM GPS time synchronization module

HDLC protocol High level data link control, protocol based on the HDLCstandard

HFBR connectortype

Plastic fiber connector

HMI Human machine interface

HSAR High speed auto reclosing

HV High voltage

HVDC High voltage direct current

IDBS Integrating dead band supervision

IEC International Electrical Committee

IEC 60044-6 IEC Standard, Instrument transformers – Part 6: Requirementsfor protective current transformers for transient performance

Section 9Glossary


567

IEC 60870-5-103 Communication standard for protective equipment. A serialmaster/slave protocol for point-to-point communication

IEC 61850 Substation Automation communication standard

IEEE Institute of Electrical and Electronics Engineers

IEEE 802.12 A network technology standard that provides 100 Mbits/s ontwisted-pair or optical fiber cable

IEEE P1386.1 PCI Mezzanine card (PMC) standard for local bus modules.References the CMC (IEEE P1386, also known as Commonmezzanine card) standard for the mechanics and the PCIspecifications from the PCI SIG (Special Interest Group) forthe electrical EMF Electro Motive Force.

IED Intelligent electronic device

I-GIS Intelligent gas insulated switchgear

IOM Binary input/output module

Instance When several occurrences of the same function are availablein the IED they are referred to as instances of that function.One instance of a function is identical to another of the samekind but will have a different number in the IED userinterfaces. The word instance is sometimes defined as an itemof information that is representative of a type. In the same wayan instance of a function in the IED is representative of a typeof function.

IP 1. Internet protocol. The network layer for the TCP/IP protocolsuite widely used on Ethernet networks. IP is a connectionless,best-effort packet switching protocol. It provides packetrouting, fragmentation and re-assembly through the data linklayer.2. Ingression protection according to IEC standard

IP 20 Ingression protection, according to IEC standard, level 20



IRF Internal fail signal

IRIG-B: InterRange Instrumentation Group Time code format B,standard 200

ITU International Telecommunications Union

LAN Local area network

LIB 520 High voltage software module

LCD Liquid crystal display

LDCM Line differential communication module

LDD Local detection device

Section 9Glossary


REG 670

LED Light emitting diode

LNT LON network tool

LON Local operating network

MCB Miniature circuit breaker

MCM Mezzanine carrier module

MIM Milli-ampere module

MPM Main processing module

MVB Multifunction vehicle bus. Standardized serial bus originallydeveloped for use in trains.

NCC National Control Centre

NUM Numerical module

OCO cycle Open-close-open cycle

OCP Overcurrent protection

OEM Optical ethernet module

OLTC On load tap changer

OV Over voltage

Overreach A term used to describe how the relay behaves during a faultcondition. For example a distance relay is over-reaching whenthe impedance presented to it is smaller than the apparentimpedance to the fault applied to the balance point, i.e. the setreach. The relay “sees” the fault but perhaps it should not haveseen it.

PCI Peripheral component interconnect, a local data bus

PCM Pulse code modulation

PCM 600 Protection and control IED manager

PC-MIP Mezzanine card standard

PISA Process interface for sensors & actuators

PMC PCI Mezzanine card

POTT Permissive overreach transfer trip

Process bus Bus or LAN used at the process level, that is, in near proximityto the measured and/or controlled components

PSM Power supply module

PST Parameter setting tool

PT ratio Potential transformer or voltage transformer ratio

PUTT Permissive underreach transfer trip

RASC Synchrocheck relay, COMBIFLEX

Section 9Glossary


569

RCA Relay characteristic angle

REVAL Evaluation software

RFPP Resistance for phase-to-phase faults

RFPE Resistance for phase-to-earth faults

RISC Reduced instruction set computer

RMS value Root mean square value

RS422 A balanced serial interface for the transmission of digital datain point-to-point connections

RS485 Serial link according to EIA standard RS485

RTC Real time clock

RTU Remote terminal unit

SA Substation Automation

SC Switch or push-button to close

SCS Station control system

SCT System configuration tool according to standard IEC 61850

SLM Serial communication module. Used for SPA/LON/IECcommunication.

SMA connector Subminiature version A, A threaded connector with constantimpedance.

SMS Station monitoring system

SNTP Simple network time protocol – is used to synchronizecomputer clocks on local area networks. This reduces therequirement to have accurate hardware clocks in everyembedded system in a network. Each embedded node caninstead synchronize with a remote clock, providing therequired accuracy.

SPA Strömberg protection acquisition, a serial master/slaveprotocol for point-to-point communication

SRY Switch for CB ready condition

ST Switch or push-button to trip

Starpoint Neutral point of transformer or generator

SVC Static VAr compensation

TC Trip coil

TCS Trip circuit supervision

TCP Transmission control protocol. The most common transportlayer protocol used on Ethernet and the Internet.

TCP/IP Transmission control protocol over Internet Protocol. The defacto standard Ethernet protocols incorporated into 4.2BSD

Section 9Glossary


REG 670

Unix. TCP/IP was developed by DARPA for internet workingand encompasses both network layer and transport layerprotocols. While TCP and IP specify two protocols at specificprotocol layers, TCP/IP is often used to refer to the entire USDepartment of Defense protocol suite based upon these,including Telnet, FTP, UDP and RDP.

TEF Time delayed earth-fault protection function

TNC connector Threaded Neill Concelman, A threaded constant impedanceversion of a BNC connector

TPZ, TPY, TPX,TPS

Current transformer class according to IEC

Underreach A term used to describe how the relay behaves during a faultcondition. For example a distance relay is under-reachingwhen the impedance presented to it is greater than the apparentimpedance to the fault applied to the balance point, i.e. the setreach. The relay does not “see” the fault but perhaps it shouldhave seen it. See also Overreach.

U/I-PISA Process interface components that deliver measured voltageand current values

UTC Coordinated universal time. A coordinated time scale,maintained by the Bureau International des Poids et Mesures(BIPM), which forms the basis of a coordinated disseminationof standard frequencies and time signals. UTC is derived fromInternational Atomic Time (TAI) by the addition of a wholenumber of "leap seconds" to synchronize it with UniversalTime 1 (UT1), thus allowing for the eccentricity of the Earth"sorbit, the rotational axis tilt (23.5 degrees), but still showingthe Earth"s irregular rotation, on which UT1 is based. TheCoordinated Universal Time is expressed using a 24-hourclock and uses the Gregorian calendar. It is used for aeroplaneand ship navigation, where it also sometimes known by themilitary name, "Zulu time". "Zulu" in the phonetic alphabetstands for "Z" which stands for longitude zero.

UV Undervoltage

WEI Weak end infeed logic

VT Voltage transformer

X.21 A digital signalling interface primarily used for telecomequipment

3IO Three times zero-sequence current. Often referred to as theresidual or the earth-fault current

3UO Three times the zero sequence voltage. Often referred to as theresidual voltage or the neutral point voltage

Section 9Glossary


571

1mrk502016-uen b en application manual generator protection ied reg 670 1.1a

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